[Title 40 CFR ]
[Code of Federal Regulations (annual edition) - July 1, 2008 Edition]
[From the U.S. Government Printing Office]



[[Page i]]

          

          40


          Parts 72 to 80

          Revised as of July 1, 2008


          Protection of Environment
          



________________________

          Containing a codification of documents of general 
          applicability and future effect

          As of July 1, 2008
          With Ancillaries
                    Published by
                    Office of the Federal Register
                    National Archives and Records
                    Administration
                    A Special Edition of the Federal Register

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                            Table of Contents



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

  Title 40:
          Chapter I--Environmental Protection Agency                 3
  Finding Aids:
      Material Approved for Incorporation by Reference........    1099
      Table of CFR Titles and Chapters........................    1109
      Alphabetical List of Agencies Appearing in the CFR......    1129
      List of CFR Sections Affected...........................    1139

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

                     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, 2008), 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 
the daily Federal Register. These two lists will identify the Federal 
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 
number of the Federal Register and date of publication. Publication 
dates and effective dates are usually not the same and care must be 
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instances where the effective date is beyond the cut-off date for the 
Code a note has been inserted to reflect the future effective date. In 
those instances where a regulation published in the Federal Register 
states a date certain for expiration, an appropriate note will be 
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.

OBSOLETE PROVISIONS

    Provisions that become obsolete before the revision date stated on 
the cover of each volume are not carried. Code users may find the text 
of provisions in effect on a given date in the past by using the 
appropriate numerical list of sections affected. For the period before 
January 1, 1986, consult either the List of CFR Sections Affected, 1949-
1963, 1964-1972, or 1973-1985, published in seven separate volumes. For 
the period beginning January 1, 1986, a ``List of CFR Sections 
Affected'' is published at the end of each CFR volume.

INCORPORATION BY REFERENCE

    What is incorporation by reference? Incorporation by reference was 
established by statute and allows Federal agencies to meet the 
requirement to publish regulations in the Federal Register by referring 
to materials already published elsewhere. For an incorporation to be 
valid, the Director of the Federal Register must approve it. The legal 
effect of incorporation by reference is that the material is treated as 
if it were published in full in the Federal Register (5 U.S.C. 552(a)). 
This material, like any other properly issued regulation, has the force 
of law.
    What is a proper incorporation by reference? The Director of the 
Federal Register will approve an incorporation by reference only when 
the requirements of 1 CFR part 51 are met. Some of the elements on which 
approval is based are:
    (a) The incorporation will substantially reduce the volume of 
material published in the Federal Register.
    (b) The matter incorporated is in fact available to the extent 
necessary to afford fairness and uniformity in the administrative 
process.
    (c) The incorporating document is drafted and submitted for 
publication in accordance with 1 CFR part 51.
    Properly approved incorporations by reference in this volume are 
listed in the Finding Aids at the end of this volume.
    What if the material incorporated by reference cannot be found? If 
you have any problem locating or obtaining a copy of material listed in 
the Finding Aids of this volume as an approved incorporation by 
reference, please contact the agency that issued the regulation 
containing that incorporation. If, after contacting the agency, you find 
the material is not available, please notify the Director of the Federal 
Register, National Archives and Records Administration, Washington DC 
20408, or call 202-741-6010.

CFR INDEXES AND TABULAR GUIDES

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separate volume, revised annually as of January 1, entitled CFR Index 
and Finding Aids. This volume contains the Parallel Table of Statutory 
Authorities and Agency Rules (Table I). A list of CFR titles, chapters, 
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also included in this volume.
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that volume.
    The Federal Register Index is issued monthly in cumulative form. 
This index is based on a consolidation of the ``Contents'' entries in 
the daily Federal Register.
    A List of CFR Sections Affected (LSA) is published monthly, keyed to 
the revision dates of the 50 CFR titles.

[[Page vii]]


REPUBLICATION OF MATERIAL

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in the Code of Federal Regulations.

INQUIRIES

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    Raymond A. Mosley,
    Director,
    Office of the Federal Register.
    July 1, 2008.







[[Page ix]]



                               THIS TITLE

    Title 40--Protection of Environment is composed of thirty-one 
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-End), 
parts 53-59, part 60 (60.1-End), 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) parts 64-71, parts 72-80, parts 81-84, part 85-Sec.  86.599-99, 
part 86 (86.600-1-End), parts 87-99, 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 700-789, and part 790 to End. The 
contents of these volumes represent all current regulations codified 
under this title of the CFR as of July 1, 2008.

    Chapter I--Environmental Protection Agency appears in all thirty-one 
volumes. Regulations issued by the Council on Environmental Quality, 
including an Index to Parts 1500 through 1508, appear in the volume 
containing part 790 to End. The OMB control numbers for title 40 appear 
in Sec.  9.1 of this chapter.

    For this volume, Susannah C. Hurley and Moja N. Mwaniki were Chief 
Editors. The Code of Federal Regulations publication program is under 
the direction of Michael L. White, assisted by Ann Worley.


[[Page 1]]



                   TITLE 40--PROTECTION OF ENVIRONMENT




                    (This book contains parts 72-80)

  --------------------------------------------------------------------
                                                                    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              Sulphur dioxide allowance system............          91
74              Sulfur dioxide opt-ins......................         177
75              Continuous emission monitoring..............         204
76              Acid rain nitrogen oxides emission reduction 
                    program.................................         488
77              Excess emissions............................         512
78              Appeal procedures...........................         519
79              Registration of fuels and fuel additives....         532
80              Regulation of fuels and fuel additives......         627

[[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. 7601 and 7651 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 conducts Air Emissions Testing as described in ASTM D7036-04 
(incorporated by reference under Sec. 75.6 of this part).
    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 
by which the Administrator allocates,

[[Page 8]]

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, Hg, 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, Sec. 75.71(a) and 75.81 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)
    (7) A Hg concentration monitoring system, consisting of a Hg 
pollutant concentration monitor and an automated DAHS. A Hg 
concentration monitoring system provides a permanent, continuous record 
of Hg emissions in units of micrograms per standard cubic meter 
([micro]gm/scm).
    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.
    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 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

[[Page 13]]

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 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

[[Page 14]]

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, EPA-600/R-97/121 or such revised procedure as approved by the 
Administrator. On and after January 1, 2009, vendors advertising 
certification with the EPA Traceability Protocol or distributing gases 
as ``EPA Protocol Gas'' must participate in the EPA Protocol Gas 
Verification Program. Non-participating vendors may not use ``EPA'' in 
any form of advertising for these products, unless approved by the 
Administrator.
    EPA Protocol Gas Verification Program means the EPA Protocol Gas 
audit program described in Section 2.1.10 of the ``EPA Traceability 
Protocol for Assay and Certification of Gaseous Calibration Standards,'' 
September 1997, EPA-600/R-97/121 (EPA Protocol Procedure) or such 
revised procedure as approved by the Administrator.
    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 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.

[[Page 15]]

    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.''
    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 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

[[Page 16]]

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-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

[[Page 17]]

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.
    Interested person means any person who submitted written comments or 
testified at a public hearing on the draft permit or other matter 
subject to notice and comment under the Acid Rain Program or any person 
who submitted his or her name to the Administrator or the permitting 
authority, as appropriate, to be placed on a list of persons interested 
in such matter. The Administrator or the permitting authority 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 of any person failing to 
respond as requested.
    Investor-owned utility means a utility that is organized as a tax-
paying for-profit business.
    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

[[Page 18]]

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 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

[[Page 19]]

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 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.

[[Page 20]]

    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 elemental Hg standards means either:
    (1) Compressed gas cylinders having known concentrations of 
elemental Hg, which have been prepared according to the ``EPA 
Traceability Protocol for Assay and Certification of Gaseous Calibration 
Standards''; or
    (2) Calibration gases having known concentrations of elemental Hg, 
produced by a generator that fully meets the performance requirements of 
the ``EPA Traceability Protocol for Qualification and Certification of 
Elemental Mercury Gas Generators''.
    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.
    NIST traceable source of oxidized Hg means a generator that: Is 
capable of providing known concentrations of vapor phase mercuric 
chloride (HgCl2), and that fully meets the performance 
requirements of the ``EPA Traceability Protocol for Qualification and 
Certification of Oxidized Mercury Gas Generators''.
    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:

[[Page 21]]

    (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.
    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

[[Page 22]]

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 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

[[Page 23]]

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
    (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 means an individual who meets the requirements 
as described in ASTM D7036-04, ``Standard Practice for Competence of Air 
Emission Testing Bodies'' (incorporated by reference under Sec. 75.6 of 
this part).
    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

[[Page 24]]

    (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 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.

[[Page 25]]

    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.
    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.
    Sorbent trap monitoring system means the equipment required by part 
75 of this chapter for the continuous monitoring of Hg emissions, using 
paired sorbent traps containing iodated charcoal (IC) or other suitable 
reagents. This excepted monitoring system consists of a probe, the 
paired sorbent traps, an umbilical line, moisture removal components, an 
air tight sample pump, a gas flow meter, and an automated data 
acquisition and handling system. The monitoring system samples the stack 
gas at a rate proportional to the stack gas volumetric flowrate. The 
sampling is a batch process. Using the sample volume measured by the gas 
flow meter and the results of the analyses of the sorbent traps, the 
average mercury concentration in the stack gas for the sampling period 
is determined, in units of micrograms per dry standard cubic meter 
([micro]g/dscm). Mercury mass emissions for each hour in the sampling 
period are calculated using the average Hg concentration for that 
period, in conjunction with contemporaneous hourly measurements of the 
stack gas flow rate, corrected for the stack moisture content.
    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 producer means an organization that prepares and 
analyzes compressed gas mixtures for use as calibration gases and that 
offers the mixtures for sale to end users or to

[[Page 26]]

third-party vendors for resale to end users.
    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 [deg]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, 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

[[Page 27]]

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.
    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

[[Page 28]]

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;
    (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 on GPO Access.



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.
 [deg]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.
[deg]F--degree Fahrenheit.
fps--feet per second.
gal--gallon.
hr--hour.
in--inch.
[deg]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.
[deg]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.

[[Page 29]]

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 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:

[[Page 30]]

    (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 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

[[Page 31]]

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]



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,

[[Page 32]]

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 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;

[[Page 33]]

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), 
(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

[[Page 34]]

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 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

[[Page 35]]

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 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

[[Page 36]]

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);
    (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.

[[Page 37]]

    (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, 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

[[Page 38]]

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.



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 addresses: American Society for Testing and Material (ASTM), 
1916 Race Street, Philadelphia, Pennsylvania 19103; and the University 
Microfilms International 300 North Zeeb Road, Ann Arbor, Michigan 48106.
    (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.
    (b) [Reserved]

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



                   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

[[Page 39]]

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]



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

[[Page 40]]

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.
    (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

[[Page 41]]

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.
    (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

[[Page 42]]

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.
    (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

[[Page 43]]

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 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

[[Page 44]]

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 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

[[Page 45]]

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.
    (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

[[Page 46]]

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.
    (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

[[Page 47]]

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 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

[[Page 48]]

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 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, 72.42, 72.43, or 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

[[Page 49]]

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 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

[[Page 50]]

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:
    (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

[[Page 51]]

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 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,

[[Page 52]]

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 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.

[[Page 53]]

    (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 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

[[Page 54]]

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 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.

[[Page 55]]

    (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 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:

[[Page 56]]

    (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.
    (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.

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

[[Page 57]]

    (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:
    (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

[[Page 58]]

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 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.

[[Page 59]]

    (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.
---------------------------------------------------------------------------

    (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:

[[Page 60]]

    (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 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

[[Page 61]]

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:
    (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-

[[Page 62]]

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.
    (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.

[[Page 63]]

    (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:
    (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;

[[Page 64]]

    (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
    (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

[[Page 65]]

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 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

[[Page 66]]

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 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]

[[Page 67]]



                   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 
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

[[Page 68]]

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.
    (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.

[[Page 69]]

    (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
    (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

[[Page 70]]

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.
    (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 pubic 
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.

[[Page 71]]

    (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, 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.

[[Page 72]]

    (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 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

[[Page 73]]

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 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

[[Page 74]]

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 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

[[Page 75]]

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 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

[[Page 76]]

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 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

[[Page 77]]

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 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

[[Page 78]]

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 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

[[Page 79]]

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.
    (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:

[[Page 80]]

    (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 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

[[Page 81]]

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 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

[[Page 82]]

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 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

[[Page 83]]

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 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

[[Page 84]]

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).
    (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

[[Page 85]]

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 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 ``

[[Page 86]]

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.
    (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

[[Page 87]]

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 (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

[[Page 88]]

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 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;

[[Page 89]]

    (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.
    (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]

[[Page 90]]



 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.

   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.


[[Page 91]]


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

    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: 113.3x10\6\ Btu/hrx1 kw-hr / 3413 Btux1 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.

[[Page 92]]

                      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--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.

    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

[[Page 93]]

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
                                                                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

[[Page 94]]

 
                                                                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
                                                                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

[[Page 95]]

 
                                                                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
                                                                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

[[Page 96]]

 
                                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
                                                                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.

[[Page 97]]

    (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.
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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:

[[Page 153]]

[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) and (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.
    (ii) Notwithstanding paragraph (b)(3)(i) of this section, if the 
amount calculated results in less than 10 tons of excess emissions, the 
maximum deduction from other units shall be adjusted so that 10 tons of 
excess emissions, or the tons of excess emissions that would result if 
no allowances could be deducted from other units, whichever is less, 
remain for the unit.
    (iii) If the authorized account representative submits within 15 
days of receipt of a notification under paragraph (b)(3)(i) of this 
section a written request specifying allowances to deduct in accordance 
with paragraphs

[[Page 160]]

(b)(3)(i) and (ii) of this section, the Administrator will deduct such 
allowances, and reduce the tons of excess emissions otherwise at the 
unit by an equal amount, up to the amount calculated under paragraphs 
(b)(3)(i) and (ii) of this section.
    (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 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]

[[Page 161]]



                      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;
    (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

[[Page 162]]

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 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

[[Page 163]]

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 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

[[Page 164]]

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.
    (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]

[[Page 165]]



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 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

[[Page 166]]

    (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 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;

[[Page 167]]

    (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, 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;

[[Page 168]]

    (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 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

[[Page 169]]

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:
[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

[[Page 170]]

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]



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

[[Page 171]]

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) 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

[[Page 172]]

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 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

[[Page 173]]

     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
     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

[[Page 174]]

     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
     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

[[Page 175]]

                            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
     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

[[Page 176]]

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.

                        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

[[Page 177]]

(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:
[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]

[[Page 178]]

  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.

           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

[[Page 179]]

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]



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

[[Page 180]]

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 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

[[Page 181]]

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 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;

[[Page 182]]

    (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 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

[[Page 183]]

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 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.

[[Page 184]]



         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 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
    

[[Page 185]]



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:
[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.


[[Page 186]]


    (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,
    [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.

[[Page 187]]



                       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
tons SO2/hour.............................................    2x8760/(annual fuel consumption for specified year
                                                                                 \1\x10\3\)
lbs SO2/hour..............................................     8760/(annual fuel consumption for specified year
                                                                                 \1\x10\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

[[Page 188]]

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.



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 emissions limitations, the 
designated

[[Page 191]]

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
    
    (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.

[[Page 195]]

    (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 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

[[Page 196]]

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 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

[[Page 197]]

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 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 =

[[Page 198]]

[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 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

[[Page 199]]

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;
    (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;

[[Page 200]]

    (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 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

[[Page 201]]

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:
[GRAPHIC] [TIFF OMITTED] TR04AP95.024


[[Page 202]]


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 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).

[[Page 203]]

    (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 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.
    (b) Method of deduction. The Administrator will deduct allowances 
beginning with those allowances with the latest recorded date of 
transfer out of the 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

[[Page 204]]

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 Special provisions for measuring Hg mass emissions using the 
          excepted sorbent trap monitoring methodology.
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.

            Subpart C_Operation and Maintenance Requirements

75.20 Initial certification and recertification procedures.
75.21 Quality assurance and quality control requirements.

[[Page 205]]

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, Hg, 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 Standard missing data procedures for Hg CEMS.
75.39 Missing data procedures for sorbent trap monitoring systems.

                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.

                  Subpart I_Hg Mass Emission Provisions

75.80 General provisions.
75.81 Monitoring of Hg mass emissions and heat input at the unit level.
75.82 Monitoring of Hg mass emissions and heat input at common and 
          multiple stacks.
75.83 Calculation of Hg mass emissions and heat input rate.
75.84 Recordkeeping and reporting.

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]
Appendix K to Part 75--Quality Assurance and Operating Procedures for 
          Sorbent Trap Monitoring Systems

    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)

[[Page 206]]

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 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.
    (d) The provisions of this part apply to sources subject to a State 
or Federal mercury (Hg) mass emission reduction program, to the extent 
that 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]



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);

[[Page 207]]

    (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 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

[[Page 208]]

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) The earlier of 90 unit operating days or 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 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) The earlier of 90 unit operating days or 180 calendar days after 
the date the unit first operates after becoming 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, 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, the owner or 
operator shall ensure that all of the continuous monitoring systems for 
SO2, NOX, CO2, Hg, 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, Hg 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, the maximum potential Hg concentration, as 
defined in section 2.1.7.1 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 
existing unit completes construction of a new stack, flue, flue gas 
desulfurization system or add-on NOX emission controls after 
the applicable deadline in paragraph (a) of this section, then the owner 
or operator shall ensure that all monitoring systems required under this 
part for monitoring SO2, NOX, CO2, 
opacity, and volumetric flow are installed on the new stack or duct and 
all certification

[[Page 209]]

tests are completed not later than 90 unit operating days or 180 
calendar days (whichever occurs first) after the date that emissions 
first exit to the atmosphere through the new stack, flue, flue gas 
desulfurization system or add-on NOX emission controls, 
notice of which date shall be provided under subpart G of this part. 
Until emissions first pass through the new stack, flue, flue gas 
desulfurization system or add-on NOX emission controls, the 
unit is subject to the appropriate deadline in paragraph (a) of this 
section. The owner or operator shall determine and report SO2 
concentration, NOX emission rate, CO2 
concentration, and flow data for all unit operating hours after 
emissions first pass through the new stack, flue, flue gas 
desulfurization system or add-on NOX emission controls until 
all required certification tests are successfully completed using 
either:
    (1) The appropriate value for substitution of missing data upon 
recertification pursuant to Sec. 75.20(b)(3); 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.
    (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 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

[[Page 210]]

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]



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.
    (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

[[Page 211]]

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 addresses: American Society for Testing and Material (ASTM), 
100 Barr harbor Drive, P.O. Box C-700, West Conshohocken, Pennsylvania 
19428-2959; and the University Microfilms International 300 North Zeeb 
Road, Ann Arbor, Michigan 48106.
    (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.
    (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.

[[Page 212]]

    (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 
Sulfur in Gaseous Fuels by Hydrogenolysis and Rateometric Colorimetry, 
for appendix D of this part.
    (38) ASTM D4840-99 (Reapproved 2004), ``Standard Guide for Sample 
Chain-of-Custody Procedures,'' for appendix K of this part, section 
7.2.9.
    (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.

[[Page 213]]

    (43) ASTM D6784-02, ``Standard Test Method for Elemental, Oxidized, 
Particle-Bound and Total Mercury in Flue Gas Generated from Coal-Fired 
Stationary Sources (Ontario Hydro Method),'' for Sec. 75.22(a)(7) and 
(b)(5).
    (44) ASTM D6911-03, ``Guide for Packaging and Shipping Environmental 
Samples for Laboratory Analysis,'' for appendix K of this part, section 
7.2.8.
    (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 appendices A, B, and E of 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.
    (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.
    (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.

[[Page 214]]

    (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, 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.

[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]

    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 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

[[Page 215]]

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 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, NOX emission rate, and Hg concentration 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

[[Page 216]]

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, 
Hg 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 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

[[Page 217]]

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]



Sec. 75.11  Specific provisions for monitoring SO2 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. 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

[[Page 218]]

    (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 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

[[Page 219]]

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.

[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 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

[[Page 220]]

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 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

[[Page 221]]

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 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  Special provisions for measuring Hg mass emissions using
the excepted sorbent trap monitoring methodology.

    For an affected coal-fired unit under a State or Federal Hg mass 
emission reduction program that adopts the provisions of subpart I of 
this part, if the owner or operator elects to use sorbent trap 
monitoring systems (as defined in Sec. 72.2 of this chapter) to 
quantify Hg mass emissions, the guidelines in paragraphs (a) through (l) 
of this section

[[Page 222]]

shall be followed for this excepted monitoring methodology:
    (a) For each sorbent trap monitoring system (whether primary or 
redundant backup), the use of paired sorbent traps, as described in 
appendix K to this part, is required;
    (b) Each sorbent trap shall have both a main section, a backup 
section, and a third section to allow spiking with a calibration gas of 
known Hg concentration, as described in appendix K to this part;
    (c) A certified flow monitoring system is required;
    (d) Correction for stack gas moisture content is required, and in 
some cases, a certified O2 or CO2 monitoring 
system is required (see Sec. 75.81(a)(4));
    (e) Each sorbent trap monitoring system shall be installed and 
operated in accordance with appendix K to this part. The automated data 
acquisition and handling system shall ensure that the sampling rate is 
proportional to the stack gas volumetric flow rate.
    (f) At the beginning and end of each sample collection period, and 
at least once in each unit operating hour during the collection period, 
the gas flow meter reading shall be recorded.
    (g) After each sample collection period, the mass of Hg adsorbed in 
each sorbent trap (in all three sections) shall be determined according 
to the applicable procedures in appendix K to this part.
    (h) The hourly Hg mass emissions for each collection period are 
determined using the results of the analyses in conjunction with 
contemporaneous hourly data recorded by a certified stack flow monitor, 
corrected for the stack gas moisture content. For each pair of sorbent 
traps analyzed, the average of the two Hg concentrations shall be used 
for reporting purposes under ( 75.84(f). Notwithstanding this 
requirement, if, due to circumstances beyond the control of the owner or 
operator, one of the paired traps is accidentally lost, damaged, or 
broken and cannot be analyzed, the results of the analysis of the other 
trap may be used for reporting purposes, provided that:
    (1) The other trap has met all of the applicable quality-assurance 
requirements of this part; and
    (2) The Hg concentration measured by the other trap is multiplied by 
a factor of 1.111.
    (i) All unit operating hours for which valid Hg concentration data 
are obtained with the primary sorbent trap monitoring system (as 
verified using the quality assurance procedures in appendix K to this 
part) shall be reported in the electronic quarterly report under Sec. 
75.84(f). For hours in which data from the primary monitoring system are 
invalid, the owner or operator may, in accordance with Sec. 75.20(d), 
report valid Hg concentration data from: A certified redundant backup 
CEMS or sorbent trap monitoring system; a certified non-redundant backup 
CEMS or sorbent trap monitoring system; or an applicable reference 
method under Sec. 75.22. If no quality-assured Hg concentration are 
available for a particular hour, the owner or operator shall report the 
appropriate substitute data value in accordance with Sec. 75.39.
    (j) Initial certification requirements and additional quality-
assurance requirements for the sorbent trap monitoring systems are found 
in Sec. 75.20(c)(9), in section 6.5.7 of appendix A to this part, in 
sections 1.5 and 2.3 of appendix B to this part, and in appendix K to 
this part.
    (k) During each RATA of a sorbent trap monitoring system, the type 
of sorbent material used by the traps shall be the same as for daily 
operation of the monitoring system. A new pair of traps shall be used 
for each RATA run. However, the size of the traps used for the RATA may 
be smaller than the traps used for daily operation of the system.
    (l) Whenever the type of sorbent material used by the traps is 
changed, the owner or operator shall conduct a diagnostic RATA of the 
modified sorbent trap monitoring system within 720 unit or stack 
operating hours after the date and hour when the new sorbent material is 
first used. If the diagnostic RATA is passed, data from the modified 
system may be reported as quality-assured, back to the date and hour 
when the new sorbent material was first used. If the RATA is failed, all 
data from the modified system shall be invalidated, back to the date and 
hour when the new sorbent material was

[[Page 223]]

first used, and data from the system shall remain invalid until a 
subsequent RATA is passed. If the required RATA is not completed within 
720 unit or stack operating hours, but is passed on the first attempt, 
data from the modified system shall be invalidated beginning with the 
first operating hour after the 720 unit or stack operating hour window 
expires and data from the system shall remain invalid until the date and 
hour of completion of the successful RATA.

[70 FR 28678, May 18, 2005, as amended at 72 FR 51527, Sept. 7, 2007; 73 
FR 4343, Jan. 24, 2008]



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.
    (A) Combine emissions for the affected units for recordkeeping and 
compliance purposes; or
    (B) Provide information satisfactory to the Administrator on methods 
for apportioning SO2 mass emissions measured in the common 
stack to each of the Phase I and Phase II affected units. The designated 
representative shall provide the information to the Administrator 
through a petition submitted under Sec. 75.66. The Administrator may 
approve such substitute methods for apportioning SO2 mass 
emissions measured in a common stack whenever the method ensures 
complete and accurate accounting of all emissions regulated under this 
part.
    (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], NOX, 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 calender 
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 ([deg] K).
Ta = Observed atmospheric temperature during the test run 
([deg] 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:
    (1) Except for LME units that use selective catalytic reduction 
(SCR) or selective non-catalytic reduction (SNCR)

[[Page 235]]

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 (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

[[Page 236]]

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 unit specific 
NOX emission rate determined during the test. Owners or 
operators must include in the monitoring plan the acceptable range of 
the water-

[[Page 237]]

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.
    (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

[[Page 238]]

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 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

[[Page 239]]

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 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.

[[Page 240]]

    (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 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

[[Page 241]]

    (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 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.

[[Page 242]]

[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 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

[[Page 243]]

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.

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

[[Page 244]]

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 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.

[[Page 245]]



   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; wheren 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 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

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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) 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

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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 concentration of Hg, as defined in section 2.1.7 of 
appendix A to this part, to report Hg emissions in [micro]gm/scm (when a 
Hg concentration monitoring system or a sorbent trap monitoring system 
is used to determine Hg mass emissions, as defined under Sec. 
75.81(b)); 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, Hg 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 require recertification include: replacement 
of

[[Page 248]]

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

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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), each 
Hg concentration monitoring system, 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. For Hg monitors, perform this check with elemental Hg 
standards;
    (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. For the Hg 
concentration monitoring system, the RATA shall be done on a [micro]gm/
scm 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
    (vi) For Hg monitors only, a 3-level system integrity check, using a 
NIST-traceable source of oxidized Hg, as described in section 6.2 of 
appendix A to this part. This test is not required for an Hg monitor 
that does not have a converter.
    (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;

[[Page 254]]

    (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 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) For each sorbent trap monitoring system, perform a RATA, on a 
[micro]gm/dscm basis, and a bias test.
    (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

[[Page 255]]

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 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

[[Page 256]]

    (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 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.
    (ix) For non-redundant backup Hg CEMS and sorbent trap monitoring 
systems, and for like-kind replacement Hg analyzers, the following 
provisions apply in addition to, or, in some cases, in lieu of, the 
general requirements in paragraphs (d)(2)(i) through (d)(2)(viii) of 
this section:
    (A) When a certified sorbent trap monitoring system is brought into 
service as a regular non-redundant backup monitoring system, the system 
shall be operated according to the procedures in Sec. 75.15 and 
appendix K of this part;
    (B) When a regular non-redundant backup Hg CEMS or a like-kind 
replacement Hg analyzer is brought into service, a linearity check with 
elemental Hg standards, as described in paragraph (c)(1)(ii) of this 
section and section 6.2 of appendix A of this part, and a single-point 
system integrity check, as described in section 2.6 of appendix B of 
this part, shall be performed. Alternatively, a 3-level system

[[Page 257]]

integrity check, as described in paragraph (c)(1)(vi) of this section 
and paragraph (g) of section 6.2 in appendix A of this part, may be 
performed in lieu of these two tests.
    (C) The weekly single-point system integrity checks described in 
section 2.6 of appendix B of this part are required as long as a non-
redundant backup Hg CEMS or like-kind replacement Hg analyzer remains in 
service, unless the daily calibrations of the Hg analyzer are done using 
a NIST-traceable source of oxidized Hg.
    (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 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

[[Page 258]]

    (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 (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

[[Page 259]]

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).
    (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

[[Page 260]]

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]



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 appendix A of part 60 of this chapter 
(supplemented, as necessary, by guidance from the Administrator), or one 
of the Hg reference methods in Sec. 75.22, as applicable, instead of 
the procedures specified in appendix B of this part.
    (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

[[Page 261]]

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 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

[[Page 262]]

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.

[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]



Sec. 75.22  Reference test methods.

    (a) The owner or operator shall use the following methods, which are 
found in appendix A-4 to part 60 of this chapter or have been published 
by ASTM, to conduct the following tests: monitoring system tests for 
certification or recertification of continuous emission monitoring 
systems and excepted monitoring systems under appendix E to this part; 
the emission tests required under Sec. 75.81(c) and (d); 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

[[Page 263]]

and system bias checks of the method. Dynamic spiking may be conducted 
(optionally) as an additional quality assurance 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.
    (7) ASTM D6784-02, Standard Test Method for Elemental, Oxidized, 
Particle-Bound and Total Mercury in Flue Gas Generated from Coal-Fired 
Stationary Sources (Ontario Hydro Method) (incorporated by reference 
under Sec. 75.6 of this part) is the reference method for determining 
Hg concentration.
    (i) Alternatively, Method 29 in appendix A-8 to part 60 of this 
chapter may be used, with these caveats: The procedures for preparation 
of Hg standards and sample analysis in sections 13.4.1.1 through 
13.4.1.3 ASTM D6784-02 (incorporated by reference under Sec. 75.6 of 
this part) shall be followed instead of the procedures in sections 
7.5.33 and 11.1.3 of Method 29 in appendix A-8 to part 60 of this 
chapter, and the QA/QC procedures in section 13.4.2 of ASTM D6784-02 
(incorporated by reference under Sec. 75.6 of this part) shall be 
performed instead of the procedures in section 9.2.3 of Method 29 in 
appendix A-8 to part 60 of this chapter. The tester may also opt to use 
the sample recovery and preparation procedures in ASTM D6784-02 
(incorporated by reference under Sec. 75.6 of this part) instead of the 
Method 29 in appendix A-8 to part 60 of this chapter procedures, as 
follows: sections 8.2.8 and 8.2.9.1 of Method 29 in appendix A-8 to part 
60 of this chapter may be replaced with sections 13.2.9.1 through 
13.2.9.3 of ASTM D6784-02 (incorporated by reference under Sec. 75.6 of 
this part); sections 8.2.9.2 and 8.2.9.3 of Method 29 in appendix A-8 to 
part 60 of this chapter may be replaced with sections 13.2.10.1 through 
13.2.10.4 of ASTM D6784-02 (incorporated by reference under Sec. 75.6 
of this part); section 8.3.4 of Method 29 in appendix A-8 to part 60 of 
this chapter may be replaced with section 13.3.4 or 13.3.6 of ASTM 
D6784-02 (as appropriate) (incorporated by reference under Sec. 75.6 of 
this part); and section 8.3.5 of Method 29 in appendix A-8 to part 60 of 
this chapter may be replaced with section 13.3.5 or 13.3.6 of ASTM 
D6784-02 (as appropriate) (incorporated by reference under Sec. 75.6 of 
this part).
    (ii) Whenever ASTM D6784-02 (incorporated by reference under Sec. 
75.6 of this part) or Method 29 in appendix A-8 to part 60 of this 
chapter is used, paired sampling trains are required. To validate a RATA 
run or an emission test run, the relative deviation (RD), calculated 
according to section 11.7 of appendix K to this part, must not exceed 10 
percent, when the average concentration is greater than 1.0 [micro]g/
m\3\. If the average concentration is <=1.0 [micro]g/m\3\, the RD must 
not exceed 20 percent. The RD results are also acceptable if the 
absolute difference between the Hg concentrations measured by the paired 
trains does not exceed 0.03 [micro]g/m\3\. If the RD criterion is met, 
the run is valid. For each valid run, average the Hg concentrations 
measured by the two trains (vapor phase, only).
    (iii) Two additional reference methods that may be used to measure 
Hg concentration are: Method 30A, ``Determination of Total Vapor Phase 
Mercury Emissions from Stationary Sources (Instrumental Analyzer 
Procedure)'' and Method 30B, ``Determination of Total Vapor Phase 
Mercury Emissions from Coal-Fired Combustion Sources Using Carbon 
Sorbent Traps''.
    (iv) When Method 29 in appendix A-8 to part 60 of this chapter or 
ASTM D6784-02 (incorporated by reference under Sec. 75.6 of this part) 
is used for the Hg emission testing required under Sec. Sec. 75.81(c) 
and (d), locate the reference method test points according to section 
8.1 of Method 30A, and if Hg stratification testing is part of the test 
protocol, follow the procedures in sections 8.1.3 through 8.1.3.5 of 
Method 30A.
    (b) The owner or operator may use any of the following methods, 
which are found in appendix A to part 60 of this chapter or have been 
published by ASTM, 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;

[[Page 264]]

    (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.
    (5) ASTM D6784-02, Standard Test Method for Elemental, Oxidized, 
Particle-Bound and Total Mercury in Flue Gas Generated from Coal-Fired 
Stationary Sources (Ontario Hydro Method) (incorporated by reference 
under Sec. 75.6 of this part) for determining Hg concentration;
    (6) Method 29 in appendix A-8 to part 60 of this chapter for 
determining Hg concentration;
    (7) Method 30A for determining Hg concentration; and
    (8) Method 30B for determining Hg concentration.
    (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:
    (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]



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

[[Page 265]]

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, a NOX concentration monitoring system used to 
determine NOX mass emissions, as defined in Sec. 
75.71(a)(2), a Hg concentration monitoring system or a sorbent trap 
monitoring system 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 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]



             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

[[Page 266]]

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 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).

[[Page 267]]

    (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, Hg concentration, 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.
    (b) SO2, CO2, or O2 concentration 
data, Hg concentration data, and moisture data. For each hour of missing 
SO2, Hg, 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, Hg, 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, Hg, 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 to part 60 of this chapter 
is used to determine NOX emission rate) the minimum potential 
moisture percentage, or the maximum potential Hg concentration, as 
specified, respectively, in sections 2.1.1.1, 2.1.3.1, 2.1.3.2, 2.1.5, 
and 2.1.7 of appendix A to this part. 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) 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

[[Page 268]]

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 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]



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

    (a) Following initial certification of the required SO2, 
CO2, O2, or Hg concentration, 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

[[Page 269]]

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.
[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).

[[Page 270]]

    (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]



Sec. 75.33  Standard missing data procedures for SO2,
NOX, Hg, 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 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

[[Page 271]]

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;
    (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

[[Page 272]]

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:
    (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

[[Page 273]]

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 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, Hg 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 (90 or more for Hg)........  N <= 24...............  Average.................  HB/HA.
                                        N  24......  For SO2, CO2, Hg, and
                                                                 H2O **, the greater of:
                                                                   Average..............  HB/HA.
                                                                   90th percentile......  720 hours.*
                                                                For O2 and H2O\X\, the
                                                                 lesser of:
                                                                   10th percentile......  HB/HA.
                                                                                          720 hours.*
90 or more, but below 95 (   N <= 8................  Average.................  HB/HA.
 80 but < 90 for Hg).
                                        N  8.......  For SO2, CO2, Hg, 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.*

[[Page 274]]

 
80 or more, but below 90 (   N  0.......  For SO2, CO2, Hg, and
 70 but < 80 for Hg).                                            H2O: **
                                                                   Maximum value \1\....  720 hours.*
                                                                For O2 and H2O\X\:
                                                                   Minimum value \1\....  720 hours.*
Below 80 (Below 70 for Hg)............  N  0.......  Maximum potential
                                                                 concentration \3\ or %
                                                                 (for SO2, CO2, Hg, 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 or Hg 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\ Alternatively, where a unit with add-on SO2 or Hg 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 SO2 or Hg concentration or (b) 1.25 times the maximum controlled value
  from the previous 720 quality-assured monitor operating hours.
\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.


   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            Method          Lookback period       Load ranges
           (percent)                 (hours) \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.

[[Page 275]]

    (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 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

[[Page 276]]

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:

         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*

[[Page 277]]

 
                                       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]



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 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

[[Page 278]]

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, and Sec. 75.38(c), 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
    (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;

[[Page 279]]

    (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.
    (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), 75.38(c), 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]



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

[[Page 280]]

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 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,

[[Page 281]]

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'' 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. 75.38  Standard missing data procedures for Hg CEMS.

    (a) Once 720 quality assured monitor operating hours of Hg 
concentration data have been obtained following initial certification, 
the owner or operator shall provide substitute data for Hg concentration 
in accordance with the procedures in ( 75.33(b)(1) through (b)(4), 
except that the term ``Hg concentration'' shall apply rather than 
``SO2 concentration,'' the term ``Hg

[[Page 282]]

concentration monitoring system'' shall apply rather than 
``SO2 pollutant concentration monitor,'' the term ``maximum 
potential Hg concentration, as defined in section 2.1.7 of appendix A to 
this part'' shall apply, rather than ``maximum potential SO2 
concentration'', and the percent monitor data availability trigger 
conditions prescribed for Hg in Table 1 of Sec. 75.33 shall apply 
rather than the trigger conditions prescribed for SO2.
    (b) For a unit equipped with a flue gas desulfurization (FGD) system 
that significantly reduces the concentration of Hg emitted to the 
atmosphere (including circulating fluidized bed units that use limestone 
injection), or for a unit equipped with add-on Hg emission controls 
(e.g., carbon injection), the standard missing data procedures in 
paragraph (a) of this section may only be used for hours in which the 
SO2 or Hg emission controls are documented to be operating 
properly, as described in Sec. 75.58(b)(3). For any hour(s) in the 
missing data period for which this documentation is unavailable, the 
owner or operator shall report, as applicable, the maximum potential Hg 
concentration, as defined in section 2.1.7 of appendix A to this part. 
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 Hg 
emission controls for each missing data period in which the procedures 
in paragraph (a) of this section are applied.
    (c) For units with FGD systems or add-on Hg emission controls, when 
the percent monitor data availability is less than 80.0 percent and is 
greater than or equal to 70.0 percent, and a missing data period occurs, 
consistent with Sec. 75.34(a)(3), for each missing data hour in which 
the FGD or Hg emission controls are documented to be operating properly, 
the owner or operator may report the maximum controlled Hg concentration 
recorded in the previous 720 quality-assured monitor operating hours. In 
addition, when the percent monitor data availability is less than 70.0 
percent and a missing data period occurs, consistent with Sec. 
75.34(a)(5), for each missing data hour in which the FGD or Hg emission 
controls are documented to be operating properly, the owner or operator 
may report the greater of the maximum expected Hg concentration (MEC) or 
1.25 times the maximum controlled Hg concentration recorded in the 
previous 720 quality-assured monitor operating hours. The MEC shall be 
determined in accordance with section 2.1.7.1 of appendix A to this 
part.

[70 FR 28679, May 18, 2005, as amended at 73 FR 4349, Jan. 24, 2008]



Sec. 75.39  Missing data procedures for sorbent trap monitoring systems.

    (a) If a primary sorbent trap monitoring system has not been 
certified by the applicable compliance date specified under a State or 
Federal Hg mass emission reduction program that adopts the requirements 
of subpart I of this part, and if quality-assured Hg concentration data 
from a certified backup Hg monitoring system, reference method, or 
approved alternative monitoring system are unavailable, the owner or 
operator shall report the maximum potential Hg concentration, as defined 
in section 2.1.7 of appendix A to this part, until the primary system is 
certified.
    (b) For a certified sorbent trap system, a missing data period will 
occur in the following circumstances, unless quality-assured Hg 
concentration data from a certified backup Hg CEMS, sorbent trap system, 
reference method, or approved alternative monitoring system are 
available:
    (1) A gas sample is not extracted from the stack during unit 
operation (e.g., during a monitoring system malfunction or when the 
system undergoes maintenance); or
    (2) The results of the Hg analysis for the paired sorbent traps are 
missing or invalid (as determined using the quality assurance procedures 
in appendix K to this part). The missing data period begins with the 
hour in which the paired sorbent traps for which the Hg analysis is 
missing or invalid were put into service. The missing data period ends 
at the first hour in which valid Hg concentration data are obtained with 
another pair of sorbent traps (i.e., the hour at which this pair of 
traps was placed in service), or with a certified backup Hg CEMS, 
reference method, or

[[Page 283]]

approved alternative monitoring system.
    (c) Initial missing data procedures. Use the missing data procedures 
in Sec. 75.31(b) until 720 hours of quality-assured Hg concentration 
data have been collected with the sorbent trap monitoring system(s), 
following initial certification.
    (d) Standard missing data procedures. Once 720 quality-assured hours 
of data have been obtained with the sorbent trap system(s), begin 
reporting the percent monitor data availability in accordance with Sec. 
75.32 and switch from the initial missing data procedures in paragraph 
(c) of this section to the standard missing data procedures in Sec. 
75.38.
    (e) Notwithstanding the requirements of paragraphs (c) and (d) of 
this section, if the unit has add-on Hg emission controls or is equipped 
with a flue gas desulfurization system that significantly reduces Hg 
emissions, the owner or operator shall report the maximum potential Hg 
concentration, as defined in section 2.1.7 of appendix A to this part, 
for any hour(s) in the missing data period for which proper operation of 
the Hg emission controls or FGD system is not documented according to 
Sec. 75.58(b)(3).
    (f) In cases where the owner or operator elects to use a primary Hg 
CEMS and a certified redundant (or non-redundant) backup sorbent trap 
monitoring system (or vice-versa), when both the primary and backup 
monitoring systems are out-of-service and quality-assured Hg 
concentration data from a temporary like-kind replacement analyzer, 
reference method, or approved alternative monitoring system are 
unavailable, the previous 720 quality-assured monitor operating hours 
reported in the electronic quarterly report under Sec. 75.64 shall be 
used for the required missing data lookback, irrespective of whether 
these data were recorded by the Hg CEMS, the sorbent trap system, a 
temporary like-kind replacement analyzer, a reference method, or an 
approved alternative monitoring system.

[70 FR 28679, May 18, 2005, as amended at 73 FR 4349, Jan. 24, 2008]



                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

[[Page 284]]

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.
    (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

[[Page 285]]

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 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


[[Page 286]]



(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,
[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.

[[Page 287]]

    (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,
    [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


[[Page 288]]



(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 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

[[Page 289]]

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, 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 the affected units which will comprise the class; and
    (3) A demonstration that the magnitude of emissions of all units 
which will comprise the class of affected units are de minimis.
    (c) If the Administrator determines that the emissions from all 
affected units which will comprise the class of units are de minimis, 
then the Administrator shall publish notice in the Federal Register, 
providing a 30-day period for public comment, prior to granting a class-
approved alternative monitoring system.

[60 FR 40297, Aug. 8, 1995]



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.

[[Page 290]]

    (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.
    (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 28605, May 26, 1999]



                  Subpart F_Recordkeeping Requirements



Sec. Sec. 75.50-75.52  [Reserved]



Sec. 75.53  Monitoring plan.

    (a) General provisions.--(1)
    (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;

[[Page 291]]

    (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, 
Hg, 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 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 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, Hg monitor, and diluent gas monitor), 
the sorbent trap monitoring system, 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

[[Page 292]]

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 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, Hg, 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

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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;
    (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

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    (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 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;

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    (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 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. 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;

[[Page 296]]

    (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, Hg, 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; 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, each continuous opacity monitoring system, and 
each sorbent trap monitoring system (as defined in Sec. 72.2 of this 
chapter), 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.

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    (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);
    (E) Daily calibration units of measure;
    (F) Effective date/hour, and (if applicable) inactivation date/hour 
of each span value;
    (G) An indication of whether dual spans are required; 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 value is no longer effective (if applicable); and
    (I) For units using the excepted methodology under Sec. 75.19, the 
applicable SO2 emission factor.
    (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

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    (E) Activation and deactivation dates and hours, when the maximum 
hourly gross load, boundaries of the range of 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

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    (F) Activation date/hour and (if applicable) inactivation date/hour 
for the fuel flowmeter system;
    (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.
    (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 a list of the fuels that are burned or a statement that the unit 
is projected to

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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 part, the 
method of qualification used, and an indication of whether the data are 
actual or projected data.
    (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]



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; and
    (6) The quality control plan as described in section 1 of appendix B 
to this part, beginning with the date of provisional certification.
    (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 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

[[Page 301]]

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);
    (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.

[[Page 302]]

    (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 estimation
         Code                                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, maximum expected
                         Hg concentration, 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, Hg 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).
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).

[[Page 303]]

 
23....................  Maximum potential SO2 concentration, NOX
                         concentration, CO2 concentration, NOX emission
                         rate or flow 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.
32....................  Hourly Hg concentration determined from analysis
                         of a single trap multiplied by a factor of
                         1.111 when one of the paired traps is
                         invalidated or damaged (See Appendix K, section
                         8).
33....................  Hourly Hg concentration determined from the trap
                         resulting in the higher Hg concentration when
                         the relative deviation criterion for the paired
                         traps is not met (See Appendix K, section 8).
40....................  Fuel specific default value (or prorated default
                         value) used for the hour.
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 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

[[Page 304]]

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 
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

[[Page 305]]

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.
    (i) Hg emission record provisions (CEMS). The owner or operator 
shall record for each hour the information required by this paragraph 
for each affected unit using Hg CEMS in combination with flow rate, and 
(in certain cases) moisture, and diluent gas monitors, to determine Hg 
mass emissions and (if applicable) unit heat input under a State or 
Federal Hg mass emissions reduction program that adopts the requirements 
of subpart I of this part.
    (1) For Hg 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 Hg concentration ([micro]gm/scm, rounded to the nearest 
tenth). For a particular pair of sorbent traps, this will be the flow-
proportional average concentration for the data collection period;
    (iv) The bias-adjusted hourly average Hg concentration ([micro]gm/
scm, rounded to the nearest tenth) if a bias adjustment factor is 
required, as provided in Sec. 75.24(d);
    (v) Method of determination for hourly Hg concentration using Codes 
1-55 in Table 4a of this section; and
    (vi) The percent monitor data availability (to the nearest tenth of 
a percent), calculated pursuant to Sec. 75.32.
    (2) For flue gas moisture content during unit operation (if 
required), as measured and reported from each certified primary monitor, 
certified back-up monitor, or other approved method of emissions 
determination (except where a default moisture value is used in 
accordance with Sec. 75.11(b), or approved under Sec. 75.66):
    (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);
    (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

[[Page 306]]

    (v) Method of determination for hourly average moisture percentage, 
using Codes 1-55 in Table 4a of this section.
    (3) For diluent gas (O2 or CO2) concentration 
during unit operation (if required), 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 diluent gas (O2 or CO2) 
concentration (in percent, rounded to the nearest tenth);
    (iv) Method of determination code for diluent gas (O2 or 
CO2) concentration data using Codes 1-55, in Table 4a of this 
section; and
    (v) The percent monitor data availability (to the nearest tenth of a 
percent) for the O2 or CO2 monitoring system (if a 
separate O2 or CO2 monitoring system is used for 
heat input determination), calculated pursuant to Sec. 75.32.
    (4) For stack gas volumetric 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, 
record the information required under paragraphs (c)(2)(i) through 
(c)(2)(vi) of this section.
    (5) For Hg mass emissions 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 Hg mass emissions (ounces, rounded to three decimal 
places);
    (iii) Hourly Hg mass emissions (ounces, rounded to three decimal 
places), adjusted for bias if a bias adjustment factor is required, as 
provided in Sec. 75.24(d); and
    (iv) Identification code for emissions formula used to derive hourly 
Hg mass emissions from Hg concentration, flow rate and moisture data, as 
provided in Sec. 75.53.
    (j) Hg emission record provisions (sorbent trap systems). The owner 
or operator shall record for each hour the information required by this 
paragraph, for each affected unit using sorbent trap monitoring systems 
in combination with flow rate, moisture, and (in certain cases) diluent 
gas monitors, to determine Hg mass emissions and (if required) unit heat 
input under a State or Federal Hg mass emissions reduction program that 
adopts the requirements of subpart I of this part.
    (1) For Hg 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 Hg concentration ([micro]gm/dscm, rounded to the 
nearest tenth). For a particular pair of sorbent traps, this will be the 
flow-proportional average concentration for the data collection period;
    (iv) The bias-adjusted hourly average Hg concentration ([micro]gm/
dscm, rounded to the nearest tenth) if a bias adjustment factor is 
required, as provided in Sec. 75.24(d);
    (v) Method of determination for hourly average Hg concentration 
using Codes 1-55 in Table 4a of this section; and
    (vi) Percent monitor data availability (recorded to the nearest 
tenth of a percent), calculated pursuant to Sec. 75.32;
    (2) For flue gas moisture content during unit operation, as measured 
and reported from each certified primary monitor, certified back-up 
monitor, or other approved method of emissions determination (except 
where a default moisture value is used in accordance with Sec. 
75.11(b), or approved under Sec. 75.66), record the information 
required under paragraphs (i)(2)(i) through (i)(2)(v) of this section;
    (3) For diluent gas (O2 or CO2) concentration 
during unit operation (if required for heat input determination), record 
the information required under paragraphs (i)(3)(i) through (i)(3)(v) of 
this section.
    (4) For stack gas volumetric flow rate during unit operation, as 
measured and reported from each certified

[[Page 307]]

primary monitor, certified back-up monitor, or other approved method of 
emissions determination, record the information required under 
paragraphs (c)(2)(i) through (c)(2)(vi) of this section.
    (5) For Hg mass emissions 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, record the information 
required under paragraph (i)(5) of this section.
    (6) Record the average flow rate of stack gas through each sorbent 
trap (in appropriate units, e.g., liters/min, cc/min, dscm/min).
    (7) Record the gas flow meter reading (in dscm, rounded to the 
nearest hundreth) at the beginning and end of the collection period and 
at least once in each unit operating hour during the collection period.
    (8) Calculate and record the ratio of the bias-adjusted stack gas 
flow rate to the sample flow rate, as described in section 11.2 of 
appendix K to this part.

[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]



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;
    (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);

[[Page 308]]

    (v) Temperature of flue gas at furnace exit or economizer outlet 
duct ([deg]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. 75.34(a)(1), (a)(2), (a)(3) or (a)(5), and for units 
with add-on Hg emission controls, the owner or operator shall record:
    (i) Parametric data which demonstrate, for each hour of missing 
SO2, Hg, 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. 
Alternatively, for units equipped with flue gas desulfurization (FGD) 
systems, the owner or operator may use quality-assured data from a 
certified SO2 monitor to demonstrate proper operation of the 
emission controls during periods of missing Hg data;
    (ii) A flag indicating, for each hour of missing SO2, Hg, 
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);
    (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

[[Page 309]]

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 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

[[Page 310]]

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 during the previous NOX emission rate test).
    (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

[[Page 311]]

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 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]



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.

[[Page 312]]

    (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), Hg monitor, 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, all daily system integrity 
checks (Hg monitors, only), 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) Date and hour;
    (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 concentration monitor 
(including O2 monitors used to determine CO2 
emissions), Hg concentration monitor, 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) and 3-level system 
integrity checks (Hg monitors with converters, only), 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);

[[Page 313]]

    (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;
    (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, each Hg 
concentration monitoring system, each sorbent trap 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,

[[Page 314]]

NOX-diluent continuous emission monitoring system, 
SO2-diluent continuous emission monitoring system, diluent 
gas (O2 or CO2) monitor used to determine heat 
input, NOX concentration monitoring system, moisture 
monitoring system, Hg concentration monitoring system, sorbent trap 
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), except for units that do not produce electrical or 
thermal output; 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 in appendix A to 
this part; and
    (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.
    (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, Hg, 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;

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    (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 ([deg]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;
    (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 ([deg]F);
    (H) Composite (wall effects) traverse point identifier;

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    (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 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;

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    (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 ([deg]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) For each RATA run using the Ontario Hydro Method to determine 
Hg concentration:
    (A) Percent CO2 and O2 in the stack gas, dry 
basis;
    (B) Moisture content of the stack gas (percent H2O);
    (C) Average stack temperature ( [deg]F);
    (D) Dry gas volume metered (dscm);
    (E) Percent isokinetic;
    (F) Particle-bound Hg collected by the filter, blank, and probe 
rinse ([micro]gm);
    (G) Oxidized Hg collected by the KCl impingers ([micro]gm);
    (H) Elemental Hg collected in the HNO3/
H2O2 impinger and in the KMnO4/
H2SO4 impingers ([micro]gm);
    (I) Total Hg, including particle-bound Hg ([micro]gm); and
    (J) Total Hg, excluding particle-bound Hg ([micro]gm)
    (viii) Data elements for Methods 30A and 30B. [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.
    (x) For each RATA run using Method 29 in appendix A-8 to part 60 of 
this chapter to determine Hg concentration:
    (A) Percent CO2 and O2 in the stack gas, dry 
basis;
    (B) Moisture content of the stack gas (percent H2O);
    (C) Average stack gas temperature ( [deg]F);
    (D) Dry gas volume metered (dscm);
    (E) Percent isokinetic;
    (F) Particulate Hg collected in the front half of the sampling 
train, corrected for the front-half blank value ([micro]g); and
    (G) Total vapor phase Hg collected in the back half of the sampling 
train, corrected for the back-half blank value ([micro]g).
    (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

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CEMS, Hg CEMS, or sorbent trap monitoring systems 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 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. For 
sorbent trap monitoring systems, the laboratory analyses of all sorbent 
traps, and information documenting the results of all leak checks and 
other applicable quality control procedures.
    (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.
    (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;

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    (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 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; and
    (F) Quarter and year.
    (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

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    (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) For the sorbent traps used in sorbent trap monitoring systems 
to quantify Hg concentration under subpart I of this part (including 
sorbent traps used for relative accuracy testing), the owner or operator 
shall keep records of the following:
    (i) The ID number of the monitoring system in which each sorbent 
trap was used to collect Hg;
    (ii) The unique identification number of each sorbent trap;
    (iii) The beginning and ending dates and hours of the data 
collection period for each sorbent trap;
    (iv) The average Hg concentration (in [micro]gm/dscm) for the data 
collection period;
    (v) Information documenting the results of the required leak checks;
    (vi) The analysis of the Hg collected by each sorbent trap; and
    (vii) Information documenting the results of the other applicable 
quality control procedures in Sec. 75.15 and in appendices B and K to 
this part.
    (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);
    (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;

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    (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.
    (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

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    (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;
    (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).
    (c) Except as otherwise provided in Sec. 75.58(b)(3)(i), units with 
add-on SO2 or NOX emission controls following the 
provisions of Sec. 75.34(a)(1) or (a)(2), and for units with add-on Hg 
emission controls, the owner or operator shall keep

[[Page 323]]

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
    (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 based on the criteria established in 
Sec. Sec. 75.19(c)(1)(iv)(B)(1); and
    (xi) Purpose of group tests.

[[Page 324]]

    (e) Excepted monitoring for Hg low mass emission units under Sec. 
75.81(b). For qualifying coal-fired units using the alternative low mass 
emission methodology under Sec. 75.81(b), the owner or operator shall 
record the data elements described in Sec. 75.59(a)(7)(vii), Sec. 
75.59(a)(7)(viii), or Sec. 75.59(a)(7)(x), as applicable, for each run 
of each Hg emission test and re-test required under Sec. 75.81(c)(1) or 
Sec. 75.81(d)(4)(iii).
    (f) 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]



                    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 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.
    (8) Routine retest reports for Hg low mass emissions units. 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 for a semiannual or annual retest required under Sec. 
75.81(d)(4)(iii) for a Hg low mass emissions unit, within 45 days after 
completing the test or within 15 days of receiving the request, 
whichever is later. The designated representative shall report, at a 
minimum, the following hardcopy information to the applicable EPA 
Regional Office, appropriate

[[Page 325]]

State, and/or appropriate local air pollution control agency that 
requested the hardcopy report: a summary of the test results; the raw 
reference method data for each test run; the raw data and results of all 
pretest, post-test, and post-run quality-assurance checks of the 
reference method; the raw data and results of moisture measurements made 
during the test runs (if applicable); diagrams illustrating the test and 
sample point locations; a copy of the test protocol used; calibration 
certificates for the gas standards or standard solutions used in the 
testing; laboratory calibrations of the source sampling equipment; and 
the names of the key personnel involved in the test program, including 
test team members, plant contact persons, agency representatives and 
test observers.
    (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]



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.
    (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 the excepted Hg monitoring methodology under 
Sec. 75.81(b), 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

[[Page 326]]

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.
    (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

[[Page 327]]

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, of periodic retesting of low 
mass emissions units performed under Sec. 75.19(c)(1)(iv)(D), and of 
periodic retesting of Hg low mass emissions units performed under Sec. 
75.81(d)(4)(iii), 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.
    (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

[[Page 328]]

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, 
NOX, or Hg mass emission reduction program that incorporates 
by reference, or otherwise adopts, the monitoring, recordkeeping, and 
reporting requirements of subpart F, G, H, or I of this part. The 
notification shall be submitted no later than 7 calendar days after the 
applicable certification deadline is reached.
    (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]



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.

[[Page 329]]

    (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.

[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]



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 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

[[Page 330]]

(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 be 
submitted in a format suitable for review and shall include the 
information in Sec. 75.59(a)(9).

[64 FR 28621, May 26, 1999, as amended at 67 FR 40443, June 12, 2002; 73 
FR 4357, Jan. 24, 2008]



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

[[Page 331]]

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;
    (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;

[[Page 332]]

    (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) Except for the daily calibration error test data, daily 
interference check, and off-line calibration demonstration information 
required in Sec. 75.59(a)(1) and (2), which must always be submitted 
with the quarterly report, the certification, quality assurance, and 
quality control information required in Sec. 75.59 shall either be 
submitted prior to or concurrent with the submittal of the relevant 
quarterly electronic data report.
    (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; and
    (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)(vii)(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.

[[Page 333]]

    (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.
    (127) 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 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) Any cover letter text accompanying a quarterly report shall 
either be submitted in hardcopy to the Agency or be provided in 
electronic format 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]



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]

[[Page 334]]



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 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

[[Page 335]]

    (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 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

[[Page 336]]

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 indicated.



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.
    (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.

[[Page 337]]

    (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
    (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

[[Page 338]]

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 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

[[Page 339]]

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. 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

[[Page 340]]

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:
    (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.

[[Page 341]]

    (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 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

[[Page 342]]

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 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

[[Page 343]]

    (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 (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

[[Page 344]]

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
    (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.

[[Page 345]]

    (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).
    (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.

[[Page 346]]

    (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 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

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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 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

[[Page 348]]

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 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:

[[Page 349]]

    (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 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

[[Page 350]]

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 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

[[Page 351]]

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
    (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

[[Page 352]]

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)
    (ix) If, for any required CEMS, diagnostic linearity checks or RATAs 
other than those required by this section are 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

[[Page 353]]

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 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

[[Page 354]]

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).
    (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''.

[[Page 355]]

    (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) 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

[[Page 356]]

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, 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.



                  Subpart I_Hg Mass Emission Provisions

    Source: 70 FR 28684, May 18, 2005, unless otherwise noted.



Sec. 75.80  General 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 Hg mass emission reduction 
program that incorporates by reference, or otherwise adopts the 
provisions of, this subpart.
    (1) For purposes of this subpart, the term ``affected unit'' shall 
mean any coal-fired unit (as defined in Sec. 72.2 of this chapter) that 
is subject to a State or Federal Hg 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 Hg 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 Hg 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 Hg concentration, flow 
rate, moisture, diluent gas concentration, 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 Hg mass emission reduction program. The requirements of this 
part for SO2, NOX, CO2 and opacity 
monitoring, recordkeeping and reporting do not apply to units that are 
subject only to a State or Federal Hg mass emission reduction

[[Page 357]]

program that adopts the requirements of this subpart, but are not 
affected units under the Acid Rain Program or under a State or Federal 
NOX mass emission reduction program that adopts the 
requirements of subpart H of this part.
    (b) Compliance dates. The owner or operator of an affected unit 
shall meet the compliance deadlines established by an applicable State 
or Federal Hg 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. 75.82(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. 75.82(b)(2)(ii) shall operate the unit so as to discharge, 
or allow to be discharged emissions of Hg to the atmosphere without 
accounting for all such emissions in accordance with the applicable 
provisions of this part.
    (3) No owner or operator of an affected unit or a non-affected unit 
under Sec. 75.82(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 Hg 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. 75.81.
    (4) No owner or operator of an affected unit or a non-affected unit 
under Sec. 75.82(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 Hg mass emission 
reduction program that adopts the requirements of this subpart; or
    (ii) The owner or operator is monitoring Hg mass emissions from the 
affected unit with another certified monitoring system approved, in 
accordance with the provisions of paragraph (d) of this section; or
    (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 the Acid Rain 
Program or to a State or Federal NOX mass emission reduction 
program that adopts the requirements of subpart H of this part shall 
comply with the applicable initial certification and recertification 
procedures in Sec. 75.20 and Sec. 75.70(d), except that the owner or 
operator shall meet any additional requirements for Hg concentration 
monitoring systems, sorbent trap monitoring systems (as defined in Sec. 
72.2 of this chapter), flow monitors, CO2 monitors, 
O2 monitors, or moisture monitors, as set forth under Sec. 
75.81, under the common stack provisions in Sec. 75.82, or under an 
applicable State or Federal Hg 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 
the Acid Rain Program or to a State or Federal NOX mass 
emission reduction program that adopts the requirements of subpart H of 
this part shall comply with the initial certification and 
recertification procedures established by an applicable State or Federal 
Hg mass emission reduction program that adopts the requirements of this 
subpart.
    (e) Quality assurance and quality control requirements. For units 
that use continuous emission monitoring systems to account for Hg mass 
emissions, the owner or operator shall meet the applicable quality 
assurance and quality control requirements in Sec. 75.21 and appendix B 
to this part for the flow monitoring systems, Hg concentration 
monitoring systems, moisture monitoring systems, and diluent monitors

[[Page 358]]

required under Sec. 75.81. Units using sorbent trap monitoring systems 
shall meet the applicable quality assurance requirements in Sec. 75.15, 
appendix K to this part, and sections 1.5 and 2.3 of appendix B to this 
part.
    (f) Missing data procedures. Except as provided in Sec. 75.38(b) 
and paragraph (g) of this section, the owner or operator shall provide 
substitute data from monitoring systems required under Sec. 75.81 for 
each affected unit as follows:
    (1) For an owner or operator using an Hg concentration monitoring 
system, substitute for missing data in accordance with the applicable 
missing data procedures in Sec. Sec. 75.31 through 75.38 whenever the 
unit combusts fuel and:
    (i) A valid, quality-assured hour of Hg concentration data (in 
[micro]gm/scm) has not been measured and recorded, either by a certified 
Hg concentration monitoring system, by an appropriate EPA reference 
method under Sec. 75.22, or by an approved alternative monitoring 
method under subpart E of this part; or
    (ii) A valid, quality-assured hour of flow rate data (in scfh) has 
not been measured and recorded for a unit either by a certified flow 
monitor, by an appropriate EPA reference method under Sec. 75.22, or by 
an approved alternative monitoring system under subpart E of this part; 
or
    (iii) 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, by an appropriate EPA 
reference method under Sec. 75.22, 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), is used to account for the hourly moisture content of the 
stack gas, or when correction of the Hg concentration for moisture is 
not necessary; or
    (iv) A valid, quality-assured hour of heat input rate data (in 
MMBtu/hr) has not been measured and recorded for a unit, either by 
certified flow rate and diluent (CO2 or O2) 
monitors, by appropriate EPA reference methods under Sec. 75.22, or by 
approved alternative monitoring systems under subpart E of this part, 
where heat input is required for allocating allowances under the 
applicable State or Federal Hg mass emission reduction program that 
adopts the requirements of this subpart.
    (2) For an owner or operator using a sorbent trap monitoring system 
to quantify Hg mass emissions, substitute for missing data in accordance 
with the missing data procedures in Sec. 75.39.
    (g) Reporting data prior to initial certification. If, by the 
applicable compliance date under the State or Federal Hg mass emission 
reduction program that adopts the requirements of this subpart, the 
owner or operator of an affected unit has not successfully completed all 
required certification tests for any monitoring system(s), he or she 
shall determine, record and report hourly data prior to initial 
certification using one of the following procedures, for the monitoring 
system(s) that are uncertified:
    (1) For Hg concentration and flow monitoring systems, report the 
maximum potential concentration of Hg as defined in section 2.1.7 of 
appendix A to this part and the maximum potential flow rate, as defined 
in section 2.1.4.1 of appendix A to this part; or
    (2) For any unit, report data from the reference methods under Sec. 
75.22; or
    (3) For any unit that is required to report heat input for purposes 
of allocating allowances, report (as applicable) the maximum potential 
flow rate, as defined in section 2.1.4.1 of appendix A to this part, the 
maximum potential CO2 concentration, as defined in section 
2.1.3.1 of appendix A to this part, the minimum potential O2 
concentration, as defined in section 2.1.3.2 of appendix A to this part, 
and the minimum potential percent moisture, as defined in section 2.1.5 
of appendix A to this part.
    (h) Petitions. (1) The designated representative of an affected unit 
that is also subject to the Acid Rain Program 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 the applicable State or 
Federal Hg 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

[[Page 359]]

such State or Federal Hg mass emission reduction program only to the 
extent that the petition is approved in writing 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. 75.82 
shall be submitted to the permitting authority and the Administrator and 
shall be governed by paragraph (h)(3) of this section. Such a petition 
shall meet the requirements of Sec. 75.66 and any additional 
requirements established by an applicable State or Federal Hg mass 
emission reduction program that adopts the requirements of this subpart.
    (3) The designated representative of an affected unit that is not 
subject to the Acid Rain Program 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 the 
applicable State or Federal Hg 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 only to 
the extent that it is approved in writing by the Administrator, in 
consultation with the permitting authority.

[70 FR 28684, May 18, 2005, as amended at; 73 FR 4360, Jan. 24, 2008]



Sec. 75.81  Monitoring of Hg mass emissions and heat input at
the unit level.

    The owner or operator of the affected coal-fired unit shall either:
    (a) Meet the general operating requirements in Sec. 75.10 for the 
following continuous emission monitors (except as provided in accordance 
with subpart E of this part):
    (1) A Hg concentration monitoring system (as defined in Sec. 72.2 
of this chapter) or a sorbent trap monitoring system (as defined in 
Sec. 72.2 of this chapter), to measure the mass concentration of total 
vapor phase Hg in the flue gas, including the elemental and oxidized 
forms of Hg, in micrograms per standard cubic meter ([micro]g/scm); and
    (2) A flow monitoring system; and
    (3) A continuous moisture monitoring system (if correction of Hg 
concentration for moisture is required), as described in Sec. 75.11(b). 
Alternatively, the owner or operator may use the appropriate fuel-
specific default moisture value provided in Sec. 75.11, or a site-
specific moisture value approved by petition under Sec. 75.66; and
    (4) If heat input is required to be reported under the applicable 
State or Federal Hg mass emission reduction program that adopts the 
requirements of this subpart, the owner or operator must meet the 
general operating requirements for a flow monitoring system and an 
O2 or CO2 monitoring system to measure heat input 
rate.
    (b) For an affected unit that emits 464 ounces (29 lb) of Hg per 
year or less, use the following excepted monitoring methodology. To 
implement this methodology for a qualifying unit, the owner or operator 
shall meet the general operating requirements in Sec. 75.10 for the 
continuous emission monitors described in paragraphs (a)(2) and (a)(4) 
of this section, and perform Hg emission testing for initial 
certification and on-going quality-assurance, as described in paragraphs 
(c) through (e) of this section.
    (c) To determine whether an affected unit is eligible to use the 
monitoring provisions in paragraph (b) of this section:
    (1) The owner or operator must perform Hg emission testing one year 
or less before the compliance date in Sec. 75.80(b), to determine the 
Hg concentration (i.e., total vapor phase Hg) in the effluent.
    (i) The testing shall be performed using one of the Hg reference 
methods listed in Sec. 75.22(a)(7), and shall consist of a minimum of 3 
runs at the normal unit operating load, while combusting coal. The coal 
combusted during the testing shall be representative of the coal that 
will be combusted at the start of the Hg mass emissions reduction 
program (preferably from the same source(s) of supply).
    (ii) The minimum time per run shall be 1 hour if Method 30A is used. 
If either Method 29 in appendix A-8 to part

[[Page 360]]

60 of this chapter, ASTM D6784-02 (the Ontario Hydro method) 
(incorporated by reference under Sec. 75.6 of this part), or Method 30B 
is used, paired samples are required for each test run and the runs must 
be long enough to ensure that sufficient Hg is collected to analyze. 
When Method 29 in appendix A-8 to part 60 of this chapter or the Ontario 
Hydro method is used, the test results shall be based on the vapor phase 
Hg collected in the back-half of the sampling trains (i.e., the non-
filterable impinger catches). For each Method 29 in appendix A-8 to part 
60 of this chapter, Method 30B, or Ontario Hydro method test run, the 
paired trains must meet the relative deviation (RD) requirement 
specified in Sec. 75.22(a)(7) or Method 30B, as applicable. If the RD 
specification is met, the results of the two samples shall be averaged 
arithmetically.
    (iii) If the unit is equipped with flue gas desulfurization or add-
on Hg emission controls, the controls must be operating normally during 
the testing, and, for the purpose of establishing proper operation of 
the controls, the owner or operator shall record parametric data or 
SO2 concentration data in accordance with Sec. 
75.58(b)(3)(i).
    (iv) If two or more of units of the same type qualify as a group of 
identical units in accordance with Sec. 75.19(c)(1)(iv)(B), the owner 
or operator may test a subset of these units in lieu of testing each 
unit individually. If this option is selected, the number of units 
required to be tested shall be determined from Table LM-4 in Sec. 
75.19. For the purposes of the required retests under paragraph (d)(4) 
of this section, EPA strongly recommends that (to the extent 
practicable) the same subset of the units not be tested in two 
successive retests, and that every effort be made to ensure that each 
unit in the group of identical units is tested in a timely manner.
    (2)(i) Based on the results of the emission testing, Equation 1 of 
this section shall be used to provide a conservative estimate of the 
annual Hg mass emissions from the unit:

[GRAPHIC] [TIFF OMITTED] TR24JA08.018


Where:

E = Estimated annual Hg mass emissions from the affected unit, (ounces/
          year)
K = Units conversion constant, 9.978 x 10-10 oz-scm/[micro]g-
          scf
N = Either 8,760 (the number of hours in a year) or the maximum number 
          of operating hours per year (if less than 8,760) allowed by 
          the unit's Federally-enforceable operating permit.
CHg = The highest Hg concentration ([micro]g/scm) from any of 
          the test runs or 0.50 [micro]g/scm, whichever is greater
Qmax = Maximum potential flow rate, determined according to 
          section 2.1.4.1 of appendix A to this part, (scfh)

    (ii) Equation 1 of this section assumes that the unit operates at 
its maximum potential flow rate, either year-round or for the maximum 
number of hours allowed by the operating permit (if unit operation is 
restricted to less than 8,760 hours per year). If the permit restricts 
the annual unit heat input but not the number of annual unit operating 
hours, the owner or operator may divide the allowable annual heat input 
(mmBtu) by the design rated heat input capacity of the unit (mmBtu/hr) 
to determine the value of ``N'' in Equation 1. Also, note that if the 
highest Hg concentration measured in any test run is less than 0.50 
[micro]g/scm, a default value of 0.50 [micro]g/scm must be used in the 
calculations.
    (3) If the estimated annual Hg mass emissions from paragraph (c)(2) 
of this section are 464 ounces per year or less, then the unit is 
eligible to use the monitoring provisions in paragraph (b) of this 
section, and continuous monitoring of the Hg concentration is not 
required (except as otherwise provided in paragraphs (e) and (f) of this 
section).
    (d) If the owner or operator of an eligible unit under paragraph 
(c)(3) of this section elects not to continuously monitor Hg 
concentration, then the following requirements must be met:
    (1) The results of the Hg emission testing performed under paragraph 
(c)

[[Page 361]]

of this section shall be submitted as a certification application to the 
Administrator and to the permitting authority, no later than 45 days 
after the testing is completed. The calculations demonstrating that the 
unit emits 464 ounces (or less) per year of Hg shall also be provided, 
and the default Hg concentration that will be used for reporting under 
Sec. 75.84 shall be specified in both the electronic and hard copy 
portions of the monitoring plan for the unit. The methodology is 
considered to be provisionally certified as of the date and hour of 
completion of the Hg emission testing.
    (2) Following initial certification, the same default Hg 
concentration value that was used to estimate the unit's annual Hg mass 
emissions under paragraph (c) of this section shall be reported for each 
unit operating hour, except as otherwise provided in paragraph 
(d)(4)(iv) or (d)(6) of this section. The default Hg concentration value 
shall be updated as appropriate, according to paragraph (d)(5) of this 
section.
    (3) The hourly Hg mass emissions shall be calculated according to 
section 9.1.3 in appendix F to this part.
    (4) The Hg emission testing described in paragraph (c) of this 
section shall be repeated periodically, for the purposes of quality-
assurance, as follows:
    (i) If the results of the certification testing under paragraph (c) 
of this section show that the unit emits 144 ounces (9 lb) of Hg per 
year or less, the first retest is required by the end of the fourth QA 
operating quarter (as defined in Sec. 72.2 of this chapter) following 
the calendar quarter of the certification testing; or
    (ii) If the results of the certification testing under paragraph (c) 
of this section show that the unit emits more than 144 ounces of Hg per 
year, but less than or equal to 464 ounces per year, the first retest is 
required by the end of the second QA operating quarter (as defined in 
Sec. 72.2 of this chapter) following the calendar quarter of the 
certification testing; and
    (iii) Thereafter, retesting shall be required either semiannually or 
annually (i.e., by the end of the second or fourth QA operating quarter 
following the quarter of the previous test), depending on the results of 
the previous test. To determine whether the next retest is due within 
two or four QA operating quarters, substitute the highest Hg 
concentration from the current test or 0.50 [micro]gm/scm (whichever is 
greater) into the equation in paragraph (c)(2) of this section. If the 
estimated annual Hg mass emissions exceeds 144 ounces, the next test is 
due within two QA operating quarters. If the estimated annual Hg mass 
emissions is 144 ounces or less, the next test is due within four QA 
operating quarters.
    (iv) An additional retest is required when there is a change in the 
coal rank of the primary fuel (e.g., when the primary fuel is switched 
from bituminous coal to lignite). Use ASTM D388-99 (incorporated by 
reference under Sec. 75.6 of this part) to determine the coal rank. The 
four principal coal ranks are anthracitic, bituminous, subbituminous, 
and lignitic. The ranks of anthracite coal refuse (culm) and bituminous 
coal refuse (gob) shall be anthracitic and bituminous, respectively. The 
retest shall be performed within 720 unit operating hours of the change.
    (5) The default Hg concentration used for reporting under Sec. 
75.84 shall be updated after each required retest. This includes retests 
that are required prior to the compliance date in Sec. 75.80(b). The 
updated value shall either be the highest Hg concentration measured in 
any of the test runs or 0.50 [micro]g/scm, whichever is greater. The 
updated value shall be applied beginning with the first unit operating 
hour in which Hg emissions data are required to be reported after 
completion of the retest, except as provided in paragraph (d)(4)(iv) of 
this section, where the need to retest is triggered by a change in the 
coal rank of the primary fuel. In that case, apply the updated default 
Hg concentration beginning with the first unit operating hour in which 
Hg emissions are required to be reported after the date and hour of the 
fuel switch.
    (6) If the unit is equipped with a flue gas desulfurization system 
or add-on Hg controls, the owner or operator shall record the 
information required under Sec. 75.58(b)(3) for each unit operating 
hour, to document proper operation of the emission controls. For any

[[Page 362]]

operating hour in which this documentation is unavailable, the maximum 
potential Hg concentration, as defined in section 2.1.7 of appendix A to 
this part, shall be reported.
    (e) For units with common stack and multiple stack exhaust 
configurations, the use of the monitoring methodology described in 
paragraphs (b) through (d) of this section is restricted as follows:
    (1) The methodology may not be used for reporting Hg mass emissions 
at a common stack unless all of the units using the common stack are 
affected units and the units' combined potential to emit does not exceed 
464 ounces of Hg per year times the number of units sharing the stack, 
in accordance with paragraphs (c) and (d) of this section. If the test 
results demonstrate that the units sharing the common stack qualify as 
low mass emitters, the default Hg concentration used for reporting Hg 
mass emissions at the common stack shall either be the highest value 
obtained in any test run or 0.50 [micro]g/scm, whichever is greater.
    (i) The initial emission testing required under paragraph (c) of 
this section may be performed at the common stack if the following 
conditions are met. Otherwise, testing of the individual units (or a 
subset of the units, if identical, as described in paragraph (c)(1)(iv) 
of this section) is required:
    (A) The testing must be done at a combined load corresponding to the 
designated normal load level (low, mid, or high) for the units sharing 
the common stack, in accordance with section 6.5.2.1 of appendix A to 
this part;
    (B) All of the units that share the stack must be operating in a 
normal, stable manner and at typical load levels during the emission 
testing. The coal combusted in each unit during the testing must be 
representative of the coal that will be combusted in that unit at the 
start of the Hg mass emission reduction program (preferably from the 
same source(s) of supply);
    (C) If flue gas desulfurization and/or add-on Hg emission controls 
are used to reduce level the emissions exiting from the common stack, 
these emission controls must be operating normally during the emission 
testing and, for the purpose of establishing proper operation of the 
controls, the owner or operator shall record parametric data or SO2 
concentration data in accordance with Sec. 75.58(b)(3)(i);
    (D) When calculating E, the estimated maximum potential annual Hg 
mass emissions from the stack, substitute the maximum potential flow 
rate through the common stack (as defined in the monitoring plan) and 
the highest concentration from any test run (or 0.50 [micro]g/scm, if 
greater) into Equation 1;
    (E) The calculated value of E shall be divided by the number of 
units sharing the stack. If the result, when rounded to the nearest 
ounce, does not exceed 464 ounces, the units qualify to use the low mass 
emission methodology; and
    (F) If the units qualify to use the methodology, the default Hg 
concentration used for reporting at the common stack shall be the 
highest value obtained in any test run or 0.50 [micro]g/scm, whichever 
is greater; or
    (ii) The retests required under paragraph (d)(4) of this section may 
also be done at the common stack. If this testing option is chosen, the 
testing shall be done at a combined load corresponding to the designated 
normal load level (low, mid, or high) for the units sharing the common 
stack, in accordance with section 6.5.2.1 of appendix A to this part. 
Provided that the required load level is attained and that all of the 
units sharing the stack are fed from the same on-site coal supply during 
normal operation, it is not necessary for all of the units sharing the 
stack to be in operation during a retest. However, if two or more of the 
units that share the stack are fed from different on-site coal supplies 
(e.g., one unit burns low-sulfur coal for compliance and the other 
combusts higher-sulfur coal), then either:
    (A) Perform the retest with all units in normal operation; or
    (B) If this is not possible, due to circumstances beyond the control 
of the owner or operator (e.g., a forced unit outage), perform the 
retest with the available units operating and assess the test results as 
follows. Use the Hg concentration obtained in the retest for reporting 
purposes under this part if the concentration is greater than or equal 
to the value obtained in the most recent test. If the retested value is

[[Page 363]]

lower than the Hg concentration from the previous test, continue using 
the higher value from the previous test for reporting purposes and use 
that same higher Hg concentration value in Equation 1 to determine the 
due date for the next retest, as described in paragraph (e)(1)(iii) of 
this section.
    (iii) If testing is done at the common stack, the due date for the 
next scheduled retest shall be determined as follows:
    (A) Substitute the maximum potential flow rate for the common stack 
(as defined in the monitoring plan) and the highest Hg concentration 
from any test run (or 0.50 [micro]g/scm, if greater) into Equation 1;
    (B) If the value of E obtained from Equation 1, rounded to the 
nearest ounce, is greater than 144 times the number of units sharing the 
common stack, but less than or equal to 464 times the number of units 
sharing the stack, the next retest is due in two QA operating quarters;
    (C) If the value of E obtained from Equation 1, rounded to the 
nearest ounce, is less than or equal to 144 times the number of units 
sharing the common stack, the next retest is due in four QA operating 
quarters.
    (2) For units with multiple stack or duct configurations, Hg 
emission testing must be performed separately on each stack or duct, and 
the sum of the estimated annual Hg mass emissions from the stacks or 
ducts must not exceed 464 ounces of Hg per year. For reporting purposes, 
the default Hg concentration used for each stack or duct shall either be 
the highest value obtained in any test run for that stack or 0.50 
[micro]gm/scm, whichever is greater.
    (3) For units with a main stack and bypass stack configuration, Hg 
emission testing shall be performed only on the main stack. For 
reporting purposes, the default Hg concentration used for the main stack 
shall either be the highest value obtained in any test run for that 
stack or 0.50 [micro]gm/scm, whichever is greater. Whenever the main 
stack is bypassed, the maximum potential Hg concentration, as defined in 
section 2.1.7 of appendix A to this part, shall be reported.
    (f) At the end of each calendar year, if the cumulative annual Hg 
mass emissions from an affected unit have exceeded 464 ounces, then the 
owner shall install, certify, operate, and maintain a Hg concentration 
monitoring system or a sorbent trap monitoring system no later than 180 
days after the end of the calendar year in which the annual Hg mass 
emissions exceeded 464 ounces. For common stack and multiple stack 
configurations, installation and certification of a Hg concentration or 
sorbent trap monitoring system on each stack (except for bypass stacks) 
is likewise required within 180 days after the end of the calendar year, 
if:
    (1) The annual Hg mass emissions at the common stack have exceeded 
464 ounces times the number of affected units using the common stack; or
    (2) The sum of the annual Hg mass emissions from all of the multiple 
stacks or ducts has exceeded 464 ounces; or
    (3) The sum of the annual Hg mass emissions from the main and bypass 
stacks has exceeded 464 ounces.
    (g) For an affected unit that is using a Hg concentration CEMS or a 
sorbent trap system under Sec. 75.81(a) to continuously monitor the Hg 
mass emissions, the owner or operator may switch to the methodology in 
Sec. 75.81(b), provided that the applicable conditions in paragraphs 
(c) through (f) of this section are met.

[70 FR 28684, May 18, 2005, as amended at 72 FR 51528, Sept. 7, 2007; 73 
FR 4360, Jan. 24, 2008]



Sec. 75.82  Monitoring of Hg mass emissions and heat input at common 
and multiple stacks.

    (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 non-affected units, the owner or operator shall either:
    (1) Install, certify, operate, and maintain the monitoring systems 
described in Sec. 75.81(a) at the common stack, record the combined Hg 
mass emissions for the units exhausting to the common stack. 
Alternatively, if, in accordance with Sec. 75.81(e), each of the units 
using the common stack is demonstrated to emit less than 464 ounces of 
Hg per year, the owner or operator

[[Page 364]]

may install, certify, operate and maintain the monitoring systems and 
perform the Hg emission testing described under Sec. 75.81(b). If 
reporting of the unit heat input rate is required, determine the hourly 
unit heat input rates either by:
    (i) Apportioning the common stack heat input rate to the individual 
units according to the procedures in Sec. 75.16(e)(3); or
    (ii) Installing, certifying, operating, and maintaining a flow 
monitoring system and diluent monitor in the duct to the common stack 
from each unit; or
    (2) Install, certify, operate, and maintain the monitoring systems 
and (if applicable) perform the Hg emission testing described in Sec. 
75.81(a) or Sec. 75.81(b) in the duct to the common stack from each 
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 the monitoring systems 
and (if applicable) perform the Hg emission testing described in Sec. 
75.81(a) or Sec. 75.81(b) in the duct to the common stack from each 
affected unit; or
    (2) Install, certify, operate, and maintain the monitoring systems 
described in Sec. 75.81(a) in the common stack; and
    (i) Install, certify, operate, and maintain the monitoring systems 
and (if applicable) perform the Hg emission testing described in Sec. 
75.81(a) or Sec. 75.81(b) in the duct to the common stack from each 
non-affected unit. The designated representative shall submit a petition 
to the permitting authority and the Administrator to allow a method of 
calculating and reporting the Hg mass emissions from the affected units 
as the difference between Hg mass emissions measured in the common stack 
and Hg mass emissions measured in the ducts of the non-affected 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 Hg mass emissions from the affected units are not underestimated; or
    (ii) Count the combined emissions measured at the common stack as 
the Hg mass emissions for the affected units, for recordkeeping and 
compliance purposes, in accordance with paragraph (a) of this section; 
or
    (iii) Submit a petition to the permitting authority and the 
Administrator to allow use of a method for apportioning Hg mass 
emissions measured in the common stack to each of the units using the 
common stack and for reporting the Hg 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 Hg mass emissions from the affected units are not underestimated.
    (3) If the monitoring option in paragraph (b)(2) of this section is 
selected, and if heat input is required to be reported under the 
applicable State or Federal Hg mass emission reduction program that 
adopts the requirements of this subpart, the owner or operator shall 
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 a flow monitoring system and a diluent gas 
(O2 or CO2) monitoring system in the duct leading 
from each affected unit to the common stack, and measure the heat input 
rate in each duct, according to section 5.2 of appendix F to this part.
    (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 Hg monitoring system(s) installed on the main stack, 
the owner and operator shall either:
    (1) Install, certify, operate, and maintain the monitoring systems 
described in Sec. 75.81(a) on both the main stack and the bypass stack 
and calculate Hg mass emissions for the unit as the sum of the Hg mass 
emissions measured at the two stacks;
    (2) Install, certify, operate, and maintain the monitoring systems 
described in Sec. 75.81(a) at the main stack and

[[Page 365]]

measure Hg mass emissions at the bypass stack using the appropriate 
reference methods in Sec. 75.22(b). Calculate Hg 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;
    (3) Install, certify, operate, and maintain the monitoring systems 
and (if applicable) perform the Hg emission testing described in Sec. 
75.81(a) or Sec. 75.81(b) 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, report, as applicable, the 
maximum potential Hg concentration (as defined in section 2.1.7 of 
appendix A to this part), and the appropriate substitute data values for 
flow rate, CO2 concentration, O2 concentration, 
and moisture (as applicable), in accordance with the missing data 
procedures of Sec. Sec. 75.31 through 75.37; or
    (4) If the monitoring option in paragraph (c)(1) or (c)(2) of this 
section is selected, and if heat input is required to be reported under 
the applicable State or Federal Hg mass emission reduction program that 
adopts the requirements of this subpart, the owner or operator shall:
    (i) Use the installed flow and diluent monitors to determine the 
hourly heat input rate at each stack (mmBtu/hr), according to section 
5.2 of appendix F to this part; and
    (ii) Calculate the hourly heat input at each stack (in mmBtu) by 
multiplying the measured stack heat input rate by the corresponding 
stack operating time; and
    (iii) Determine the hourly unit heat input by summing the hourly 
stack heat input values.
    (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 the monitoring systems 
and (if applicable) perform the Hg emission testing described in Sec. 
75.81(a) or Sec. 75.81(b) in each of the multiple stacks and determine 
Hg mass emissions from the affected unit as the sum of the Hg 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 Hg mass emissions from 
the units using that stack;
    (2) Install, certify, operate, and maintain the monitoring systems 
and (if applicable) perform the Hg emission testing described in Sec. 
75.81(a) or Sec. 75.81(b) in each of the ducts that feed into the 
stack, and determine Hg mass emissions from the affected unit using the 
sum of the Hg mass emissions measured at each duct, except that where 
another unit also exhausts flue gases to one or more of the stacks, the 
owner or operator shall also comply with the applicable requirements of 
paragraphs (a) and (b) of this section to determine and record Hg mass 
emissions from the units using that stack; or
    (3) If the monitoring option in paragraph (d)(1) or (d)(2) of this 
section is selected, and if heat input is required to be reported under 
the applicable State or Federal Hg mass emission reduction program that 
adopts the requirements of this subpart, the owner or operator shall:
    (i) Use the installed flow and diluent monitors to determine the 
hourly heat input rate at each stack or duct (mmBtu/hr), according to 
section 5.2 of appendix F to this part; and
    (ii) Calculate the hourly heat input at each stack or duct (in 
mmBtu) by multiplying the measured stack (or duct) heat input rate by 
the corresponding stack (or duct) operating time; and
    (iii) Determine the hourly unit heat input by summing the hourly 
stack (or duct) heat input values.

[70 FR 28684, May 18, 2005, as amended at; 73 FR 4362, Jan. 24, 2008]

[[Page 366]]



Sec. 75.83  Calculation of Hg mass emissions and heat input rate.

    The owner or operator shall calculate Hg mass emissions and heat 
input rate in accordance with the procedures in sections 9.1 through 9.3 
of appendix F to this part.



Sec. 75.84  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. 75.82(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 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. 75.80(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), (g) (if applicable), (h), and (i) or (j) 
(as applicable). For the information in Sec. 75.57(a)(2), replace the 
phrase ``the deadline in Sec. 75.4(a), (b) or (c)'' with the phrase 
``the applicable certification deadline under the State or Federal Hg 
mass emission reduction program'';
    (2) The information required in Sec. 75.58(b)(3), for units with 
flue gas desulfurization systems or add-on Hg emission controls;
    (3) For affected units using Hg CEMS or sorbent trap monitoring 
systems, for each hour when the unit is operating, record the Hg mass 
emissions, calculated in accordance with section 9 of appendix F to this 
part.
    (4) Heat input and Hg methodologies for the hour; and
    (5) Formulas from monitoring plan for total Hg mass emissions and 
heat input rate (if applicable);
    (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. 
75.82(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. 
75.82(b)(2)(ii). The monitoring plan shall contain sufficient 
information on the continuous monitoring systems and the use of data 
derived from these systems to demonstrate that all the unit's Hg 
emissions are monitored and reported.
    (2) Updates. Whenever the owner or operator makes a replacement, 
modification, or change in a certified continuous monitoring system 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. 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.
    (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 Hg 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. 75.82(b)(2)(ii):
    (i) Initial certification and recertification applications in 
accordance with Sec. 75.80(d);
    (ii) Monitoring plans in accordance with paragraph (e) of this 
section; and
    (iii) Quarterly reports in accordance with paragraph (f) of this 
section.

[[Page 367]]

    (3) Other petitions and communications. The designated 
representative for an affected unit shall submit petitions, 
correspondence, application forms, and petition-related test results in 
accordance with the provisions in Sec. 75.80(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. 75.82(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. 
75.82(b)(2)(ii).
    (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. 75.82(b)(2)(ii), as follows: No later 
than 21 days prior to the commencement of initial certification testing; 
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. 75.82(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 commencement of initial 
certification testing; 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. Electronic 
quarterly reports shall be submitted, beginning with the calendar 
quarter containing the compliance date in Sec. 75.80(b), unless 
otherwise specified in the final rule implementing a State or Federal Hg 
mass emissions reduction program that adopts the requirements of this 
subpart. The designated representative for an affected unit shall report 
the data and information in this paragraph (f)(1) and the applicable 
compliance certification information in paragraph (f)(2) of this section 
to the Administrator quarterly, except as otherwise provided in Sec. 
75.64(a) for units in long-term cold storage. 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 date of 
report generation and the following information for each affected unit 
or group of units monitored at a common stack:
    (i) The facility information in Sec. 75.64(a)(3); and
    (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 flue gas desulfurization systems or with add-on 
Hg emission controls, the parametric information in Sec. 75.58(b)(3);

[[Page 368]]

    (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) Stratification test results required as part of the RATA 
supplementary records under Sec. 75.59(a)(7);
    (H) 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;
    (I) 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.
    (J) For units using sorbent trap monitoring systems, the hourly gas 
flow meter readings taken between the initial and final meter readings 
for the data collection period; and
    (iii) Ounces of Hg emitted during quarter and cumulative ounces of 
Hg emitted in the year-to-date (rounded to the nearest thousandth); and
    (iv) Unit or stack operating hours for quarter, cumulative unit or 
stack operating hours for year-to-date; and
    (v) Reporting period heat input (if applicable) and cumulative, 
year-to-date heat input.
    (2) Compliance certification. (i) The designated representative 
shall certify that the monitoring plan information in each quarterly 
electronic report (i.e., component and system identification codes, 
formulas, etc.) represent current operating conditions for the affected 
unit(s)
    (ii) 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:
    (A) The monitoring data submitted were recorded in accordance with 
the applicable requirements of this part, including the quality 
assurance procedures and specifications; and
    (B) With regard to a unit with an FGD system or with add-on Hg 
emission controls, that for all hours where data are substituted in 
accordance with Sec. 75.38(b), the add-on emission controls were 
operating within the range of parameters listed in the quality-assurance 
plan for the unit (or that quality-assured SO2 CEMS data were 
available to document proper operation of the emission controls), and 
that the substitute values do not systematically underestimate Hg 
emissions.
    (3) Additional reporting requirements. The designated representative 
shall also comply with all of the quarterly reporting requirements in 
Sec. Sec. 75.64(d), (f), and (g).

[70 FR 28684, May 18, 2005, as amended at 72 FR 51528, Sept. 7, 2007; 73 
FR 4363, Jan. 24, 2008]

[[Page 369]]



     Sec. Appendix A to Part 75--Specifications and Test Procedures

                1. Installation and Measurement Location

                         1.1 Gas and Hg Monitors

    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, and NOX 
concentration monitoring system or NOX-diluent CEMS 
(NOX pollutant concentration monitor and diluent gas 
monitor), Hg concentration monitoring system, or sorbent trap monitoring 
system will pass the relative accuracy test (see section 6 of this 
appendix).
    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 
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

[[Page 370]]

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 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


[[Page 371]]


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 D3177-02 (Reapproved 2007), Standard Test Methods for 
Total Sulfur in the Analysis Sample of Coal and Coke; ASTM D4239-02, 
Standard Test Methods for Sulfur in the Analysis Sample of Coal and Coke 
Using High-Temperature Tube Furnace Combustion Methods; ASTM D4294-98, 
Standard Test Method for Sulfur in Petroleum and Petroleum Products by 
Energy-Dispersive X-ray Fluorescence Spectrometry; ASTM D1552-01, 
Standard Test Method for Sulfur in Petroleum Products (High-Temperature 
Method); ASTM D129-00, Standard Test Method for Sulfur in Petroleum 
Products (General Bomb Method); ASTM D2622-98, Standard Test Method for 
Sulfur in Petroleum Products by Wavelength Dispersive X-ray Fluorescence 
Spectrometry, for sulfur content of solid or liquid fuels; ASTM D3176-89 
(Reapproved 2002), Standard Practice for Ultimate Analysis of Coal and 
Coke; ASTM D240-00, Standard Test Method for Heat of Combustion of 
Liquid Hydrocarbon Fuels by Bomb Calorimeter; or ASTM D5865-01a, 
Standard Test Method for Gross Calorific Value of Coal and Coke (all 
incorporated by reference under Sec. 75.6 of this part).

                 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-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

[[Page 372]]

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.
    (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

[[Page 373]]

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 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.

[[Page 374]]

    (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 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

[[Page 375]]

    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.

  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.


[[Page 376]]

[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: 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

[[Page 377]]

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 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

[[Page 378]]

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 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

[[Page 379]]

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

    * * * 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 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 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

[[Page 380]]

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 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

[[Page 381]]

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 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

[[Page 382]]

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.

                            2.1.7 Hg Monitors

    Determine the appropriate span and range value(s) for each Hg 
pollutant concentration monitor, so that all expected Hg concentrations 
can be determined accurately.

                 2.1.7.1 Maximum Potential Concentration

    (a) The maximum potential concentration depends upon the type of 
coal combusted in the unit. For the initial MPC determination, there are 
three options:
    (1) Use one of the following default values: 9 [micro]gm/scm for 
bituminous coal; 10 [micro]gm/scm for sub-bituminous coal; 16 [micro]gm/
scm for lignite, and 1 [micro]gm/scm for waste coal, i.e., anthracite 
culm or bituminous gob. If different coals are blended, use the highest 
MPC for any fuel in the blend; or
    (2) You may base the MPC on the results of site-specific emission 
testing using the one of the Hg reference methods in Sec. 75.22, if the 
unit does not have add-on Hg emission controls or a flue gas 
desulfurization system, or if you test upstream of these control 
devices. A minimum of 3 test runs are required, at the normal operating 
load. Use the highest total Hg concentration obtained in any of the 
tests as the MPC; or
    (3) You may base the MPC on 720 or more hours of historical CEMS 
data or data from a sorbent trap monitoring system, if the unit does not 
have add-on Hg emission controls or a flue gas desulfurization system 
(or if the CEMS or sorbent trap system is located upstream of these 
control devices) and if the Hg CEMS or sorbent trap system has been 
tested for relative accuracy against one of the Hg reference methods in 
Sec. 75.22 and has met a relative accuracy specification of 20.0% or 
less.
    (b) For the purposes of missing data substitution, the fuel-specific 
or site-specific MPC values defined in paragraph (a) of this section 
apply to units using sorbent trap monitoring systems.

                 2.1.7.2 Maximum Expected Concentration

    For units with FGD systems that significantly reduce Hg emissions 
(including fluidized bed units that use limestone injection) and for 
units equipped with add-on Hg emission controls (e.g., carbon 
injection), determine the maximum expected Hg concentration (MEC) during 
normal, stable operation of the unit and emission controls. To calculate 
the MEC, substitute the MPC value from section 2.1.7.1 of this appendix 
into Equation A-2 in section 2.1.1.2 of this appendix. For units with 
add-on Hg emission controls, base the percent removal efficiency on 
design engineering calculations. For units with FGD systems, use the 
best available estimate of the Hg removal efficiency of the FGD system.

                     2.1.7.3 Span and Range Value(s)

    (a) For each Hg monitor, determine a high span value, by rounding 
the MPC value from section 2.1.7.1 of this appendix upward to the next 
highest multiple of 10 [micro]gm/scm.
    (b) For an affected unit equipped with an FGD system or a unit with 
add-on Hg emission controls, if the MEC value from section 2.1.7.2 of 
this appendix is less than 20 percent of the high span value from 
paragraph (a) of this section, and if the high span value is 20 
[micro]gm/scm or greater, define a second, low span value of 10 
[micro]gm/scm.
    (c) If only a high span value is required, set the full-scale range 
of the Hg analyzer to be greater than or equal to the span value.
    (d) If two span values are required, you may either:
    (1) Use two separate (high and low) measurement scales, setting the 
range of each scale to be greater than or equal to the high or low span 
value, as appropriate; or
    (2) Quality-assure two segments of a single measurement scale.

                  2.1.7.4 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 Hg monitor (at a minimum, an annual evaluation is required) and 
shall make any necessary span and range adjustments, with corresponding 
monitoring plan updates. 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, 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

[[Page 383]]

that up to 90 days after the end of that quarter may be taken to 
implement a span adjustment if the calibration gas concentrations 
currently being used for calibration error tests, system integrity 
checks, and linearity checks are unsuitable for use with the new span 
value and new calibration materials must be ordered.
    (a) The guidelines of section 2.1 of this appendix do not apply to 
Hg monitoring systems.
    (b) Whenever a full-scale range exceedance occurs during a quarter 
and is not caused by a monitor out-of-control period, proceed as 
follows:
    (1) For monitors with a single measurement scale, report 200 percent 
of the full-scale range as the hourly Hg concentration until the 
readings come back on-scale and if appropriate, make adjustments to the 
MPC, span, and range to prevent future full-scale exceedances; or
    (2) For units with two separate measurement scales, if the low range 
is exceeded, no further action is required, provided that the high range 
is available and is not out-of-control or out-of-service for any reason. 
However, if 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 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 Hg monitor, 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 gas 
concentrations currently being used for calibration error tests, system 
integrity checks and linearity checks are unsuitable for use with the 
new span value, then a diagnostic linearity or 3-level system integrity 
check using the new calibration gas concentrations 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.

                 2.2 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

[[Page 384]]

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.

                         2.2.3 Mercury Monitors.

    Design and equip each mercury monitor to permit the introduction of 
known concentrations of elemental Hg and HgCl2 separately, at 
a point immediately preceding the sample extraction filtration system, 
such that the entire measurement system can be checked. If the Hg 
monitor does not have a converter, the HgCl2 injection 
capability is not required.

                      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 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.
    (c) The calibration error of a Hg concentration monitor shall not 
deviate from the reference value of either the zero or upscale 
calibration gas by more than 5.0 percent of the span value, as 
calculated using Equation A-5 of this appendix. Alternatively, if the 
span value is 10 [micro]gm/scm, the calibration error test results are 
also acceptable if the absolute value of the difference between the 
monitor response value and the reference value, [bond]R-A[bond] in 
Equation A-5 of this appendix, is <= 1.0 [micro]gm/scm.

                           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) For the linearity check and the 3-level system integrity check 
of an Hg monitor, which are required, respectively, under Sec. 
75.20(c)(1)(ii) and (c)(1)(vi), the measurement error shall not exceed 
10.0 percent of the reference value at any of the three gas levels. To 
calculate the measurement error at each level, take the absolute value 
of the difference between the reference value and mean CEM response, 
divide the result by the reference value, and then multiply by 100. 
Alternatively, the results at any gas level are acceptable if the 
absolute value of the difference between the average monitor response 
and the average reference value, i.e., [verbar]R-A[verbar] in Equation 
A-4 of this appendix, does not exceed 0.8 [micro]g/m\3\. The principal 
and alternative performance specifications in this section also apply to 
the single-level system integrity check described in section 2.6 of 
appendix B to this part.

[[Page 385]]

                          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 (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.

            3.3.8 Relative Accuracy for Hg Monitoring Systems

    The relative accuracy of a Hg concentration monitoring system or a 
sorbent trap monitoring system shall not exceed 20.0 percent. 
Alternatively, for affected units where the average of the reference 
method measurements of Hg concentration during the relative accuracy 
test audit is less than 5.0 [micro]gm/scm, the test results are 
acceptable if the difference between the mean value of the monitor 
measurements and the reference method mean value does not exceed 1.0 
[micro]gm/scm, in cases where the relative accuracy specification of 
20.0 percent 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

[[Page 386]]

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.

                       3.4.3 Hg Monitoring Systems

    Mercury concentration monitoring systems and sorbent trap monitoring 
systems shall not be biased low as determined by the test procedure in 
section 7.6 of this appendix.

                             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

    Automated data acquisition and handling systems shall read and 
record the full range of pollutant concentrations and volumetric flow 
from zero through span and provide a continuous, permanent record of all 
measurements and required information as an ASCII flat file capable of 
transmission both by direct computer-to-computer electronic transfer via 
modem and EPA-provided software and by an IBM-compatible personal 
computer diskette. 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, a 
moisture monitoring system, a Hg concentration monitoring system, and a 
sorbent trap 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, ounces/hr, tons/hr).
    Data acquisition and handling systems shall also compute and record 
monitor calibration error; any bias adjustments to SO2, 
NOX, and Hg pollutant concentration data, flow rate data, Hg 
emission rate data, or NOX emission rate data; and all 
missing data procedure statistics specified in subpart D of this part.
    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 as an ASCII flat file capable of transmission both 
by direct computer-to-computer electronic transfer via modem and EPA-
provided software and by an IBM-compatible personal computer diskette.

                           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 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, EPA-600/R-97/121 or such revised procedure as

[[Page 387]]

approved by the Administrator (EPA Traceability Protocol).
    (b) An EPA Protocol Gas must have a specialty gas producer-certified 
uncertainty (95-percent confidence interval) that must not be greater 
than 2.0 percent 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.
    (c) On and after January 1, 2009, a specialty gas producer 
advertising calibration gas certification with the EPA Traceability 
Protocol or distributing calibration gases as ``EPA Protocol Gas'' must 
participate in the EPA Protocol Gas Verification Program (PGVP) 
described in Section 2.1.10 of the EPA Traceability Protocol or it 
cannot use ``EPA'' in any form of advertising for these products, unless 
approved by the Administrator. A specialty gas producer not 
participating in the PGVP may not certify a calibration gas as an EPA 
Protocol Gas, unless approved by the Administrator.
    (d) A copy of EPA-600/R-97/121 is available from the National 
Technical Information Service, 5285 Port Royal Road, Springfield, VA, 
703-605-6585 or http://www.ntis.gov, and from http://www.epa.gov/ttn/
emc/news.html or http://www.epa.gov/appcdwww/tsb/index.html.

                       5.1.5 Research Gas Mixtures

    Research gas mixtures must be vendor-certified to be within 2.0 
percent of the concentration specified on the cylinder label (tag 
value), using the uncertainty calculation procedure in section 2.1.8 of 
the ``EPA Traceability Protocol for Assay and Certification of Gaseous 
Calibration Standards,'' September 1997, EPA-600/R-97/121. 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.

                        5.1.9 Mercury Standards.

    For 7-day calibration error tests of Hg concentration monitors and 
for daily calibration error tests of Hg monitors, either NIST-traceable 
elemental Hg standards (as defined in Sec. 72.2 of this chapter) or a 
NIST-traceable source of oxidized Hg (as defined in Sec. 72.2 of this 
chapter) may be used. For linearity checks, NIST-traceable elemental Hg 
standards shall be used. For 3-level and single-point system integrity 
checks under Sec. 75.20(c)(1)(vi), sections 6.2(g) and 6.3.1 of this 
appendix, and sections 2.1.1, 2.2.1 and 2.6 of appendix B to this part, 
a NIST-traceable source of oxidized Hg shall be used. Alternatively, 
other NIST-traceable standards may be used for the required checks, 
subject to the approval of the Administrator. Notwithstanding these 
requirements, Hg calibration standards that are not NIST-traceable may 
be used for the tests described in this section until December 31, 2009. 
However, on and after January 1, 2010, only NIST-traceable calibration 
standards shall be used for these tests.

                           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-

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consecutive days. To the extent practicable, test the DAHS software 
prior to testing the monitoring hardware.

           6.1.2 Requirements for Air Emission Testing Bodies

    (a) On and after January 1, 2009, any Air Emission Testing Body 
(AETB) conducting relative accuracy test audits of CEMS and sorbent trap 
monitoring systems under this part must conform to the requirements of 
ASTM D7036-04 (incorporated by reference under Sec. 75.6 of this part). 
This section is not applicable to daily operation, daily calibration 
error checks, daily flow interference checks, quarterly linearity checks 
or routine maintenance of CEMS.
    (b) The AETB shall provide to the affected source(s) certification 
that the AETB operates in conformance with, and that data submitted to 
the Agency has been collected in accordance with, the requirements of 
ASTM D7036-04 (incorporated by reference under Sec. 75.6 of this part). 
This certification may be provided in the form of:
    (1) A certificate of accreditation of relevant scope issued by a 
recognized, national accreditation body; or
    (2) A letter of certification signed by a member of the senior 
management staff of the AETB.
    (c) The AETB shall either provide a Qualified Individual on-site to 
conduct or shall oversee all relative accuracy testing carried out by 
the AETB as required in ASTM D7036-04 (incorporated by reference under 
Sec. 75.6 of this part). The Qualified Individual shall provide the 
affected source(s) with copies of the qualification credentials relevant 
to the scope of the testing conducted.

                6.2 Linearity Check (General Procedures)

    Check the linearity of each SO2, NOX, 
CO2, Hg, 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 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).

[[Page 389]]

    (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.
    (g) For Hg monitors, follow the guidelines in section 2.2.3 of this 
appendix in addition to the applicable procedures in section 6.2 when 
performing the system integrity checks described in Sec. 
75.20(c)(1)(vi) and in sections 2.1.1, 2.2.1 and 2.6 of appendix B to 
this part.
    (h) For Hg concentration monitors, if moisture is added to the 
calibration gas during the required linearity checks or system integrity 
checks, the moisture content of the calibration gas must be accounted 
for. Under these circumstances, the dry basis concentration of the 
calibration gas shall be used to calculate the linearity error or 
measurement error (as applicable).

                    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, each Hg 
concentration 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. For Hg monitors, you may perform this test 
using either elemental Hg standards or a NIST-traceable source of 
oxidized Hg. Also for Hg monitors, if moisture is added to the 
calibration gas, the added moisture must be accounted for and the dry-
basis concentration of the calibration gas shall be used to calculate 
the calibration error. (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 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 non-consecutive 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. 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

[[Page 390]]

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, 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. For Hg monitors, the calibration gas used for this test may 
either be the elemental or oxidized form of Hg. 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

[[Page 391]]

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, 0.5 [micro]g/m\3\ (for 
Hg), 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 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, each Hg concentration 
monitoring system, each sorbent trap monitoring system, 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 or add-on Hg 
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

[[Page 392]]

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). Notwithstanding this requirement, up to 336 
consecutive unit or stack operating hours may be taken to complete the 
RATA of a Hg monitoring system, when ASTM 6784-02 (incorporated by 
reference under Sec. 75.6 of this part) or Method 29 in appendix A-8 to 
part 60 of this chapter is used as the reference method. 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, each NOX-diluent CEMS, each Hg 
concentration monitoring system, and each sorbent trap monitoring 
system, 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, each NOX-diluent CEMS, each NOX 
concentration monitoring system used to determine NOX mass 
emissions, as defined in Sec. 75.71(a)(2), each Hg concentration 
monitoring system, and each sorbent trap monitoring system 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 level.
    (b) For the initial certification of a gas or Hg 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

[[Page 393]]

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 ``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

[[Page 394]]

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.

               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

[[Page 395]]

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.
    (c) For Hg monitoring systems, use the same basic approach for 
traverse point selection that is used for the other gas monitoring 
system RATAs, except that the stratification test provisions in sections 
8.1.3 through 8.1.3.5 of Method 30A shall apply, rather than the 
provisions of sections 6.5.6.1 through 6.5.6.3 of this appendix.

                       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 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.

[[Page 396]]

    (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 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, Hg, 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 may be made either sequentially from port 
to port or simultaneously at 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 reference 
method). For moisture monitoring systems, an appropriate coefficient, 
``K'' factor or other suitable mathematical algorithm may be developed 
prior to the RATA,

[[Page 397]]

to adjust the monitoring system readings with respect to the reference 
method. 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 75.59(a)(5)(vii). Whenever the coefficient, K factor or algorithm is 
changed, a RATA of the moisture monitoring system is required. For the 
RATA of a Hg CEMS using the Ontario Hydro Method, or for the RATA of a 
sorbent trap system (irrespective of the reference method used), the 
time per run must be long enough to collect a sufficient mass of Hg to 
analyze. For the RATA of a sorbent trap monitoring system, the type of 
sorbent material used by the traps shall be the same as for daily 
operation of the monitoring system; however, the size of the traps used 
for the RATA may be smaller than the traps used for daily operation of 
the system. Spike the third section of each sorbent trap with elemental 
Hg, as described in section 7.1.2 of appendix K to this part. Install a 
new pair of sorbent traps prior to each test run. For each run, the 
sorbent trap data shall be validated according to the quality assurance 
criteria in section 8 of appendix K to this part.
    (b) To properly correlate individual SO2, Hg, or 
NOX CEMS data (in lb/MMBtu) and volumetric flow rate data 
with the 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 
or have been published by ASTM, 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 
appendices A-1 and A-2 to part 60 of this chapter or its allowable 
alternatives in appendix A 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; Methods 7, 7A, 7C, 7D or 7E in appendix A-4 to part 60 
of this chapter for NOX, excluding the exceptions of Method 
7E in appendix A-4 to part 60 of this chapter identified in Sec. 
75.22(a)(5); and for Hg, either ASTM D6784-02 (the Ontario Hydro Method) 
(incorporated by reference under Sec. 75.6 of this part), Method 29 in 
appendix A-8 to part 60 of this chapter, Method 30A, or Method 30B When 
using Method 7E in appendix A-4 to part 60 of this chapter for measuring 
NOX concentration, total NOX, both NO and 
NO2, must be measured.

                             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.

[[Page 398]]

[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, Hg 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 
only for heat input rate determination, NOX concentration 
monitoring systems used to determine NOX mass emissions under 
subpart H of this part, Hg monitoring systems used to determine Hg mass 
emissions under subpart I of this part, and flow monitors using the 
following procedures. 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, d, of a data set 
as follows.
[GRAPHIC] [TIFF OMITTED] TR12JN02.010

(Eq. A-7)

where,

n = Number of data points.

n
[Sigma] di = Algebraic sum of the
i=1 individual differences di.

di = The difference between a reference method value and the 
corresponding continuous emission monitoring system value 
(RMi-CEMi) at a given point in time i.

                        7.3.2 Standard Deviation

    Calculate the standard deviation, Sd, of a data set as 
follows:

[[Page 399]]

[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 Sec. 75.71(a)(2); 
NOX-diluent CEMS, Hg concentration monitoring systems, and 
sorbent trap monitoring systems, 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 difference, d, of the data set 
using equation A-7 of this appendix. To calculate bias for an 
SO2 or NOX pollutant concentration monitor, ``d'' 
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, ``d'' 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, ``d'' is, for each paired data point, the 
difference between the NOX-diluent emission rate values (in 
lb/

[[Page 400]]

mmBtu) obtained from the reference method and the monitoring system. To 
calculate bias for a Hg monitoring system when using the Ontario Hydro 
Method or Method 29 in appendix A-8 to part 60 of this chapter, ``d'' 
is, for each data point, the difference between the average Hg 
concentration value (in [micro]g/m\3\) from the paired Ontario Hydro or 
Method 29 in appendix A-8 to part 60 of this chapter sampling trains and 
the concentration measured by the monitoring system. For sorbent trap 
monitoring systems, use the average Hg concentration measured by the 
paired traps in the calculation of ``d''.

                        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.
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, 
NOX-diluent monitoring systems, Hg concentration monitoring 
systems, and sorbent trap 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. Similarly, for Hg concentration and sorbent trap 
monitoring systems, where the average Hg concentration during the RATA 
is < 5.0 [micro]gm/dscm, if the monitoring system meets the normal or 
the alternative relative accuracy specification in section 3.3.8 of this 
appendix but fails the bias test, the owner or operator may either use 
the bias adjustment factor (BAF) calculated from Equation A-12 or may 
use a default BAF of 1.250 for reporting purposes under this part.
    (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

[[Page 401]]

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 or Hg, 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, or when using a Hg concentration or sorbent trap 
monitoring system and a flow monitor to calculate Hg mass emissions 
under subpart I of this part, use bias-adjusted values for 
NOX (or Hg) concentration and flow rate in the mass emission 
calculations and use bias-adjusted NOX (or Hg) concentrations 
to compute the appropriate substitution values for NOX (or 
Hg) 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 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:

[[Page 402]]

[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.

                                                  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:
 
--------------------------------------------------------------------------------------------------------------------------------------------------------
 
--------------------------------------------------------------------------------------------------------------------------------------------------------
 
--------------------------------------------------------------------------------------------------------------------------------------------------------

[[Page 403]]

 
 
--------------------------------------------------------------------------------------------------------------------------------------------------------
 
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                           .................
--------------------------------------------------------------------------------------------------------------------------------------------------------


           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......................
----------------------------------------------------------------------------------------------------------------
 
 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..........................................
--------------------------------------------------------------------------------------------------------------------------------------------------------

[[Page 404]]

 
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.............
----------------------------------------------------------------------------------------------------------------
 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

[[Page 405]]

[GRAPHIC] [TIFF OMITTED] TR24JA08.000

[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

[[Page 406]]

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.

[58 FR 3701, Jan. 11, 1993, as amended at 60 FR 26541-26546, 26569-
26570, May 17, 1995; 61 FR 25582, May 22, 1996; 61 FR 59162, Nov. 20, 
1996; 63 FR 57512, Oct. 27, 1998; 64 FR 28631-28643, May 26, 1999; 64 FR 
37582, July 12, 1999; 67 FR 40448, 40449, 40452, 40453, 40455, June 12, 
2002; 67 FR 53505, Aug. 16, 2002; 70 FR 28690, May 18, 2005; 72 FR 
51528, Sept. 7, 2007; 73 FR 4363, Jan. 24, 2008]



   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.

               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 requirements in section 6.1.2 of appendix A to this part shall 
     be met by any Air Emissions Testing Body (AETB) performing the 
 semiannual/annual RATAs described in section 2.3 of this appendix and 
 the Hg emission tests described in Sec. Sec. 75.81(c) and 75.81(d)(4).

  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

[[Page 407]]

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.

    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.

[[Page 408]]

    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.

          1.5 Requirements for Sorbent Trap Monitoring Systems

             1.5.1 Sorbent Trap Identification and Tracking

    Include procedures for inscribing or otherwise permanently marking a 
unique identification number on each sorbent trap, for tracking 
purposes. Keep records of the ID of the monitoring system in which each 
sorbent trap is used, and the dates and hours of each Hg collection 
period.

           1.5.2 Monitoring System Integrity and Data Quality

    Explain the procedures used to perform the leak checks when sorbent 
traps are placed in service and removed from service. Also explain the 
other QA procedures used to ensure system integrity and data quality, 
including, but not limited to, gas flow meter calibrations, verification 
of moisture removal, and ensuring air-tight pump operation. In addition, 
the QA plan must include the data acceptance and quality control 
criteria in section 8 of appendix K to this part. All reference meters 
used to calibrate the gas flow meters (e.g., wet test meters) shall be 
periodically recalibrated. Annual, or more frequent, recalibration is 
recommended. If a NIST-traceable calibration device is used as a 
reference flow meter, the QA plan must include a protocol for ongoing 
maintenance and periodic recalibration to maintain the accuracy and 
NIST-traceability of the calibrator.

                            1.5.3 Hg Analysis

    Explain the chain of custody employed in packing, transporting, and 
analyzing the sorbent traps (see sections 7.2.8 and 7.2.9 in appendix K 
to this part). Keep records of all Hg analyses. The analyses shall be 
performed in accordance with the procedures described in section 10 of 
appendix K to this part.

                     1.5.4 Laboratory Certification

    The QA Plan shall include documentation that the laboratory 
performing the analyses on the carbon sorbent traps is certified by the 
International Organization for Standardization (ISO) to have a 
proficiency that meets the requirements of ISO 17025. Alternatively, if 
the laboratory performs the spike recovery study described in section 
10.3 of appendix K to this part and repeats that procedure annually, ISO 
certification is not required.

                      1.5.5 Data Collection Period

    State, and provide the rationale for, the minimum acceptable data 
collection period (e.g., one day, one week, etc.) for the size of 
sorbent trap selected for the monitoring. Include in the discussion such 
factors as the Hg concentration in the stack gas, the capacity of the 
sorbent trap, and the minimum mass of Hg required for the analysis.

              1.5.6 Relative Accuracy Test Audit Procedures

    Keep records of the procedures and details peculiar to the sorbent 
trap monitoring systems that are to be followed 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

[[Page 409]]

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'').
    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

[[Page 410]]

monitors used to measure CO2 emissions or percent moisture) 
exceeds 1.0 percent CO2 or O2, or when the 
calibration error of a flow monitor or a moisture sensor 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 be considered out-of-control if [bond]R-
A[bond], 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 
[bond]RA[bond] in Equation A-6 does not exceed 5.0 ppm (for span values 
<= 50 ppm), or if [bond]R-A[bond] does not exceed 10.0 ppm (for span 
values  50 ppm, but <= 200 ppm). For a Hg monitor, an out-of-
control period occurs when the calibration error exceeds 5.0% of the 
span value. Notwithstanding, the Hg monitor shall not be considered out-
of-control if [bond]R-A[bond] in Equation A-6 does not exceed 1.0 
[micro]gm/scm. 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.

    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

[[Page 411]]

(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.
    (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, Hg, 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 Hg 
monitors, perform the linearity checks using elemental Hg standards. 
Alternatively, you may perform 3-level system integrity checks at the 
same three calibration gas levels (i.e., low, mid, and high), using a 
NIST-traceable source of oxidized Hg. If you choose this option, the 
performance specification in section 3.2(c)(3) of appendix A to this 
part must be met at each gas level. 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

[[Page 412]]

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 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.

               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 413]]

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 414]]

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 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

[[Page 415]]

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. 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

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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 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

[[Page 417]]

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 for Hg monitoring systems and 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, NOX-
diluent CEMS, or SO2-diluent CEMS. For each primary and 
redundant backup Hg concentration monitoring system and each sorbent 
trap monitoring system, RATAs shall be performed annually, i.e., once 
every four successive QA operating quarters (as defined in Sec. 72.2 of 
this chapter). 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

[[Page 418]]

(including O2 monitors used to determine CO2 
emissions), CO2 or O2 diluent monitors used to 
determine heat input, NOX concentration monitoring systems, 
Hg concentration monitoring systems, sorbent trap monitoring systems, 
moisture 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-

[[Page 419]]

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 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. Notwithstanding these requirements, when ASTM 
D6784-02 (incorporated by reference under Sec. 75.6 of this part) or 
Method 29 in appendix A-8 to part 60 of this chapter is used as the 
reference method for the RATA of a Hg CEMS, if a calibration error test 
of the CEMS is failed during a RATA test period, any test run(s) 
completed prior to the failed calibration error test need not be 
repeated; however, the RATA may not continue until a subsequent 
calibration error test of the Hg CEMS has been passed. 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 re-
linearization of the monitor is required 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

[[Page 420]]

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 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, a Hg concentration 
monitoring system, a sorbent trap 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, Hg, 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.

                         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

[[Page 421]]

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 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, flow 
monitor, NOX CEMS, NOX concentration monitoring 
system used to calculate NOX mass emissions, Hg concentration 
monitoring system, or sorbent trap monitoring system 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 to 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

[[Page 422]]

(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 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.

               2.6 System Integrity Checks for Hg Monitors

    For each Hg concentration monitoring system (except for a Hg monitor 
that does not have a converter), perform a single-point system integrity 
check weekly, i.e., at least once every 168 unit or stack operating 
hours, using a NIST-traceable source of oxidized Hg. Perform this check 
using a mid- or high-level gas concentration, as defined in section 5.2 
of appendix A to this part. The performance specifications in paragraph 
(3) of section 3.2 of appendix A to this part must be met, otherwise the 
monitoring system is considered out-of-control, from the hour of the 
failed check until a subsequent system integrity check is passed. If a 
required system integrity check is not performed and passed within 168 
unit or stack operating hours of last successful check, the monitoring 
system shall also be considered out of control, beginning with the 169th 
unit or stack operating hour after the last successful check, and 
continuing until a subsequent system integrity check is passed. This 
weekly check is not required if the daily calibration assessments in 
section 2.1.1 of this appendix are performed using a NIST-traceable 
source of oxidized Hg.

[[Page 423]]



                                         Figure 1 to Appendix B of Part 75--Quality Assurance Test Requirements
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                                            Basic QA test frequency requirements *
                Test                --------------------------------------------------------------------------------------------------------------------
                                             Daily *                 Weekly               Quarterly *            Semiannual *              Annual
--------------------------------------------------------------------------------------------------------------------------------------------------------
Calibration Error Test (2 pt.).....  ...............  ......................  .....................  .....................
Interference Check (flow)..........  ...............  ......................  .....................  .....................
Flow-to-Load Ratio.................  ......................  ......................  ..............  .....................
Leak Check (DP flow monitors)......  ......................  ......................  ..............  .....................
Linearity Check or System Integrity  ......................  ......................  ..............  .....................
 Check ** (3 pt.).
Single-point System Integrity Check  ......................  ...............  .....................  .....................
 **.
RATA (SO2, NOX, CO2, O2, H2O) \1\..  ......................  ......................  .....................  ..............
RATA (All Hg monitoring systems)...  ......................  ......................  .....................  .....................  
RATA (flow) 1 2....................  ......................  ......................  .....................   .............
--------------------------------------------------------------------------------------------------------------------------------------------------------
* ``Daily'' means operating days, only. ``Weekly'' means once every 168 unit or stack operating hours. ``Quarterly'' means once every QA operating
  quarter. ``Semiannual'' means once every two QA operating quarters. ``Annual'' means once every four QA operating quarters.
** The system integrity check applies only to Hg monitors with converters. The single-point weekly system integrity check is not required if daily
  calibrations are performed using a NIST-traceable source of oxidized Hg. The 3-point quarterly system integrity check is not required if a linearity
  check is performed.
\1\ Conduct RATA annually (i.e., once every four QA operating quarters), 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 calendar years and whenever a flow
  monitor is re-linearized, 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.


[[Page 424]]


   Figure 2 to Appendix B of Part 75--Relative Accuracy Test Frequency
                            Incentive System
------------------------------------------------------------------------
                                  Semiannual W
            RATA                    (percent)             Annual W
------------------------------------------------------------------------
SO2 or NOXY.................  7.5% 12.
                               eq>15.0 ppm X.        0 ppm X.
SO2-diluent.................  7.5% 0.0
                               eq>0.030 lb/mmBtu X.  25 lb/mmBtu =G5X.
NOX-diluent.................  7.5% 0.
                               eq>0.020 lb/mmBtu X.  015 lb/mmBtu X.
Flow........................  7.5% < RA <= 10.0%    RA <= 7.5% or 1.5
                               thn-eq>2.0 fps X.     fps X.
CO2 or O2...................  7.5% < RA <= 10.0%    RA <= 7.5% or 0.7
                               thn-eq>1.0% CO2/O2    % CO2/O2X.
                               X.
Hg X........................  N/A.................  RA < 20.0% or 
                                                     1.0 [micro]g/scm X.
Moisture....................  7.5% 1.0
                               eq>1.5% H2O X.        % H2O X.
------------------------------------------------------------------------
W The deadline for the next RATA is the end of the second (if
  semiannual) or fourth (if annual) successive QA operating quarter
  following the quarter in which the CEMS was last tested. Exclude
  calendar quarters with fewer than 168 unit operating hours (or, for
  common stacks and bypass stacks, exclude quarters with fewer than 168
  stack operating hours) in determining the RATA deadline. For SO2
  monitors, QA operating quarters in which only very low sulfur fuel as
  defined in Sec. 72.2, is combusted may also be excluded. However,
  the exclusion of calendar quarters is limited as follows: the deadline
  for the next RATA shall be no more than 8 calendar quarters after the
  quarter in which a RATA was last performed.
X The difference between monitor and reference method mean values
  applies to moisture monitors, CO2, and O2 monitors, low emitters of
  SO2, NOX, or Hg, or and low flow, only. The specifications for Hg
  monitors also apply to sorbent trap monitoring systems.
Y A NOX concentration monitoring system used to determine NOX mass
  emissions under Sec. 75.71.


[58 FR 3701, Jan. 11, 1993, as amended at 60 FR 26546, 26571, May 17, 
1995; 61 FR 59165, Nov. 20, 1996; 64 FR 28644, May 26, 1999; 64 FR 
37582, July 12, 1999; 67 FR 40456, 40457, June 12, 2002; 67 FR 53505, 
Aug. 16, 2002; 67 FR 57274, Sept. 9, 2002; 70 FR 28693, May 18, 2005; 72 
FR 51528, Sept. 7, 2007; 73 FR 4367, Jan. 24, 2008]



     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.

[[Page 425]]

    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 ( 
[deg]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 ( [deg]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).

              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.

[[Page 426]]

                             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 ([deg]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.

      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.

[[Page 427]]

    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 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.

[[Page 428]]

    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 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

[[Page 429]]

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 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-

[[Page 430]]

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, 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,
    (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\:------------

[[Page 431]]

 
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 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

[[Page 432]]

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.

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 ([deg]), inches of water (in H2O), pounds
  per square inch (psi), or milliamperes (ma) for both transmitter or transducer readings and reference
  readings).


[[Page 433]]

    (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 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

[[Page 434]]

(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 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


[[Page 435]]


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.

    (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.

[[Page 436]]

    (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, 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.

[[Page 437]]

    (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 438]]

[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 439]]

[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 440]]

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 441]]

    (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, Standard 
Test Method for Heat of Combustion of Liquid Hydrocarbon Fuels by Bomb 
Calorimeter, ASTM D4809-00, Standard Test Method for Heat of Combustion 
of Liquid Hydrocarbon Fuels by Bomb Calorimeter (Precision Method), or 
ASTM D5865-01a, Standard Test Method for Gross Calorific Value of Coal 
and Coke (all incorporated by reference under Sec. 75.6 of this part) 
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

[[Page 442]]

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.
[GRAPHIC] [TIFF OMITTED] TR12JN02.014


[[Page 443]]


[GRAPHIC] [TIFF OMITTED] TR12JN02.015


[[Page 444]]


[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 445]]

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 446]]

                  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 447]]

    (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 448]]

    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 449]]

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 450]]

               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 451]]

                      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 452]]

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 453]]

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 454]]


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 455]]

[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 456]]


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 28652-28663, 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]

    Editor's Note: At 67 FR 53505, Aug. 16, 2002, section 2.4.1 Table D-
6 was amended. However, this table is a photograph and the amendments 
could not be incorporated.

[[Page 457]]



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 be met by any Air Emissions Testing Body 
(AETB) performing 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 combination of fuels (and, optionally, for each combination 
of fuels), measure the NOX and O2 concentrations 
at each sampling

[[Page 458]]

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 [deg]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 unit while combusting each type of fuel 
(or fuel mixture) for which a NOX emission rate versus heat 
input rate correlation curve was

[[Page 459]]

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 this appendix. Record the heat input 
rate for each fuel to the nearest 0.1 mmBtu/hr. During partial unit 
operating hours or during

[[Page 460]]

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 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

[[Page 461]]

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.

                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

[[Page 462]]

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 26551-26553, 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]



            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 x10-7 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 = 1.660x10-7 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 463]]

[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=1.194x10-7 (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\
------------------------------------------------------------------------
                                                             FC-factor
                  Fuel                       F-factor        (scf CO2/
                                           (dscf/mmBtu)       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 [deg]C (68 [deg]F) and 29.92
  inches of mercury.

[[Page 464]]

 
\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 [deg]C (68 [deg]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, Standard Test Method for Gross 
Calorific Value of Coal and Coke, and ASTM D240-00, Standard Test Method 
for Heat of Combustion of Liquid Hydrocarbon Fuels by Bomb Calorimeter, 
or ASTM D4809-00, Standard Test Method for Heat of Combustion of Liquid 
Hydrocarbon Fuels by Bomb Calorimeter (Precision Method) for oil; and 
ASTM D3588-98, Standard Practice for Calculating Heat Value, 
Compressibility Factor, and Relative Density of Gaseous Fuels, ASTM 
D4891-89 (Reapproved 2006), Standard Test Method for Heating Value of 
Gases in Natural Gas Range by Stoichiometric Combustion, GPA Standard 
2172-96 Calculation of Gross Heating Value, Relative Density and 
Compressibility Factor for Natural Gas Mixtures from Compositional 
Analysis, GPA Standard 2261-00 Analysis for Natural Gas and Similar 
Gaseous Mixtures by Gas Chromatography, or ASTM D1826-94 (Reapproved 
1998), Standard Test Method for Calorific (Heating) Value of Gases in 
Natural Gas Range by Continuous Recording Calorimeter, for gaseous 
fuels, as applicable. (All of these methods are incorporated by 
reference under Sec. 75.6 of this part).
    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

[[Page 465]]

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 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 = 5.7x10-7 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 5.7x10-7 (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

[[Page 466]]

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:
[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:

[[Page 467]]

[GRAPHIC] [TIFF OMITTED] TR26MY99.051

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:

[[Page 468]]

[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 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, 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 of this part).
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 of this part. Use ASTM D2013-01, Standard Practice for Preparing 
Coal Samples for Analysis, for preparation of a daily coal sample and 
analyze each daily coal sample for gross calorific value using ASTM 
D5865-01a, Standard Test Method for Gross Calorific Value of Coal and 
Coke. 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


[[Page 469]]


(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), or ASTM D5865-01a, Btu/lb. 
(incorporated by reference under Sec. 75.6 of this part).
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 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.

[[Page 470]]

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.

  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 [deg]R.
TStack = Flue gas temperature at flow monitor location, 
[deg]R, where [deg]R=460+ [deg]F.
PStack = The absolute flue gas pressure=barometric pressure 
at the flow monitor location + flue gas static pressure, inches of 
mercury.

[[Page 471]]

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 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 own 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:

[[Page 472]]

[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.).
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.

[[Page 473]]

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:
    (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. Procedures for Hg Mass Emissions.

    9.1 Use the procedures in this section to calculate the hourly Hg 
mass emissions (in ounces) at each monitored location, for the affected 
unit or group of units that discharge through a common stack.
    9.1.1 To determine the hourly Hg mass emissions when using a Hg 
concentration monitoring system that measures on a wet basis and a flow 
monitor, use the following equation:
[GRAPHIC] [TIFF OMITTED] TR18MY05.023

Where:

Mh = Hg mass emissions for the hour, rounded off to three 
decimal places, (ounces).
K = Units conversion constant, 9.978 x 10-10 oz-scm/
[micro]gm-scf
Ch = Hourly Hg concentration, wet basis, adjusted for bias if 
the bias-test procedures in appendix A to this part show that a bias-
adjustment factor is necessary, ([micro]gm/wscm).

[[Page 474]]

Qh = Hourly stack gas volumetric flow rate, adjusted for 
bias, where the bias-test procedures in appendix A to this part shows a 
bias-adjustment factor is necessary, (scfh)
th = Unit or stack operating time, as defined in Sec. 72.2, 
(hr)

    9.1.2 To determine the hourly Hg mass emissions when using a Hg 
concentration monitoring system that measures on a dry basis or a 
sorbent trap monitoring system and a flow monitor, use the following 
equation:
[GRAPHIC] [TIFF OMITTED] TR18MY05.024

Where:

Mh = Hg mass emissions for the hour, rounded off to three 
decimal places, (ounces).
K = Units conversion constant, 9.978 x 10-10 oz-scm/
[micro]gm-scf
Ch = Hourly Hg concentration, dry basis, adjusted for bias if 
the bias-test procedures in appendix A to this part show that a bias-
adjustment factor is necessary, ([micro]gm/dscm). For sorbent trap 
systems, a single value of Ch (i.e., a flow-proportional 
average concentration for the data collection period), is applied to 
each hour in the data collection period, for a particular pair of traps.
Qh = Hourly stack gas volumetric flow rate, adjusted for 
bias, where the bias-test procedures in appendix A to this part shows a 
bias-adjustment factor is necessary, (scfh)
Bws = Moisture fraction of the stack gas, expressed as a 
decimal (equal to % H2O 100)
th = Unit or stack operating time, as defined in Sec. 72.2, 
(hr)

    9.1.3 For units that are demonstrated under Sec. 75.81(d) to emit 
less than 464 ounces of Hg per year, and for which the owner or operator 
elects not to continuously monitor the Hg concentration, calculate the 
hourly Hg mass emissions using Equation F-28 in section 9.1.1 of this 
appendix, except that ``Ch'' shall be the applicable default 
Hg concentration from Sec. 75.81(c), (d), or (e), expressed in 
[micro]gm/scm. Correction for the stack gas moisture content is not 
required when this methodology is used.
    9.2 Use the following equation to calculate quarterly and year-to-
date Hg mass emissions in ounces:
[GRAPHIC] [TIFF OMITTED] TR18MY05.025

Where:

Mtime period = Hg mass emissions for the given time period 
i.e., quarter or year-to-date, rounded to the nearest thousandth, 
(ounces).
Mh = Hg mass emissions for the hour, rounded to three decimal 
places, (ounces).
n = The number of hours in the given time period (quarter or year-to-
date).

    9.3 If heat input rate monitoring is required, follow the applicable 
procedures for heat input apportionment and summation in sections 5.3, 
5.6 and 5.7 of this appendix.

   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
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 
26553-26556, 26571, May 17, 1995; 61 FR 25585, May 22, 1996; 61 FR 
59166, Nov. 20, 1996; 63 FR 57513, Oct. 27, 1998; 64 FR 28666-28671, 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]

[[Page 475]]



  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:
[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.

[[Page 476]]

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 [deg]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 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.

[[Page 477]]

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 478]]

[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 26556-26557, 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]



 Sec. Appendix K to Part 75--Quality Assurance and Operating Procedures 
                   for Sorbent Trap Monitoring Systems

                        1.0 Scope and Application

    This appendix specifies sampling, and analytical, and quality-
assurance criteria and procedures for the performance-based monitoring 
of vapor-phase mercury (Hg) emissions in combustion flue gas streams, 
using a sorbent trap monitoring system (as defined in Sec. 72.2 of this 
chapter). The principle employed is continuous sampling using in-stack 
sorbent media coupled with analysis of the integrated samples. The 
performance-based approach of this appendix allows for use of various 
suitable sampling and analytical technologies while maintaining a 
specified and documented level of data quality

[[Page 479]]

through performance criteria. Persons using this appendix should have a 
thorough working knowledge of Methods 1, 2, 3, 4 and 5 in appendices A-1 
through A-3 to part 60 of this chapter, as well as the determinative 
technique selected for analysis.

                              1.1 Analytes.

    The analyte measured by these procedures and specifications is total 
vapor-phase Hg in the flue gas, which represents the sum of elemental Hg 
(Hg\0\, CAS Number 7439-97-6) and oxidized forms of Hg, in mass 
concentration units of micrograms per dry standard cubic meter 
([micro]gm/dscm).

                           1.2 Applicability.

    These performance criteria and procedures are applicable to 
monitoring of vapor-phase Hg emissions under relatively low-dust 
conditions (i.e., sampling in the stack after all pollution control 
devices), from coal-fired electric utility steam generators which are 
subject to subpart I of this part. Individual sample collection times 
can range from 30 minutes to several days in duration, depending on the 
Hg concentration in the stack. The monitoring system must achieve the 
performance criteria specified in Section 8 of this appendix and the 
sorbent media capture ability must not be exceeded. The sampling rate 
must be maintained at a constant proportion to the total stack flowrate 
to ensure representativeness of the sample collected. Failure to achieve 
certain performance criteria will result in invalid Hg emissions 
monitoring data.

                             2.0 Principle.

    Known volumes of flue gas are extracted from a stack or duct through 
paired, in-stack, pre-spiked sorbent media traps at an appropriate 
nominal flow rate. Collection of Hg on the sorbent media in the stack 
mitigates potential loss of Hg during transport through a probe/sample 
line. Paired train sampling is required to determine measurement 
precision and verify acceptability of the measured emissions data.
    The sorbent traps are recovered from the sampling system, prepared 
for analysis, as needed, and analyzed by any suitable determinative 
technique that can meet the performance criteria. A section of each 
sorbent trap is spiked with Hg\0\ prior to sampling. This section is 
analyzed separately and the recovery value is used to correct the 
individual Hg sample for measurement bias.

                  3.0 Clean Handling and Contamination.

    To avoid Hg contamination of the samples, special attention should 
be paid to cleanliness during transport, field handling, sampling, 
recovery, and laboratory analysis, as well as during preparation of the 
sorbent cartridges. Collection and analysis of blank samples (field, 
trip, lab) is useful in verifying the absence of contaminant Hg.

                               4.0 Safety.

                            4.1 Site hazards.

    Site hazards must be thoroughly considered in advance of applying 
these procedures/specifications in the field; advance coordination with 
the site is critical to understand the conditions and applicable safety 
policies. At a minimum, portions of the sampling system will be hot, 
requiring appropriate gloves, long sleeves, and caution in handling this 
equipment.

                     4.2 Laboratory safety policies.

    Laboratory safety policies should be in place to minimize risk of 
chemical exposure and to properly handle waste disposal. Personnel shall 
wear appropriate laboratory attire according to a Chemical Hygiene Plan 
established by the laboratory.

                    4.3 Toxicity or carcinogenicity.

    The toxicity or carcinogenicity of any reagents used must be 
considered. Depending upon the sampling and analytical technologies 
selected, this measurement may involve hazardous materials, operations, 
and equipment and this appendix does not address all of the safety 
problems associated with implementing this approach. It is the 
responsibility of the user to establish appropriate safety and health 
practices and determine the applicable regulatory limitations prior to 
performance. Any chemical should be regarded as a potential health 
hazard and exposure to these compounds should be minimized. Chemists 
should refer to the Material Safety Data Sheet (MSDS) for each chemical 
used.

                               4.4 Wastes.

    Any wastes generated by this procedure must be disposed of according 
to a hazardous materials management plan that details and tracks various 
waste streams and disposal procedures.

                       5.0 Equipment and Supplies.

    The following list is presented as an example of key equipment and 
supplies likely required to perform vapor-phase Hg monitoring using a 
sorbent trap monitoring system. It is recognized that additional 
equipment and supplies may be needed. Collection of paired samples is 
required. Also required are a certified stack gas volumetric flow 
monitor that meets the requirements of Sec. 75.10 and an acceptable 
means of correcting for the stack gas moisture content, i.e., either by 
using data from a certified continuous moisture monitoring system or by 
using an approved default moisture value (see Sec. Sec. 75.11(b)).

[[Page 480]]

                   5.1 Sorbent Trap Monitoring System.

    A typical sorbent trap monitoring system is shown in Figure K-1. The 
monitoring system shall include the following components:
[GRAPHIC] [TIFF OMITTED] TR07SE07.027


[[Page 481]]



                          5.1.1 Sorbent Traps.

    The sorbent media used to collect Hg must be configured in a trap 
with three distinct and identical segments or sections, connected in 
series, that are amenable to separate analyses. Section 1 is designated 
for primary capture of gaseous Hg. Section 2 is designated as a backup 
section for determination of vapor-phase Hg breakthrough. Section 3 is 
designated for QA/QC purposes where this section shall be spiked with a 
known amount of gaseous Hg\0\ prior to sampling and later analyzed to 
determine recovery efficiency. The sorbent media may be any collection 
material (e.g., carbon, chemically-treated filter, etc.) capable of 
quantitatively capturing and recovering for subsequent analysis, all 
gaseous forms of Hg for the intended application. Selection of the 
sorbent media shall be based on the material's ability to achieve the 
performance criteria contained in Section 8 of this appendix as well as 
the sorbent's vapor-phase Hg capture efficiency for the emissions matrix 
and the expected sampling duration at the test site. The sorbent media 
must be obtained from a source that can demonstrate the quality 
assurance and control necessary to ensure consistent reliability. The 
paired sorbent traps are supported on a probe (or probes) and inserted 
directly into the flue gas stream.

                     5.1.2 Sampling Probe Assembly.

    Each probe assembly shall have a leak-free attachment to the sorbent 
trap(s). Each sorbent trap must be mounted at the entrance of or within 
the probe such that the gas sampled enters the trap directly. Each 
probe/sorbent trap assembly must be heated to a temperature sufficient 
to prevent liquid condensation in the sorbent trap(s). Auxiliary heating 
is required only where the stack temperature is too low to prevent 
condensation. Use a calibrated thermocouple to monitor the stack 
temperature. A single probe capable of operating the paired sorbent 
traps may be used. Alternatively, individual probe/sorbent trap 
assemblies may be used, provided that the individual sorbent traps are 
co-located to ensure representative Hg monitoring and are sufficiently 
separated to prevent aerodynamic interference.

                      5.1.3 Moisture Removal Device

    A robust moisture removal device or system, suitable for continuous 
duty (such as a Peltier cooler), shall be used to remove water vapor 
from the gas stream prior to entering the gas flow meter.

                           5.1.4 Vacuum Pump.

    Use a leak-tight, vacuum pump capable of operating within the 
candidate system's flow range.

                          5.1.5 Gas Flow Meter

    A gas flow meter (such as a dry gas meter, thermal mass flow meter, 
or other suitable measurement device) shall be used to determine the 
total sample volume on a dry basis, in units of standard cubic meters. 
The meter must be sufficiently accurate to measure the total sample 
volume to within 2 percent and must be calibrated at selected flow rates 
across the range of sample flow rates at which the sorbent trap 
monitoring system typically operates. The gas flow meter shall be 
equipped with any necessary auxiliary measurement devices (e.g., 
temperature sensors, pressure measurement devices) needed to correct the 
sample volume to standard conditions.

              5.1.6 Sample Flow Rate Meter and Controller.

    Use a flow rate indicator and controller for maintaining necessary 
sampling flow rates.

                        5.1.7 Temperature Sensor.

    Same as Section 6.1.1.7 of Method 5 in appendix A-3 to part 60 of 
this chapter.

                            5.1.8 Barometer.

    Same as Section 6.1.2 of Method 5 in appendix A-3 to part 60 of this 
chapter.

                      5.1.9 Data Logger (Optional).

    Device for recording associated and necessary ancillary information 
(e.g., temperatures, pressures, flow, time, etc.).

             5.2 Gaseous Hg\0\ Sorbent Trap Spiking System.

    A known mass of gaseous Hg\0\ must be spiked onto section 3 of each 
sorbent trap prior to sampling. Any approach capable of quantitatively 
delivering known masses of Hg\0\ onto sorbent traps is acceptable. 
Several technologies or devices are available to meet this objective. 
Their practicality is a function of Hg mass spike levels. For low 
levels, NIST-certified or NIST-traceable gas generators or tanks may be 
suitable, but will likely require long preparation times. A more 
practical, alternative system, capable of delivering almost any mass 
required, makes use of NIST-certified or NIST-traceable Hg salt 
solutions (e.g., Hg(NO3)2). With this system, an 
aliquot of known volume and concentration is added to a reaction vessel 
containing a reducing agent (e.g., stannous chloride); the Hg salt 
solution is reduced to Hg\0\ and purged onto section 3 of the sorbent 
trap using an impinger sparging system.

                     5.3 Sample Analysis Equipment.

    Any analytical system capable of quantitatively recovering and 
quantifying total gaseous Hg from sorbent media is acceptable provided 
that the analysis can meet the performance criteria in Section 8 of this 
procedure. Candidate recovery techniques include

[[Page 482]]

leaching, digestion, and thermal desorption. Candidate analytical 
techniques include ultraviolet atomic fluorescence (UV AF); ultraviolet 
atomic absorption (UV AA), with and without gold trapping; and in situ 
X-ray fluorescence (XRF) analysis.

                       6.0 Reagents and Standards.

    Only NIST-certified or NIST-traceable calibration gas standards and 
reagents shall be used for the tests and procedures required under this 
appendix.

                  7.0 Sample Collection and Transport.

                        7.1 Pre-Test Procedures.

                    7.1.1 Selection of Sampling Site.

    Sampling site information should be obtained in accordance with 
Method 1 in appendix A-1 to part 60 of this chapter. Identify a 
monitoring location representative of source Hg emissions. Locations 
shown to be free of stratification through measurement traverses for 
gases such as SO2 and NOX may be one such 
approach. An estimation of the expected stack Hg concentration is 
required to establish a target sample flow rate, total gas sample 
volume, and the mass of Hg\0\ to be spiked onto section 3 of each 
sorbent trap.

              7.1.2 Pre-sampling Spiking of Sorbent Traps.

    Based on the estimated Hg concentration in the stack, the target 
sample rate and the target sampling duration, calculate the expected 
mass loading for section 1 of each sorbent trap (for an example 
calculation, see section 11.1 of this appendix). The pre-sampling spike 
to be added to section 3 of each sorbent trap shall be within 50 percent of the expected section 1 mass loading. Spike 
section 3 of each sorbent trap at this level, as described in section 
5.2 of this appendix. For each sorbent trap, keep an official record of 
the mass of Hg\0\ added to section 3. This record shall include, at a 
minimum, the ID number of the trap, the date and time of the spike, the 
name of the analyst performing the procedure, the mass of Hg\0\ added to 
section 3 of the trap ([micro]gm), and the supporting calculations. This 
record shall be maintained in a format suitable for inspection and audit 
and shall be made available to the regulatory agencies upon request.

                        7.1.3 Pre-test Leak Check

    Perform a leak check with the sorbent traps in place. Draw a vacuum 
in each sample train. Adjust the vacuum in the sample train to 15[sec] 
Hg. Using the gas flow meter, determine leak rate. The leakage rate must 
not exceed 4 percent of the target sampling rate. Once the leak check 
passes this criterion, carefully release the vacuum in the sample train 
then seal the sorbent trap inlet until the probe is ready for insertion 
into the stack or duct.

            7.1.4 Determination of Flue Gas Characteristics.

    Determine or measure the flue gas measurement environment 
characteristics (gas temperature, static pressure, gas velocity, stack 
moisture, etc.) in order to determine ancillary requirements such as 
probe heating requirements (if any), initial sample rate, proportional 
sampling conditions, moisture management, etc.

                         7.2 Sample Collection.

    7.2.1 Remove the plug from the end of each sorbent trap and store 
each plug in a clean sorbent trap storage container. Remove the stack or 
duct port cap and insert the probe(s). Secure the probe(s) and ensure 
that no leakage occurs between the duct and environment.
    7.2.2 Record initial data including the sorbent trap ID, start time, 
starting dry gas meter readings, initial temperatures, set-points, and 
any other appropriate information.

                         7.2.3 Flow Rate Control

    Set the initial sample flow rate at the target value from section 
7.1.1 of this appendix. Record the initial gas flow meter reading, stack 
temperature (if needed to convert to standard conditions), meter 
temperatures (if needed), etc. Then, for every operating hour during the 
sampling period, record the date and time, the sample flow rate, the gas 
flow meter reading, the stack temperature (if needed), the flow meter 
temperatures (if needed), temperatures of heated equipment such as the 
vacuum lines and the probes (if heated), and the sampling system vacuum 
readings. Also, record the stack gas flow rate, as measured by the 
certified flow monitor, and the ratio of the stack gas flow rate to the 
sample flow rate. Adjust the sampling flow rate to maintain proportional 
sampling, i.e., keep the ratio of the stack gas flow rate to sample flow 
rate constant, to within 25 percent of the 
reference ratio from the first hour of the data collection period (see 
section 11 of this appendix). The sample flow rate through a sorbent 
trap monitoring system during any hour (or portion of an hour) in which 
the unit is not operating shall be zero.

                 7.2.4 Stack Gas Moisture Determination.

    Determine stack gas moisture using a continuous moisture monitoring 
system, as described in Sec. 75.11(b). Alternatively, the owner or 
operator may use the appropriate fuel-specific moisture default value 
provided in Sec. 75.11, or a site-specific moisture default value 
approved by petition under Sec. 75.66.

[[Page 483]]

                     7.2.5 Essential Operating Data

    Obtain and record any essential operating data for the facility 
during the test period, e.g., the barometric pressure for correcting the 
sample volume measured by a dry gas meter to standard conditions. At the 
end of the data collection period, record the final gas flow meter 
reading and the final values of all other essential parameters.

                       7.2.6 Post Test Leak Check.

    When sampling is completed, turn off the sample pump, remove the 
probe/sorbent trap from the port and carefully re-plug the end of each 
sorbent trap. Perform a leak check with the sorbent traps in place, at 
the maximum vacuum reached during the sampling period. Use the same 
general approach described in section 7.1.3 of this appendix. Record the 
leakage rate and vacuum. The leakage rate must not exceed 4 percent of 
the average sampling rate for the data collection period. Following the 
leak check, carefully release the vacuum in the sample train.

                         7.2.7 Sample Recovery.

    Recover each sampled sorbent trap by removing it from the probe, 
sealing both ends. Wipe any deposited material from the outside of the 
sorbent trap. Place the sorbent trap into an appropriate sample storage 
container and store/preserve in appropriate manner.

           7.2.8 Sample Preservation, Storage, and Transport.

    While the performance criteria of this approach provide for 
verification of appropriate sample handling, it is still important that 
the user consider, determine, and plan for suitable sample preservation, 
storage, transport, and holding times for these measurements. Therefore, 
procedures in ASTM D6911-03 ``Standard Guide for Packaging and Shipping 
Environmental Samples for Laboratory Analysis'' (incorporated by 
reference, see Sec. 75.6) shall be followed for all samples.

                          7.2.9 Sample Custody.

    Proper procedures and documentation for sample chain of custody are 
critical to ensuring data integrity. The chain of custody procedures in 
ASTM D4840-99 (reapproved 2004) ``Standard Guide for Sample Chain-of-
Custody Procedures'' (incorporated by reference, see Sec. 75.6) shall 
be followed for all samples (including field samples and blanks).

               8.0 Quality Assurance and Quality Control.

    Table K-1 summarizes the QA/QC performance criteria that are used to 
validate the Hg emissions data from sorbent trap monitoring systems, 
including the relative accuracy test audit (RATA) requirement (see Sec. 
75.20(c)(9), section 6.5.7 of appendix A to this part, and section 2.3 
of appendix B to this part). Except as provided in Sec. 75.15(h) and as 
otherwise indicated in Table K-1, failure to achieve these performance 
criteria will result in invalidation of Hg emissions data.

[[Page 484]]



           Table K-1.--Quality Assurance/Quality Control Criteria for Sorbent Trap Monitoring Systems
----------------------------------------------------------------------------------------------------------------
   QA/QC test or specification        Acceptance criteria             Frequency          Consequences if not met
----------------------------------------------------------------------------------------------------------------
Pre-test leak check..............  <=4% of target sampling    Prior to sampling.......  Sampling shall not
                                    rate.                                                commence until the leak
                                                                                         check is passed.
Post-test leak check.............  <=4% of average sampling   After sampling..........  ** See Note, below.
                                    rate.
Ratio of stack gas flow rate to    No more than 5% of the     Every hour throughout     ** See Note, below.
 sample flow rate.                  hourly ratios or 5         data collection period.
                                    hourly ratios (whichever
                                    is less restrictive) may
                                    deviate from the
                                    reference ratio by more
                                    than  25%.
Sorbent trap section 2 break-      <=5% of Section 1 Hg mass  Every sample............  ** See Note, below.
 through.
Paired sorbent trap agreement....  <=10% Relative Deviation   Every sample............  Either invalidate the
                                    (RD) if the average                                  data from the paired
                                    concentration is  1.0 [micro]g/m\3\.                               results from the trap
                                   <= 20% RD if the average                              with the higher Hg
                                    concentration is <= 1.0                              concentration.
                                    [micro]g/m\3\.
                                   Results are also
                                    acceptable if absolute
                                    difference between
                                    concentrations from
                                    paired traps is <= 0.03
                                    [micro]g/m\3\.
Spike Recovery Study.............  Average recovery between   Prior to analyzing field  Field samples shall not
                                    85% and 115% for each of   samples and prior to      be analyzed until the
                                    the 3 spike                use of new sorbent        percent recovery
                                    concentration levels.      media.                    criteria has been met
Multipoint analyzer calibration..  Each analyzer reading      On the day of analysis,   Recalibrate until
                                    within  10% of true        samples.
                                    value and r\2\ = 0.99.
Analysis of independent            Within  10% of true value.     calibration, prior to     independent standard
                                                               analyzing field samples.  analysis until
                                                                                         successful.
Spike recovery from section 3 of   75-125% of spike amount..  Every sample............  ** See Note, below.
 sorbent trap.
RATA.............................  RA <= 20.0% or Mean        For initial               Data from the system are
                                    difference <= 1.0          certification and         invalidated until a
                                    [micro]g/dscm for low      annually thereafter.      RATA is passed.
                                    emitters.
Gas flow meter calibration.......  Calibration factor (Y)     At three settings prior   Recalibrate the meter at
                                    within  5% of average      least quarterly at one    to determine a new
                                    value from the most        setting thereafter. For   value of Y.
                                    recent 3-point             mass flow meters,
                                    calibration.               initial calibration
                                                               with stack gas is
                                                               required.
Temperature sensor calibration...  Absolute temperature       Prior to initial use and  Recalibrate. Sensor may
                                    measured by sensor         at least quarterly        not be used until
                                    within  1.5% of a
                                    reference sensor.
Barometer calibration............  Absolute pressure          Prior to initial use and  Recalibrate. Instrument
                                    measured by instrument     at least quarterly        may not be used until
                                    within  10 mm Hg of
                                    reading with a mercury
                                    barometer.
----------------------------------------------------------------------------------------------------------------
** Note: If both traps fail to meet the acceptance criteria, the data from the pair of traps are invalidated.
  However, if only one of the paired traps fails to meet this particular acceptance criterion and the other
  sample meets all of the applicable QA criteria, the results of the valid trap may be used for reporting under
  this part, provided that the measured Hg concentration is multiplied by a factor of 1.111. When the data from
  both traps are invalidated and quality-assured data from a certified backup monitoring system, reference
  method, or approved alternative monitoring system are unavailable, missing data substitution must be used.


[[Page 485]]

                  9.0 Calibration and Standardization.

    9.1 Only NIST-certified and NIST-traceable calibration standards 
(i.e., calibration gases, solutions, etc.) shall be used for the spiking 
and analytical procedures in this appendix.

                     9.2 Gas Flow Meter Calibration

    9.2.1 Preliminaries. The manufacturer or supplier of the gas flow 
meter should perform all necessary set-up, testing, programming, etc., 
and should provide the end user with any necessary instructions, to 
ensure that the meter will give an accurate readout of dry gas volume in 
standard cubic meters for the particular field application.
    9.2.2 Initial Calibration. Prior to its initial use, a calibration 
of the flow meter shall be performed. The initial calibration may be 
done by the manufacturer, by the equipment supplier, or by the end user. 
If the flow meter is volumetric in nature (e.g., a dry gas meter), the 
manufacturer, equipment supplier, or end user may perform a direct 
volumetric calibration using any gas. For a mass flow meter, the 
manufacturer, equipment supplier, or end user may calibrate the meter 
using a bottled gas mixture containing 12  0.5% 
CO2, 7  0.5% O2, and balance 
N2, or these same gases in proportions more representative of 
the expected stack gas composition. Mass flow meters may also be 
initially calibrated on-site, using actual stack gas.
    9.2.2.1 Initial Calibration Procedures. Determine an average 
calibration factor (Y) for the gas flow meter, by calibrating it at 
three sample flow rate settings covering the range of sample flow rates 
at which the sorbent trap monitoring system typically operates. You may 
either follow the procedures in section 10.3.1 of Method 5 in appendix 
A-3 to part 60 of this chapter or the procedures in section 16 of Method 
5 in appendix A-3 to part 60 of this chapter. If a dry gas meter is 
being calibrated, use at least five revolutions of the meter at each 
flow rate.
    9.2.2.2 Alternative Initial Calibration Procedures. Alternatively, 
you may perform the initial calibration of the gas flow meter using a 
reference gas flow meter (RGFM). The RGFM may either be: (1) A wet test 
meter calibrated according to section 10.3.1 of Method 5 in appendix A-3 
to part 60; (2) a gas flow metering device calibrated at multiple flow 
rates using the procedures in section 16 of Method 5 in appendix A-3 to 
part 60; or (3) a NIST-traceable calibration device capable of measuring 
volumetric flow to an accuracy of 1 percent. To calibrate the gas flow 
meter using the RGFM, proceed as follows: While the sorbent trap 
monitoring system is sampling the actual stack gas or a compressed gas 
mixture that simulates the stack gas composition (as applicable), 
connect the RGFM to the discharge of the system. Care should be taken to 
minimize the dead volume between the sample flow meter being tested and 
the RGFM. Concurrently measure dry gas volume with the RGFM and the flow 
meter being calibrated the for a minimum of 10 minutes at each of three 
flow rates covering the typical range of operation of the sorbent trap 
monitoring system. For each 10-minute (or longer) data collection 
period, record the total sample volume, in units of dry standard cubic 
meters (dscm), measured by the RGFM and the gas flow meter being tested.
    9.2.2.3 Initial Calibration Factor. Calculate an individual 
calibration factor Yi at each tested flow rate from section 
9.2.2.1 or 9.2.2.2 of this appendix (as applicable), by taking the ratio 
of the reference sample volume to the sample volume recorded by the gas 
flow meter. Average the three Yi values, to determine Y, the 
calibration factor for the flow meter. Each of the three individual 
values of Yi must be within 0.02 of Y. 
Except as otherwise provided in sections 9.2.2.4 and 9.2.2.5 of this 
appendix, use the average Y value from the three level calibration to 
adjust all subsequent gas volume measurements made with the gas flow 
meter.
    9.2.2.4 Initial On-Site Calibration Check. For a mass flow meter 
that was initially calibrated using a compressed gas mixture, an on-site 
calibration check shall be performed before using the flow meter to 
provide data for this part. While sampling stack gas, check the 
calibration of the flow meter at one intermediate flow rate typical of 
normal operation of the monitoring system. Follow the basic procedures 
in section 9.2.2.1 or 9.2.2.2 of this appendix. If the on-site 
calibration check shows that the value of Yi, the calibration 
factor at the tested flow rate, differs by more than 5 percent from the 
value of Y obtained in the initial calibration of the meter, repeat the 
full 3-level calibration of the meter using stack gas to determine a new 
value of Y, and apply the new Y value to all subsequent gas volume 
measurements made with the gas flow meter.
    9.2.2.5 Ongoing Quality Assurance. Recalibrate the gas flow meter 
quarterly at one intermediate flow rate setting representative of normal 
operation of the monitoring system. Follow the basic procedures in 
section 9.2.2.1 or 9.2.2.2 of this appendix. If a quarterly 
recalibration shows that the value of Yi, the calibration 
factor at the tested flow rate, differs from the current value of Y by 
more than 5 percent, repeat the full 3-level calibration of the meter to 
determine a new value of Y, and apply the new Y value to all subsequent 
gas volume measurements made with the gas flow meter.

            9.3 Thermocouples and Other Temperature Sensors.

    Use the procedures and criteria in Section 10.3 of Method 2 in 
appendix A-1 to part 60 of

[[Page 486]]

this chapter to calibrate in-stack temperature sensors and 
thermocouples. Dial thermometers shall be calibrated against mercury-in-
glass thermometers. Calibrations must be performed prior to initial use 
and at least quarterly thereafter. At each calibration point, the 
absolute temperature measured by the temperature sensor must agree to 
within 1.5 percent of the temperature measured 
with the reference sensor, otherwise the sensor may not continue to be 
used.

                             9.4 Barometer.

    Calibrate against a mercury barometer. Calibration must be performed 
prior to initial use and at least quarterly thereafter. At each 
calibration point, the absolute pressure measured by the barometer must 
agree to within 10 mm Hg of the pressure measured 
by the mercury barometer, otherwise the barometer may not continue to be 
used.

                      9.5 Other Sensors and Gauges.

    Calibrate all other sensors and gauges according to the procedures 
specified by the instrument manufacturer(s).

                   9.6 Analytical System Calibration.

    See section 10.1 of this appendix.

                       10.0 Analytical Procedures.

    The analysis of the Hg samples may be conducted using any instrument 
or technology capable of quantifying total Hg from the sorbent media and 
meeting the performance criteria in section 8 of this appendix.

                    10.1 Analyzer System Calibration.

    Perform a multipoint calibration of the analyzer at three or more 
upscale points over the desired quantitative range (multiple calibration 
ranges shall be calibrated, if necessary). The field samples analyzed 
must fall within a calibrated, quantitative range and meet the necessary 
performance criteria. For samples that are suitable for aliquotting, a 
series of dilutions may be needed to ensure that the samples fall within 
a calibrated range. However, for sorbent media samples that are consumed 
during analysis (e.g., thermal desorption techniques), extra care must 
be taken to ensure that the analytical system is appropriately 
calibrated prior to sample analysis. The calibration curve range(s) 
should be determined based on the anticipated level of Hg mass on the 
sorbent media. Knowledge of estimated stack Hg concentrations and total 
sample volume may be required prior to analysis. The calibration curve 
for use with the various analytical techniques (e.g., UV AA, UV AF, and 
XRF) can be generated by directly introducing standard solutions into 
the analyzer or by spiking the standards onto the sorbent media and then 
introducing into the analyzer after preparing the sorbent/standard 
according to the particular analytical technique. For each calibration 
curve, the value of the square of the linear correlation coefficient, 
i.e., r\2\, must be = 0.99, and the analyzer response must be 
within 10 percent of reference value at each 
upscale calibration point. Calibrations must be performed on the day of 
the analysis, before analyzing any of the samples. Following 
calibration, an independently prepared standard (not from same 
calibration stock solution) shall be analyzed. The measured value of the 
independently prepared standard must be within 10 
percent of the expected value.

                        10.2 Sample Preparation.

    Carefully separate the three sections of each sorbent trap. Combine 
for analysis all materials associated with each section, i.e., any 
supporting substrate that the sample gas passes through prior to 
entering a media section (e.g., glass wool, polyurethane foam, etc.) 
must be analyzed with that segment.

                       10.3 Spike Recovery Study.

    Before analyzing any field samples, the laboratory must demonstrate 
the ability to recover and quantify Hg from the sorbent media by 
performing the following spike recovery study for sorbent media traps 
spiked with elemental mercury.
    Using the procedures described in sections 5.2 and 11.1 of this 
appendix, spike the third section of nine sorbent traps with gaseous 
Hg\0\, i.e., three traps at each of three different mass loadings, 
representing the range of masses anticipated in the field samples. This 
will yield a 3 x 3 sample matrix. Prepare and analyze the third section 
of each spiked trap, using the techniques that will be used to prepare 
and analyze the field samples. The average recovery for each spike 
concentration must be between 85 and 115 percent. If multiple types of 
sorbent media are to be analyzed, a separate spike recovery study is 
required for each sorbent material. If multiple ranges are calibrated, a 
separate spike recovery study is required for each range.

                       10.4 Field Sample Analysis

    Analyze the sorbent trap samples following the same procedures that 
were used for conducting the spike recovery study. The three sections of 
each sorbent trap must be analyzed separately (i.e., section 1, then 
section 2, then section 3). Quantify the total mass of Hg for each 
section based on analytical system response and the calibration curve 
from section 10.1 of this appendix. Determine the spike recovery from 
sorbent trap section 3. The spike recovery must be no less than 75 
percent and no greater than 125 percent. To report the final Hg mass for 
each trap, add together the Hg masses collected in trap sections 1 and 
2.

[[Page 487]]

                  11.0 Calculations and Data Analysis.

             11.1 Calculation of Pre-Sampling Spiking Level.

    Determine sorbent trap section 3 spiking level using estimates of 
the stack Hg concentration, the target sample flow rate, and the 
expected sample duration. First, calculate the expected Hg mass that 
will be collected in section 1 of the trap. The pre-sampling spike must 
be within 50 percent of this mass. Example 
calculation: For an estimated stack Hg concentration of 5 [micro]gm/
m\3\, a target sample rate of 0.30 L/min, and a sample duration of 5 
days:

(0.30 L/min) (1440 min/day) (5 days) (10-3 m\3\/liter) 
(5[micro]gm/m\3\) = 10.8 [micro]gm

A pre-sampling spike of 10.8 [micro]gm 50 percent 
is, therefore, appropriate.

            11.2 Calculations for Flow-Proportional Sampling.

    For the first hour of the data collection period, determine the 
reference ratio of the stack gas volumetric flow rate to the sample flow 
rate, as follows:
[GRAPHIC] [TIFF OMITTED] TR18MY05.012

Where:

Rref = Reference ratio of hourly stack gas flow rate to 
hourly sample flow rate
Qref = Average stack gas volumetric flow rate for first hour 
of collection period, adjusted for bias, if necessary, according to 
section 7.6.5 of appendix A to this part, (scfh)
Fref = Average sample flow rate for first hour of the 
collection period, in appropriate units (e.g., liters/min, cc/min, dscm/
min)
K = Power of ten multiplier, to keep the value of Rref 
between 1 and 100. The appropriate K value will depend on the selected 
units of measure for the sample flow rate.

    Then, for each subsequent hour of the data collection period, 
calculate ratio of the stack gas flow rate to the sample flow rate using 
the equation K-2:
[GRAPHIC] [TIFF OMITTED] TR18MY05.013

Where:

Rh = Ratio of hourly stack gas flow rate to hourly sample 
flow rate
Qh = Average stack gas volumetric flow rate for the hour, 
adjusted for bias, if necessary, according to section 7.6.5 of appendix 
A to this part, (scfh)
Fh = Average sample flow rate for the hour, in appropriate 
units (e.g., liters/min, cc/min, dscm/min)
K = Power of ten multiplier, to keep the value of Rh between 
1 and 100. The appropriate K value will depend on the selected units of 
measure for the sample flow rate and the range of expected stack gas 
flow rates.

Maintain the value of Rh within 25 
percent of Rref throughout the data collection period.

                   11.3 Calculation of Spike Recovery.

    Calculate the percent recovery of each section 3 spike, as follows:
    [GRAPHIC] [TIFF OMITTED] TR18MY05.014
    
Where:

%R = Percentage recovery of the pre-sampling spike
M3 = Mass of Hg recovered from section 3 of the sorbent trap, 
([micro]gm)
Ms = Calculated Hg mass of the pre-sampling spike, from 
section 7.1.2 of this appendix, ([micro]gm)

                    11.4 Calculation of Breakthrough.

    Calculate the percent breakthrough to the second section of the 
sorbent trap, as follows:
[GRAPHIC] [TIFF OMITTED] TR18MY05.015

Where:

%B = Percent breakthrough
M2 = Mass of Hg recovered from section 2 of the sorbent trap, 
([micro]gm)
M1 = Mass of Hg recovered from section 1 of the sorbent trap, 
([micro]gm)

                             11.5 [Reserved]

                  11.6 Calculation of Hg Concentration

    Calculate the Hg concentration for each sorbent trap, using the 
following equation:
[GRAPHIC] [TIFF OMITTED] TR07SE07.036

Where:

C = Concentration of Hg for the collection period, ([micro]gm/dscm)
M\*\ = Total mass of Hg recovered from sections 1 and 2 of the sorbent 
trap, ([micro]g)
Vt = Total volume of dry gas metered during the collection 
period, (dscm). For the purposes of this appendix, standard temperature 
and pressure are defined as 20 [deg]C and 760 mm Hg, respectively.

               11.7 Calculation of Paired Trap Agreeement

    Calculate the relative deviation (RD) between the Hg concentrations 
measured with the paired sorbent traps:

[[Page 488]]

[GRAPHIC] [TIFF OMITTED] TR07SE07.037

Where:

RD = Relative deviation between the Hg concentrations from traps ``a'' 
and ``b'' (percent)
Ca = Concentration of Hg for the collection period, for 
sorbent trap ``a'' ([micro]gm/dscm)
Cb = Concentration of Hg for the collection period, for 
sorbent trap ``b'' ([micro]gm/dscm)

                 11.8 Calculation of Hg Mass Emissions.

    To calculate Hg mass emissions, follow the procedures in section 
9.1.2 of appendix F to this part. Use the average of the two Hg 
concentrations from the paired traps in the calculations, except as 
provided in Sec. 75.15(h) or in Table K-1.

                        12.0 Method Performance.

    These monitoring criteria and procedures have been applied to coal-
fired utility boilers (including units with post-combustion emission 
controls), having vapor-phase Hg concentrations ranging from 0.03 
[micro]gm/dscm to 100 [micro]gm/dscm.

[70 FR 28695, May 18, 2005, as amended at 72 FR 51528, Sept. 7, 2007; 72 
FR 55279, Sept. 28, 2007; 73 FR 4376, Jan. 24, 2008]



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.
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

[[Page 489]]

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 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.

[[Page 490]]

    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.
    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).

[[Page 491]]

    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 
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

[[Page 492]]

(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).
    (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),

[[Page 493]]

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 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.

[[Page 494]]

    (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 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

[[Page 495]]

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 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

[[Page 496]]

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
    (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:

[[Page 497]]

    (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 
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

[[Page 498]]

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 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

[[Page 499]]

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 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

[[Page 500]]

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, 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

[[Page 501]]

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.
    (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;

[[Page 502]]

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 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:

[[Page 503]]

[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.
    (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

[[Page 504]]

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 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

[[Page 505]]

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 
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,

[[Page 506]]

[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 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

[[Page 507]]

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 
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

[[Page 508]]

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).



 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.

[[Page 509]]

 
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.
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.

[[Page 510]]

 
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.
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.

[[Page 511]]

 
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.
----------------------------------------------------------------------------------------------------------------



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.

[[Page 512]]

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. 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.


[[Page 513]]


    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 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

[[Page 514]]

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;
    (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

[[Page 515]]

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.
    (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.

[[Page 516]]

    (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:
    (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

[[Page 517]]

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 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

[[Page 518]]

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 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;

[[Page 519]]

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, or part 97 of this chapter; 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 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.

[[Page 520]]

    (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;
    (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;

[[Page 521]]

    (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;
    (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;

[[Page 522]]

    (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.
    (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]



Sec. 78.2  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 appeals of any final decision of 
the Administrator under parts 72, 73, 74, 75, 76, or 77 of this chapter.

[58 FR 3760, Jan. 11, 1993, as amended at 69 FR 21645, Apr. 21, 2004]



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.
    (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.
    (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.
    (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):

[[Page 523]]

    (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.
    (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.
    (7) The following persons may petition for administrative review of 
a decision of the Administrator that is made under subparts AA through 
II of 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.
    (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.
    (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.
    (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) and (2) 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 and, if an evidentiary 
hearing is requested, why direct and cross-examination of witnesses is 
necessary to resolve such factual issues;

[[Page 524]]

    (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.

[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]



Sec. 78.4  Filings.

    (a) All original filings made under this part shall be signed by the 
person making the filing or by an attorney or authorized representative. 
Any filings on behalf of owners and operators of an affected unit or 
affected source shall be signed by the designated representative. Any 
filings on behalf of persons

[[Page 525]]

with an interest in allowances in a general account shall be signed by 
the authorized account representative. Any filings on behalf of owners 
and operators of a NOX Budget unit or source shall be signed 
by the NOX authorized account representative. Any filings on 
behalf of persons with an interest in NOX allowances in a 
general account shall be signed by the NOX authorized account 
representative. 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 interest in 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. The name, address, telephone number, 
and facsimile number 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 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

[[Page 526]]

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]



Sec. 78.5  Limitation on filing or presenting new evidence and raising
new issues.

    (a) Where there was an opportunity for public comment 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 public comment period, 
absent a showing of good cause explaining the party's failure to do so 
during the public comment period. 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 public comment period.
    (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]



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 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.

[[Page 527]]

    (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 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 public comment:
    (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

[[Page 528]]

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]



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.
    (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.

[[Page 529]]

    (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 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

[[Page 530]]

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 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

[[Page 531]]

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 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

[[Page 532]]

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.
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.

[[Page 533]]



                      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 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

[[Page 534]]

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]



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, fuel manufacturers shall submit to the Administrator 
a report for each registered fuel showing (i) the range of concentration 
of each additive reported under Sec. 79.11(a) and (ii) the volume of 
such fuel produced in the quarter. Reports shall be submitted within 45 
days after the close of the reporting period on forms supplied by the 
Administrator upon request.
    (2) Fuel manufacturers shall submit to the Administrator a report 
annually for each registered fuel providing additional data and 
information as specified in Sec. 79.31(c) and (d) in the designation of 
the fuel in subpart D. Reports shall be submitted on or before 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 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 paragraphs (c) 
and (d) in the designation of the additive in subpart D. Additive 
manufacturers shall also report annually the volume of each additive 
produced. Reports shall be submitted on or before 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 or the later registration of an additive is between October 1 
and December 31, no report will be required for the period to

[[Page 535]]

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.



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]



                 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;

[[Page 536]]

    (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 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.

[[Page 537]]

    (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 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]

[[Page 538]]



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 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.

[[Page 539]]

    (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;
    (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

[[Page 540]]

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.
    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

[[Page 541]]

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 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

[[Page 542]]

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 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.

[[Page 543]]

    (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
    (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.

[[Page 544]]

    (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.
    (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

[[Page 545]]

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, 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

[[Page 546]]

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.
    (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

[[Page 547]]

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 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.

[[Page 548]]

    (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 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

[[Page 549]]

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 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

[[Page 550]]

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 
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

[[Page 551]]

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 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 [deg]C or 
less. If the emissions are sampled using the impinger method, the sample 
must be stored in a capped sample vial at 0 [deg]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

[[Page 552]]

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.
    (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

[[Page 553]]

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.
    (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]

[[Page 554]]

    (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 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

[[Page 555]]

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 
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;

[[Page 556]]

    (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 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

[[Page 557]]

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 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

[[Page 558]]

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 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:

[[Page 559]]

    (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.
    (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

[[Page 560]]

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..................................  57.40.3
Sulfur, ppm..................................  33925
Benzene, vol%................................  1.530.3
RVP, psi.....................................  8.70.3
Octane, (R+M)/2..............................  87.30.5
Distillation Parameters:
  10%, [deg]F................................  1285
  50%, [deg]F................................  2185
  90%, [deg]F................................  3305
Aromatics, vol%..............................  32.02.7
Olefins, vol%................................  9.22.5
Saturates, vol%..............................  58.82.0
Additive Types:
  Required...................................  Deposit Control
                                               Corrosion Inhibitor
                                               Demulsifier
                                               Anti-oxidant
                                               Metal Deactivator
  Permissible................................  Anti-static
------------------------------------------------------------------------

    (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..................................  331
Sulfur, wt%..................................  0.050.0025
Cetane Number................................  45.22
Cetane Index.................................  45.72
Distillation Parameters:
  10%, [deg]F................................  4335
  50%, [deg]F................................  5165
  90%, [deg]F................................  6065
Aromatics, vol%..............................  38.42.7
Olefins, vol%................................  1.50.4
Saturates, vol%..............................  60.12.0
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.

[[Page 561]]

    (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
------------------------------------------------------------------------

    (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%, [deg]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
------------------------------------------------------------------------


[[Page 562]]



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 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

[[Page 563]]

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 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.

[[Page 564]]



                                                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.
--------------------------------------------------------------------------------------------------------------------------------------------------------

    (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).

[[Page 565]]

    (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 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,

[[Page 566]]

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 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

[[Page 567]]

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-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

[[Page 568]]

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 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

[[Page 569]]

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 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

[[Page 570]]

    (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 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

[[Page 571]]

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 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,

[[Page 572]]

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 [deg]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 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 [deg]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

[[Page 573]]

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.
    (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

[[Page 574]]

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 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

[[Page 575]]

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 [deg]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 [deg]C or less.
    (D) 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) 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).

[[Page 576]]

    (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.) 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.

[[Page 577]]

    (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.
    (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

[[Page 578]]

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 [deg]F5 [deg]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, 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.

[[Page 579]]

    (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 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

[[Page 580]]

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 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

[[Page 581]]

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 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:

[[Page 582]]

    (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:

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),

[[Page 583]]

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,
    (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

[[Page 584]]

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).
    (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

[[Page 585]]

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.
    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

[[Page 586]]

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 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

[[Page 587]]

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.
    (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).

[[Page 588]]

    (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.
    (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

[[Page 589]]

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 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

[[Page 590]]

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;
    (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

[[Page 591]]

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.
    (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

[[Page 592]]

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.
    (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

[[Page 593]]

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.
    (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.

[[Page 594]]

    (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 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

[[Page 595]]

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 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

[[Page 596]]

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[deg] 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 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

[[Page 597]]

``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. 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

[[Page 598]]

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 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.

[[Page 599]]

    (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 [deg]C 2 [deg]C and for rabbits, it is 20 
[deg]C 3 [deg]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 
[deg]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 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

[[Page 600]]

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 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

[[Page 601]]

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 [deg]C (80 
[deg]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 [deg]C. 
Accuracy of the temperature monitoring device will be 1 [deg]C for the temperature range of 20-30 [deg]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 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.

[[Page 602]]

    (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
    (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;

[[Page 603]]

    (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.
    (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.

[[Page 604]]

    (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. 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:

[[Page 605]]

    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 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

[[Page 606]]

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 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

[[Page 607]]

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, 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

[[Page 608]]

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 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

[[Page 609]]

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.
    (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

[[Page 610]]

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 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

[[Page 611]]

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 
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.

[[Page 612]]

    (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.
    (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

[[Page 613]]

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 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.

[[Page 614]]

    (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.
    (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.

[[Page 615]]

    (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.
    (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

[[Page 616]]

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.
    (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+(2xpercent 2nd 
division) + (3xpercent 3rd division) metaphases]/100; and

[[Page 617]]

    (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 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.

[[Page 618]]

    (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 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 [deg]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

[[Page 619]]

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 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

[[Page 620]]

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).
    (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

[[Page 621]]

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 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 [deg]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 [deg]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).

[[Page 622]]

    (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.
    (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;

[[Page 623]]

    (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.

    (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

[[Page 624]]

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 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 [reg]-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.

[[Page 625]]

    (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 [deg]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.
    (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 [deg]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

[[Page 626]]

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 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,

[[Page 627]]

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]



PART 80_REGULATION OF FUELS AND FUEL ADDITIVES--Table of Contents




                      Subpart A_General Provisions

Sec.
80.1 Scope.
80.2 Definitions.
80.3 Test methods.
80.4 Right of entry; tests and inspections.
80.5 Penalties.
80.7 Requests for information.
80.8 Sampling methods for gasoline and diesel fuel.
80.9 Rounding a test result for determining conformance with a fuels 
          standard.

                   Subpart B_Controls and Prohibitions

80.20-80.21 [Reserved]
80.22 Controls and prohibitions.
80.23 Liability for violations.
80.24 Controls applicable to motor vehicle manufacturers.
80.25 [Reserved]
80.26 Confidentiality of information.
80.27 Controls and prohibitions on gasoline volatility.
80.28 Liability for violations of gasoline volatility controls and 
          prohibitions.
80.29 Controls and prohibitions on diesel fuel quality.
80.30 Liability for violations of diesel fuel control and prohibitions.
80.32 Controls applicable to liquefied petroleum gas retailers and 
          wholesale purchaser-consumers.
80.33 Controls applicable to natural gas retailers and wholesale 
          purchaser-consumers.

                      Subpart C_Oxygenated Gasoline

80.35 Labeling of retail gasoline pumps; oxygenated gasoline.
80.36-80.39 [Reserved]

                     Subpart D_Reformulated Gasoline

80.40 Fuel certification procedures.
80.41 Standards and requirements for compliance.
80.42 Simple emissions model.
80.43-80.44 [Reserved]
80.45 Complex emissions model.
80.46 Measurement of reformulated gasoline fuel parameters.
80.47 [Reserved]
80.48 Augmentation of the complex emission model by vehicle testing.
80.49 Fuels to be used in augmenting the complex emission model through 
          vehicle testing.
80.50 General test procedure requirements for augmentation of the 
          emission models.
80.51 Vehicle test procedures.
80.52 Vehicle preconditioning.

[[Page 628]]

80.53-80.54 [Reserved]
80.55 Measurement methods for benzene and 1,3-butadiene.
80.56 Measurement methods for formaldehyde and acetaldehyde.
80.57-80.58 [Reserved]
80.59 General test fleet requirements for vehicle testing.
80.60 Test fleet requirements for exhaust emission testing.
80.61 [Reserved]
80.62 Vehicle test procedures to place vehicles in emitter group sub-
          fleets.
80.63-80.64 [Reserved]
80.65 General requirements for refiners and importers.
80.66 Calculation of reformulated gasoline properties.
80.67 Compliance on average.
80.68 Compliance surveys.
80.69 Requirements for downstream oxygenate blending.
80.70 Covered areas.
80.71 Descriptions of VOC-control regions.
80.72 Procedures for opting out of the covered areas.
80.73 Inability to produce conforming gasoline in extraordinary 
          circumstances.
80.74 Recordkeeping requirements.
80.75 Reporting requirements.
80.76 Registration of refiners, importers or oxygenate blenders.
80.77 Product transfer documentation.
80.78 Controls and prohibitions on reformulated gasoline.
80.79 Liability for violations of the prohibited activities.
80.80 Penalties.
80.81 Enforcement exemptions for California gasoline.
80.82 Butane blending.
80.83 Renewable oxygenate requirements.
80.84 Treatment of interface and transmix.
80.85-80.89 [Reserved]

                         Subpart E_Anti-Dumping

80.90 Conventional gasoline baseline emissions determination.
80.91 Individual baseline determination.
80.92 Baseline auditor requirements.
80.93 Individual baseline submission and approval.
80.94 Requirements for gasoline produced at foreign refineries.
80.95-80.100 [Reserved]
80.101 Standards applicable to refiners and importers.
80.102 [Reserved]
80.103 Registration of refiners and importers.
80.104 Recordkeeping requirements.
80.105 Reporting requirements.
80.106 Product transfer documents.
80.107-80.124 [Reserved]

                      Subpart F_Attest Engagements

80.125 Attest engagements.
80.126 Definitions.
80.127 Sample size guidelines.
80.128 Alternative agreed upon procedures for refiners and importers.
80.129 [Reserved]
80.130 Agreed upon procedures reports.
80.131 Agreed upon procedures for GTAB, certain conventional gasoline 
          imported by truck, previously certified gasoline used to 
          produce gasoline, and butane blenders.
80.132 [Reserved]
80.133 Agreed-upon procedures for refiners and importers.
80.134-80.135 [Reserved]

                      Subpart G_Detergent Gasoline

80.140 Definitions.
80.141 Interim detergent gasoline program.
80.142-80.154 [Reserved]
80.155 Interim detergent program controls and prohibitions.
80.156 Liability for violations of the interim detergent program 
          controls and prohibitions.
80.157 Volumetric additive reconciliation (``VAR''), equipment 
          calibration, and recordkeeping requirements.
80.158 Product transfer documents (PTDs).
80.159 Penalties.
80.160 Exemptions.
80.161 Detergent additive certification program.
80.162 Additive compositional data.
80.163 Detergent certification options.
80.164 Certification test fuels.
80.165 Certification test procedures and standards.
80.166 Carburetor deposit control performance test and test fuel 
          guidelines.
80.167 Confirmatory testing.
80.168 Detergent certification program controls and prohibitions.
80.169 Liability for violations of the detergent certification program 
          controls and prohibitions.
80.170 Volumetric additive reconciliation (VAR), equipment calibration, 
          and recordkeeping requirements.
80.171 Product transfer documents (PTDs).
80.172 Penalties.
80.173 Exemptions.
80.174 Addresses.

                        Subpart H_Gasoline Sulfur

                           General Information

80.180-80.185 [Reserved]
80.190 Who must register with EPA under the sulfur program?

[[Page 629]]

                        Gasoline Sulfur Standards

80.195 What are the gasoline sulfur standards for refiners and 
          importers?
80.200 What gasoline is subject to the sulfur standards and 
          requirements?
80.205 How is the annual refinery or importer average and corporate pool 
          average sulfur level determined?
80.210 What sulfur standards apply to gasoline downstream from 
          refineries and importers?
80.211 What are the requirements for treating imported gasoline as 
          blendstock?
80.212 What requirements apply to oxygenate blenders?
80.213 What alternative sulfur standards and requirements apply to 
          transmix processors and transmix blenders?
80.214 [Reserved]

                       Geographic Phase-In Program

80.215 What is the scope of the geographic phase-in program?
80.216 What standards apply to gasoline produced or imported for use in 
          the GPA?
80.217 How does a refiner or importer apply for the GPA standards?
80.218 [Reserved]
80.219 Designation and downstream requirements for GPA gasoline.
80.220 What are the downstream standards for GPA gasoline?

                           Hardship Provisions

80.225 What is the definition of a small refiner?
80.230 Who is not eligible for the hardship provisions for small 
          refiners?
80.235 How does a refiner obtain approval as a small refiner?
80.240 What are the small refiner gasoline sulfur standards?
80.245 How does a small refiner apply for a sulfur baseline?
80.250 How is the small refiner sulfur baseline and volume determined?
80.255 Compliance plans and demonstration of commitment to produce low 
          sulfur gasoline.
80.260 What are the procedures and requirements for obtaining a hardship 
          extension?
80.265 How will the EPA approve or disapprove a hardship extension 
          application?
80.270 Can a refiner seek temporary relief from the requirements of this 
          subpart?

                        Allotment Trading Program

80.271 How can a small refiner obtain an adjustment of its 2004-2007 
          per-gallon cap standard?
80.275 How are allotments generated and used?

    Averaging, Banking and Trading (ABT) Program--General Information

80.280 [Reserved]
80.285 Who may generate credits under the ABT program?
80.290 How does a refiner apply for a sulfur baseline?

                   ABT Program--Baseline Determination

80.295 How is a refinery sulfur baseline determined?
80.300 [Reserved]

                     ABT Program--Credit Generation

80.305 How are credits generated during the time period 2000 through 
          2003?
80.310 How are credits generated beginning in 2004?

                         ABT Program--Credit Use

80.315 How are credits used and what are the limitations on credit use?
80.320-80.325 [Reserved]

 Sampling, Testing and Retention Requirements for Refiners and Importers

80.330 What are the sampling and testing requirements for refiners and 
          importers?
80.335 What gasoline sample retention requirements apply to refiners and 
          importers?
80.340 What standards and requirements apply to refiners producing 
          gasoline by blending blendstocks into previously certified 
          gasoline (PCG)?
80.345 [Reserved]
80.350 What alternative sulfur standards and requirements apply to 
          importers who transport gasoline by truck?
80.355 [Reserved]

                Recordkeeping and Reporting Requirements

80.360 [Reserved]
80.365 What records must be kept?
80.370 What are the sulfur reporting requirements?
80.371-80.373 [Reserved]

                               Exemptions

80.374 What if a refiner or importer is unable to produce gasoline 
          conforming to the requirements of this subpart?
80.375 What requirements apply to California gasoline?
80.380 What are the requirements for obtaining an exemption for gasoline 
          used for research, development or testing purposes?
80.382 What requirements apply to gasoline for use in American Samoa, 
          Guam and the Commonwealth of the Northern Mariana Islands?

[[Page 630]]

                          Violation Provisions

80.385 What acts are prohibited under the gasoline sulfur program?
80.390 What evidence may be used to determine compliance with the 
          prohibitions and requirements of this subpart and liability 
          for violations of this subpart?
80.395 Who is liable for violations under the gasoline sulfur program?
80.400 What defenses apply to persons deemed liable for a violation of a 
          prohibited act?
80.405 What penalties apply under this subpart?

    Provisions for Foreign Refiners With Individual Sulfur Baselines

80.410 What are the additional requirements for gasoline produced at 
          foreign refineries having individual small refiner sulfur 
          baselines, foreign refineries granted temporary relief under 
          Sec. 80.270, or baselines for generating credits during 2000 
          through 2003?

                           Attest Engagements

80.415 What are the attest engagement requirements for gasoline sulfur 
          compliance applicable to refiners and importers?

  Subpart I_Motor Vehicle, Nonroad, Locomotive, and Marine Diesel Fuel

                           General Information

80.500 What are the implementation dates for the motor vehicle diesel 
          fuel sulfur control program?
80.501 What fuel is subject to the provisions of this subpart?
80.502 What definitions apply for purposes of this subpart?
80.503-80.509 [Reserved]
80.510 What are the standards and marker requirements for NRLM diesel 
          fuel?
80.511 What are the per-gallon and marker requirements that apply to 
          NRLM diesel fuel and heating oil downstream of the refiner or 
          importer?
80.512 May an importer treat diesel fuel as blendstock?
80.513 What provisions apply to transmix processing facilities?
80.514-80.519 [Reserved]

          Motor Vehicle Diesel Fuel Standards and Requirements

80.520 What are the standards and dye requirements for motor vehicle 
          diesel fuel?
80.521 What are the standards and identification requirements for diesel 
          fuel additives?
80.522 May used motor oil be dispensed into diesel motor vehicles or 
          nonroad diesel engines?
80.523 [Reserved]
80.524 What sulfur content standard applies to motor vehicle diesel fuel 
          downstream of the refinery or importer?
80.525 What requirements apply to kerosene blenders?
80.526 [Reserved]
80.527 Under what conditions may motor vehicle diesel fuel subject to 
          the 15 ppm sulfur standard be downgraded to motor vehicle 
          diesel fuel subject to the 500 ppm sulfur standard?
80.528-80.529 [Reserved]

                       Temporary Compliance Option

80.530 Under what conditions can 500 ppm motor vehicle diesel fuel be 
          produced or imported after May 31, 2006?
80.531 How are motor vehicle diesel fuel credits generated?
80.532 How are motor vehicle diesel fuel credits used and transferred?
80.533 How does a refiner or importer apply for a motor vehicle or non-
          highway baseline for the generation of NRLM credits or the use 
          of the NRLM small refiner compliance options?
80.534 [Reserved]
80.535 How are NRLM diesel fuel credits generated?
80.536 How are NRLM diesel fuel credits used and transferred?
80.537-80.539 [Reserved]

                     Geographic Phase-In Provisions

80.540 How may a refiner be approved to produce gasoline under the GPA 
          gasoline sulfur standards in 2007 and 2008?
80.541-80.549 [Reserved]

                    Small Refiner Hardship Provisions

80.550 What is the definition of a motor vehicle diesel fuel small 
          refiner or a NRLM diesel fuel small refiner under this 
          subpart?
80.551 How does a refiner obtain approval as a small refiner under this 
          subpart?
80.552 What compliance options are available to motor vehicle diesel 
          fuel small refiners?
80.553 Under what conditions may the small refiner gasoline sulfur 
          standards be extended for a small refiner of motor vehicle 
          diesel fuel?
80.554 What compliance options are available to NRLM diesel fuel small 
          refiners?
80.555 What provisions are available to a large refiner that acquires a 
          small refiner or one or more of its refineries?
80.556-80.559 [Reserved]

                        Other Hardship Provisions

80.560 How can a refiner seek temporary relief from the requirements of 
          this subpart in case of extreme hardship circumstances?

[[Page 631]]

80.561 How can a refiner or importer seek temporary relief from the 
          requirements of this subpart in case of extreme unforseen 
          circumstances?
80.562-80.569 [Reserved]

                          Labeling Requirements

80.570 What labeling requirements apply to retailers and wholesale 
          purchaser-consumers of diesel fuel beginning June 1, 2006?
80.571 What labeling requirements apply to retailers and wholesale 
          purchaser-consumers of NRLM diesel fuel or heating oil 
          beginning June 1, 2007?
80.572 What labeling requirements apply to retailers and wholesale 
          purchaser-consumers of NR and NRLM diesel fuel and heating oil 
          beginning June 1, 2010?
80.573 What labeling requirements apply to retailers and wholesale 
          purchaser-consumers of NRLM diesel fuel and heating oil 
          beginning June 1, 2012?
80.574 What labeling requirements apply to retailers and wholesale 
          purchaser-consumers of NRLM diesel fuel, or heating oil 
          beginning June 1, 2014?
80.575-80.579 [Reserved]

                          Sampling and Testing

80.580 What are the sampling and testing methods for sulfur?
80.581 What are the batch testing and sample retention requirements for 
          motor vehicle and NRLM diesel fuel?
80.582 What are the sampling and testing methods for the fuel marker?
80.583 What alternative sampling and testing requirements apply to 
          importers who transport motor vehicle diesel fuel or NRLM 
          diesel fuel by truck or rail car?
80.584 What are the precision and accuracy criteria for approval of test 
          methods for determining the sulfur content of motor vehicle 
          and NRLM diesel fuel?
80.585 What is the process for approval of a test method for determining 
          the sulfur content of diesel?
80.586 What are the record retention requirements for test methods 
          approved under this subpart?
80.587-80.589 [Reserved]

                Recordkeeping and Reporting Requirements

80.590 What are the product transfer document requirements for motor 
          vehicle diesel fuel, NRLM diesel fuel, heating oil and other 
          distillates?
80.591 What are the product transfer document requirements for additives 
          to be used in diesel fuel?
80.592 What records must be kept by entities in the motor vehicle diesel 
          fuel and diesel fuel additive distribution systems?
80.593 What are the reporting requirements for refiners and importers of 
          motor vehicle diesel fuel subject to temporary refiner relief 
          standards?
80.594 What are the pre-compliance reporting requirements for motor 
          vehicle diesel fuel?
80.595 How does a small or GPA refiner apply for a motor vehicle diesel 
          fuel volume baseline for the purpose of extending their 
          gasoline sulfur standards?
80.596 How is a refinery motor vehicle diesel fuel volume baseline 
          calculated?
80.597 What are the registration requirements?
80.598 What are the designation requirements for refiners, importers, 
          and distributors?
80.599 How do I calculate volume balances for designation purposes?
80.600 What records must be kept for purposes of the designate and track 
          provisions?
80.601 What are the reporting requirements for purposes of the designate 
          and track provisions?
80.602 What records must be kept by entities in the NRLM diesel fuel and 
          diesel fuel additive production, importation, and distribution 
          systems?
80.603 What are the pre-compliance reporting requirements for NRLM 
          diesel fuel?
80.604 What are the annual reporting requirements for refiners and 
          importers of NRLM diesel fuel?

                               Exemptions

80.605 [Reserved]
80.606 What national security exemption applies to distillate fuel?
80.607 What are the requirements for obtaining an exemption for diesel 
          fuel used for research, development or testing purposes?
80.608 What requirements apply to diesel fuel for use in the 
          Territories?
80.609 [Reserved]

                          Violation Provisions

80.610 What acts are prohibited under the diesel fuel sulfur program?
80.611 What evidence may be used to determine compliance with the 
          prohibitions and requirements of this subpart and liability 
          for violations of this subpart?
80.612 Who is liable for violations of this subpart?
80.613 What defenses apply to persons deemed liable for a violation of a 
          prohibited act under this subpart?
80.614 What are the alternative defense requirements in lieu of Sec. 
          80.613(a)(1)(vi)?
80.615 What penalties apply under this subpart?

[[Page 632]]

80.616 What are the enforcement exemptions for California diesel 
          distributed within the State of California?
80.617 How may California diesel fuel be distributed or sold outside of 
          the State of California?
80.618-80.619 [Reserved]

 Provisions for Foreign Refiners and Importers for Motor Vehicle Diesel 
   Fuel Subject to a Temporary Compliance Option or Hardship Provision

80.620 What are the additional requirements for diesel fuel or 
          distillates produced by foreign refineries subject to a 
          temporary refiner compliance option, hardship provisions, or 
          motor vehicle or NRLM diesel fuel credit provisions?

                        Subpart J_Gasoline Toxics

                           General Information

80.800-80.805 [Reserved]
80.810 Who shall register with EPA under the gasoline toxics program?

                Gasoline Toxics Performance Requirements

80.815 What are the gasoline toxics performance requirements for 
          refiners and importers?
80.820 What gasoline is subject to the toxics performance requirements 
          of this subpart?
80.825 How is the refinery or importer annual average toxics value 
          determined?
80.830 What requirements apply to oxygenate blenders?
80.835 What requirements apply to butane blenders?
80.840 What requirements apply to transmix processors?
80.845 What requirements apply to California gasoline?
80.850 How is the compliance baseline determined?
80.855 What is the compliance baseline for refineries or importers with 
          insufficient data?
80.860-80.905 [Reserved]

                         Baseline Determination

80.910 How does a refiner or importer apply for a toxics baseline?
80.915 How are the baseline toxics value and the baseline toxics volume 
          determined?
80.920-80.980 [Reserved]

                Recordkeeping and Reporting Requirements

80.985 What records shall be kept?
80.990 What are the toxics reporting requirements?

                               Exemptions

80.995 What if a refiner or importer is unable to produce gasoline 
          conforming to the requirements of this subpart?
80.1000 What are the requirements for obtaining an exemption for 
          gasoline used for research, development or testing purposes?

                          Violation Provisions

80.1005 What acts are prohibited under the gasoline toxics program?
80.1010 [Reserved]
80.1015 Who is liable for violations under the gasoline toxics program?
80.1020 [Reserved]
80.1025 What penalties apply under this subpart?

    Provisions for Foreign Refiners With Individual Toxics Baselines

80.1030 What are the requirements for gasoline produced at foreign 
          refineries having individual refiner toxics baselines?

                           Attest Engagements

80.1035 What are the attest engagement requirements for gasoline toxics 
          compliance applicable to refiners and importers?
80.1040 [Reserved]

                          Additional Rulemaking

80.1045 What additional rulemaking will EPA conduct?

                    Subpart K_Renewable Fuel Standard

80.1100 How is the statutory default requirement for 2006 implemented?
80.1101 Definitions.
80.1102-80.1103 [Reserved]
80.1104 What are the implementation dates for the Renewable Fuel 
          Standard Program?
80.1105 What is the Renewable Fuel Standard?
80.1106 To whom does the Renewable Volume Obligation apply?
80.1107 How is the Renewable Volume Obligation calculated?
80.1108-80.1114 [Reserved]
80.1115 How are equivalence values assigned to renewable fuel?
80.1116-80.1124 [Reserved]
80.1125 Renewable Identification Numbers (RINs).
80.1126 How are RINs generated and assigned to batches of renewable fuel 
          by renewable fuel producers or importers?
80.1127 How are RINs used to demonstrate compliance?
80.1128 General requirements for RIN distribution.
80.1129 Requirements for separating RINs from volumes of renewable fuel.

[[Page 633]]

80.1130 Requirements for exporters of renewable fuels.
80.1131 Treatment of invalid RINs.
80.1132 Reported spillage of renewable fuel.
80.1133-80.1140 [Reserved]
80.1141 Small refinery exemption.
80.1142 What are the provisions for small refiners under the RFS 
          program?
80.1143 What are the opt-in provisions for noncontiguous states and 
          territories?
80.1144-80.1149 [Reserved]
80.1150 What are the registration requirements under the RFS program?
80.1151 What are the recordkeeping requirements under the RFS program?
80.1152 What are the reporting requirements under the RFS program?
80.1153 What are the product transfer document (PTD) requirements for 
          the RFS program?
80.1154 What are the provisions for renewable fuel producers and 
          importers who produce or import less than 10,000 gallons of 
          renewable fuel per year?
80.1155 What are the additional requirements for a producer of 
          cellulosic biomass ethanol or waste derived ethanol?
80.1156-80.1159 [Reserved]
80.1160 What acts are prohibited under the RFS program?
80.1161 Who is liable for violations under the RFS program?
80.1162 [Reserved]
80.1163 What penalties apply under the RFS program?
80.1164 What are the attest engagement requirements under the RFS 
          program?
80.1165 What are the additional requirements under this subpart for a 
          foreign small refiner?
80.1166 What are the additional requirements under this subpart for a 
          foreign producer of cellulosic biomass ethanol or waste 
          derived ethanol?
80.1167 What are the additional requirements under this subpart for a 
          foreign RIN owner?

                       Subpart L_Gasoline Benzene

80.1200-80.1219 [Reserved]

                           General Information

80.1220 What are the implementation dates for the gasoline benzene 
          program?
80.1225 Who must register with EPA under the gasoline benzene program?

                      Gasoline Benzene Requirements

80.1230 What are the gasoline benzene requirements for refiners and 
          importers?
80.1235 What gasoline is subject to the benzene requirements of this 
          subpart?
80.1236 What requirements apply to California gasoline?
80.1238 How is a refinery's or importer's average benzene concentration 
          determined?
80.1240 How is a refinery's or importer's compliance with the gasoline 
          benzene requirements of this subpart determined?

              Averaging, Banking and Trading (ABT) Program

80.1270 Who may generate benzene credits under the ABT program?
80.1275 How are early benzene credits generated?
80.1280 How are refinery benzene baselines calculated?
80.1285 How does a refiner apply for a benzene baseline?
80.1290 How are standard benzene credits generated?
80.1295 How are gasoline benzene credits used?

                           Hardship Provisions

80.1334 What are the requirements for early compliance with the gasoline 
          benzene program?
80.1335 Can a refiner seek relief from the requirements of this subpart?
80.1336 What if a refiner or importer cannot produce gasoline conforming 
          to the requirements of this subpart?

                        Small Refiner Provisions

80.1338 What criteria must be met to qualify as a small refiner for the 
          gasoline benzene requirements of this subpart?
80.1339 Who is not eligible for the provisions for small refiners?
80.1340 How does a refiner obtain approval as a small refiner?
80.1342 What compliance options are available to small refiners under 
          this subpart?
80.1343 What hardship relief provisions are available only to small 
          refiners?
80.1344 What provisions are available to a non-small refiner that 
          acquires one or more of a small refiner's refineries?

              Sampling, Testing and Retention Requirements

80.1347 What are the sampling and testing requirements for refiners and 
          importers?
80.1348 What gasoline sample retention requirements apply to refiners 
          and importers?

                Recordkeeping and Reporting Requirements

80.1350 What records must be kept?
80.1352 What are the pre-compliance reporting requirements for the 
          gasoline benzene program?
80.1354 What are the reporting requirements for the gasoline benzene 
          program?

[[Page 634]]

                           Attest Engagements

80.1356 What are the attest engagement requirements for gasoline benzene 
          compliance?

                        Violations and Penalties

80.1358 What acts are prohibited under the gasoline benzene program?
80.1359 What evidence may be used to determine compliance with the 
          prohibitions and requirements of this subpart and liability 
          for violations of this subpart?
80.1360 Who is liable for violations under the gasoline benzene program?
80.1361 What penalties apply under the gasoline benzene program?

                            Foreign Refiners

80.1363 What are the additional requirements under this subpart for 
          gasoline produced at foreign refineries?

Appendix A to Part 80--Test for the Determination of Phosphorus in 
          Gasoline
Appendix B to Part 80--Test Methods for Lead in Gasoline
Appendixes C-G to Part 80 [Reserved]

    Authority: 42 U.S.C. 7414, 7521(1), 7545 and 7601(a).

    Source: 38 FR 1255, Jan. 10, 1973, unless otherwise noted.

    Effective Date Note: At 59 FR 7716, Feb. 16, 1994, EPA published 
amendments to part 80 containing information collection and 
recordkeeping requirements, which will not become effective until 
approval has been given by the Office of Management and Budget.



                      Subpart A_General Provisions



Sec. 80.1  Scope.

    (a) This part prescribes regulations for the control and/or 
prohibition of fuels and additives for use in motor vehicles and motor 
vehicle engines. These regulations are based upon a determination by the 
Administrator that the emission product of a fuel or additive will 
endanger the public health, or will impair to a significant degree the 
performance of a motor vehicle emission control device in general use or 
which the Administrator finds has been developed to a point where in a 
reasonable time it would be in general use were such regulations 
promulgated; and certain other findings specified by the Act.
    (b) Nothing in this part is intended to preempt the ability of State 
or local governments to control or prohibit any fuel or additive for use 
in motor vehicles and motor vehicle engines which is not explicitly 
regulated by this part.

[38 FR 1255, Jan. 10, 1973, as amended at 38 FR 33741, Dec. 6, 1973; 42 
FR 25732, May 19, 1977]



Sec. 80.2  Definitions.

    As used in this part:
    (a) Act means the Clean Air Act, as amended (42 U.S.C. 1857 et 
seq.).
    (b) Administrator means the Administrator of the Environmental 
Protection Agency.
    (c) Gasoline means any fuel sold in any State \1\ for use in motor 
vehicles and motor vehicle engines, and commonly or commercially known 
or sold as gasoline.
---------------------------------------------------------------------------

    \1\ State means a State, the District of Columbia, the Commonwealth 
of Puerto Rico, the Virgin Islands, Guam, American Samoa and the 
Commonwealth of the Northern Mariana Islands.
---------------------------------------------------------------------------

    (d) Previously certified gasoline, or PCG, means gasoline or RBOB 
that previously has been included in a batch for purposes of complying 
with the standards in Subparts D, E, H, and J of this part, as 
appropriate.
    (e) Lead additive means any substance containing lead or lead 
compounds.
    (f) Previously designated diesel fuel or PDD means diesel fuel that 
has been previously designated and included by a refiner or importer in 
a batch for purposes of complying with the standards and requirements of 
subpart I of this part.
    (g) Unleaded gasoline means gasoline which is produced without the 
use of any lead additive and which contains not more than 0.05 gram of 
lead per gallon and not more than 0.005 gram of phosphorus per gallon.
    (h) Refinery means any facility, including but not limited to, a 
plant, tanker truck, or vessel where gasoline or diesel fuel is 
produced, including any facility at which blendstocks are combined to 
produce gasoline or diesel fuel, or at which blendstock is added to 
gasoline or diesel fuel.
    (i) Refiner means any person who owns, leases, operates, controls, 
or supervises a refinery.
    (j) Retail outlet means any establishment at which gasoline, diesel 
fuel,

[[Page 635]]

methanol, natural gas or liquified petroleum gas is sold or offered for 
sale for use in motor vehicles or nonroad engines, including locomotive 
engines or marine engines.
    (k) Retailer means any person who owns, leases, operates, controls, 
or supervises a retail outlet.
    (l) Distributor means any person who transports or stores or causes 
the transportation or storage of gasoline or diesel fuel at any point 
between any gasoline or diesel fuel refinery or importer's facility and 
any retail outlet or wholesale purchaser-consumer's facility.
    (m) Lead additive manufacturer means any person who produces a lead 
additive or sells a lead additive under his own name.
    (n) Reseller means any person who purchases gasoline or diesel fuel 
identified by the corporate, trade, or brand name of a refiner from such 
refiner or a distributor and resells or transfers it to retailers or 
wholesale purchaser-consumers displaying the refiner's brand, and whose 
assets or facilities are not substantially owned, leased, or controlled 
by such refiner.
    (o) Wholesale purchaser-consumer means any person that is an 
ultimate consumer of gasoline, diesel fuel, methanol, natural gas, or 
liquified petroleum gas and which purchases or obtains gasoline, diesel 
fuel, natural gas or liquified petroleum gas from a supplier for use in 
motor vehicles or nonroad engines, including locomotive engines or 
marine engines and, in the case of gasoline, diesel fuel, methanol or 
liquified petroleum gas, receives delivery of that product into a 
storage tank of at least 550-gallon capacity substantially under the 
control of that person.
    (p)-(q) [Reserved]
    (r) Importer means a person who imports gasoline, gasoline blending 
stocks or components, or diesel fuel from a foreign country into the 
United States (including the Commonwealth of Puerto Rico, the Virgin 
Islands, Guam, American Samoa, and the Northern Mariana Islands).
    (s) Gasoline blending stock, blendstock, or component means any 
liquid compound which is blended with other liquid compounds to produce 
gasoline.
    (t) Carrier means any distributor who transports or stores or causes 
the transportation or storage of gasoline or diesel fuel without taking 
title to or otherwise having any ownership of the gasoline or diesel 
fuel, and without altering either the quality or quantity of the 
gasoline or diesel fuel.
    (u) Ethanol blending plant means any refinery at which gasoline is 
produced solely through the addition of ethanol to gasoline, and at 
which the quality or quantity of gasoline is not altered in any other 
manner.
    (v) Ethanol blender means any person who owns, leases, operates, 
controls, or supervises an ethanol blending plant.
    (w) Cetane index or ``Calculated cetane index'' is a number 
representing the ignition properties of diesel fuel oils from API 
gravity and mid-boiling point as determined by ASTM standard method D 
976-80, entitled ``Standard Methods for Calculated Cetane Index of 
Distillate Fuels''. ASTM test method D 976-80 is incorporated by 
reference. 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. A copy may be obtained from the American Society for Testing 
and Materials, 1916 Race Street, Philadelphia, PA 19103. A copy may be 
inspected at the Air Docket Section (A-130), Room M-1500, U.S. 
Environmental Protection Agency, Docket No. A-86-03, 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.
    (x) Diesel fuel means any fuel sold in any State or Territory of the 
United States and suitable for use in diesel engines, and that is--
    (1) A distillate fuel commonly or commercially known or sold as No. 
1 diesel fuel or No. 2 diesel fuel;
    (2) A non-distillate fuel other than residual fuel with comparable 
physical and chemical properties (e.g., biodiesel fuel); or
    (3) A mixture of fuels meeting the criteria of paragraphs (1) and 
(2) of this definition.

[[Page 636]]

    (y) Motor vehicle diesel fuel means any diesel fuel or other 
distillate fuel that is used, intended for use, or made available for 
use in motor vehicles or motor vehicle engines.
    (z) Aromatic content is the aromatic hydrocarbon content in volume 
percent as determined by ASTM standard test method D 1319-03, entitled, 
``Standard Test Method for Hydrocarbon Types in Liquid Petroleum 
Products by Fluorescent Indicator Adsorption''. ASTM test method D 1319-
03 is incorporated by reference. This incorporation by reference was 
approved by the Director of the Federal Register in accordance 5 U.S.C. 
552(a) and 1 CFR part 51. Copies may be obtained from the American 
Society for Testing and Materials, 100 Barr Harbor Dr., West 
Conshohocken, PA 19428-2959. Copies may be inspected at the Air Docket, 
EPA/DC, EPA West, Room B102, 1301 Constitution Ave., NW., Washington, 
DC, 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.
    (aa) [Reserved]
    (bb) Sulfur percentage is the percentage of sulfur in diesel fuel by 
weight, as determined using the applicable sampling and testing 
methodologies set forth in Sec. 80.580.
    (cc) Designated Volatility Nonattainment Area means any area 
designated as being in nonattainment with the National Ambient Air 
Quality Standard for ozone pursuant to rulemaking under section 
107(d)(4)(A)(ii) of the Clean Air Act.
    (dd) Designated Volatility Attainment Area means an area not 
designated as being in nonattainment with the National Ambient Air 
Quality Standard for ozone pursuant to rulemaking under section 
107(d)(4)(A)(ii) of the Clean Air Act.
    (ee) Reformulated gasoline means any gasoline whose formulation has 
been certified under Sec. 80.40, and which meets each of the standards 
and requirements prescribed under Sec. 80.41.
    (ff) Conventional gasoline means any gasoline which has not been 
certified under Sec. 80.40.
    (gg) Batch of gasoline means a quantity of gasoline that is 
homogeneous with regard to those properties that are specified for 
conventional or reformulated gasoline.
    (hh) Covered area means each of the geographic areas specified in 
Sec. 80.70 in which only reformulated gasoline may be sold or dispensed 
to ultimate consumers.
    (ii) Reformulated gasoline credit means the unit of measure for the 
paper transfer of benzene content resulting from reformulated gasoline 
which contains less than 0.95 volume percent benzene.
    (jj) Oxygenate means any substance which, when added to gasoline, 
increases the oxygen content of that gasoline. Lawful use of any of the 
substances or any combination of these substances requires that they be 
``substantially similar'' under section 211(f)(1) of the Clean Air Act, 
or be permitted under a waiver granted by the Administrator under the 
authority of section 211(f)(4) of the Clean Air Act.
    (kk) Reformulated gasoline blendstock for oxygenate blending, or 
RBOB means a petroleum product which, when blended with a specified type 
and percentage of oxygenate, meets the definition of reformulated 
gasoline, and to which the specified type and percentage of oxygenate is 
added other than by the refiner or importer of the RBOB at the refinery 
or import facility where the RBOB is produced or imported.
    (ll) Oxygenate blending facility means any facility (including a 
truck) at which oxygenate is added to gasoline or blendstock, and at 
which the quality or quantity of gasoline is not altered in any other 
manner except for the addition of deposit control additives.
    (mm) Oxygenate blender means any person who owns, leases, operates, 
controls, or supervises an oxygenate blending facility, or who owns or 
controls the blendstock or gasoline used or the gasoline produced at an 
oxygenate blending facility.
    (nn) [Reserved]
    (oo) Liquefied petroleum gas means a liquid hydrocarbon fuel that is 
stored under pressure and is composed primarily of species that are 
gases at atmospheric conditions (temperature = 25

[[Page 637]]

[deg]C and pressure = 1 atm), excluding natural gas.
    (pp) Control area means a geographic area in which only oxygenated 
gasoline under the oxygenated gasoline program may be sold or dispensed, 
with boundaries determined by section 211(m) of the Act.
    (qq) Control period means the period during which oxygenated 
gasoline must be sold or dispensed in any control area, pursuant to 
section 211(m)(2) of the Act.
    (rr) Oxygenated gasoline means gasoline which contains a measurable 
amount of oxygenate.
    (ss) Tank truck means a truck and/or trailer used to transport or 
cause the transportation of gasoline or diesel fuel, that meets the 
definition of motor vehicle in section 216(2) of the Act.
    (tt) Natural gas means a fuel whose primary constituent is methane.
    (uu) Methanol means any fuel sold for use in motor vehicles and 
commonly known or commercially sold as methanol or MXX, where XX is the 
percent methanol (CH3OH) by volume.
    (vv) Opt-in area. An area which becomes a covered area under Sec. 
80.70 pursuant to section 211(k)(6) of the Clean Air Act.
    (ww) Gasoline Treated as Blendstock, or GTAB, means imported 
gasoline that is excluded from the import facility's compliance 
calculations, but is treated as blendstock in a related refinery that 
includes the GTAB in its refinery compliance calculations.
    (xx) Diesel fuel additive means any substance not composed solely of 
carbon and/or hydrogen, or of diesel blendstocks, that is added to, 
intended to be added to, used in, or offered for use in motor vehicle 
diesel fuel or NRLM diesel fuel or in diesel motor vehicle or diesel 
NRLM engine fuel systems subsequent to the production of diesel fuel by 
processing crude oil from refinery processing units.
    (yy)-(zz) [Reserved]
    (aaa) Distillate fuel means diesel fuel and other petroleum fuels 
that can be used in engines that are designed for diesel fuel. For 
example, jet fuel, heating oil, kerosene, No. 4 fuel, DMX, DMA, DMB, and 
DMC are distillate fuels; and natural gas, LPG, gasoline, and residual 
fuel are not distillate fuels. Blends containing residual fuel may be 
distillate fuels.
    (bbb) Residual fuel means a petroleum fuel that can only be used in 
diesel engines if it is preheated before injection. For example, No. 5 
fuels, No. 6 fuels, and RM grade marine fuels are residual fuels. Note: 
Residual fuels do not necessarily require heating for storage or 
pumping.
    (ccc) Heating Oil means any 1, 2, or non-petroleum 
diesel blend that is sold for use in furnaces, boilers, stationary 
diesel engines, and similar applications and which is commonly or 
commercially known or sold as heating oil, fuel oil, and similar trade 
names, and that is not jet fuel, kerosene, or MVNRLM diesel fuel.
    (ddd) Jet fuel means any distillate fuel used, intended for use, or 
made available for use in aircraft.
    (eee) Kerosene means any No.1 distillate fuel commonly or 
commercially sold as kerosene.
    (fff) #1D means the distillate fuel classification relating to ``No. 
1-D'' diesel fuels as described in ASTM D 975-04. The Director of the 
Federal Register approved the incorporation by reference of ASTM D 975-
04, Standard Specification for Diesel Fuel Oils, as prescribed in 5 
U.S.C. 552(a) and 1 CFR part 51. Anyone may purchase copies of this 
standard from the American Society for Testing and Materials, 100 Barr 
Harbor Dr., West Conshohocken, PA 19428. Anyone may inspect copies at 
the U.S. EPA, Air and Radiation Docket and Information Center, 1301 
Constitution Ave., NW., Room B102, EPA West Building, 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.
    (ggg) #2D means the distillate fuel classification relating to ``No. 
2-D'' diesel fuels as described in ASTM D 975-04.
    (hhh)-(jjj) [Reserved]
    (kkk) Nonroad diesel engine means an engine that is designed to 
operate with diesel fuel that meets the definition of

[[Page 638]]

nonroad engine in 40 CFR 1068.30, including locomotive and marine diesel 
engines.
    (lll) Locomotive engine means an engine used in a locomotive as 
defined under 40 CFR 92.2.
    (mmm) Marine engine and Category 3 have the meanings given under 40 
CFR 94.2.
    (nnn) Nonroad, locomotive, or marine (NRLM) diesel fuel means any 
diesel fuel or other distillate fuel that is used, intended for use, or 
made available for use, as a fuel in any nonroad diesel engines, 
including locomotive and marine diesel engines, except the following: 
Distillate fuel with a T90 greater than 700 [deg]F that is used only in 
Category 2 and 3 marine engines is not NRLM diesel fuel. Use the 
distillation test method specified in 40 CFR 1065.1010 to determine the 
T90 of the fuel. NR diesel fuel and LM diesel fuel are subcategories of 
NRLM diesel fuel.
    (ooo) Nonroad (NR) diesel fuel means any NRLM diesel fuel that is 
not ``locomotive or marine (LM) diesel fuel.''
    (ppp) Locomotive or marine (LM) diesel fuel means any diesel fuel or 
other distillate fuel that is used, intended for use, or made available 
for use, as a fuel in locomotive or marine diesel engines, except for 
the following fuels:
    (1) Fuel that is also used, intended for use, or made available for 
use in motor vehicle engines or nonroad engines other than locomotive 
and marine diesel engines is not LM diesel fuel.
    (2) Distillate fuel with a T90 greater than 700 [deg]F that is used 
only in Category 2 and 3 marine engines is not LM diesel fuel. Use the 
distillation test method specified in 40 CFR 1065.1010 to determine the 
T90 of the fuel.
    (qqq) MVNRLM diesel fuel means any diesel fuel or other distillate 
fuel that meets the definition of motor vehicle (MV) or nonroad, 
locomotive, or marine (NRLM) diesel fuel. Motor vehicle diesel fuel, 
NRLM diesel fuel, NR diesel fuel, and LM diesel fuel are subcategories 
of MVNRLM diesel fuel.
    (rrr) Solvent yellow 124 means N-ethyl-N-[2-[1-(2-
methylpropoxy)ethoxyl]-4-phenylazo]-benzeneamine.
    (sss) Non-petroleum diesel (NP diesel) means a diesel fuel that 
contains at least 80 percent mono-alkyl esters of long chain fatty acids 
derived from vegetable oils or animal fats.

(Sec. 211, (Sec. 223, Pub. L. 95-95, 91 Stat. 764, 42 U.S.C. 7545(g)) 
and sec. 301(a) 42 U.S.C. 7602(a), formerly 42 U.S.C. 1857g(a)) of the 
Clean Air Act, as amended)

[38 FR 1255, Jan. 10, 1973]

    Editorial Note: For Federal Register citations affecting Sec. 80.2, 
see the List of CFR Sections Affected, which appears in the Finding Aids 
section of the printed volume and on GPO Access.



Sec. 80.3  Test methods.

    The lead and phosphorus content of gasoline shall be determined in 
accordance with test methods set forth in the appendices to this part.

[47 FR 765, Jan. 7, 1982]



Sec. 80.4  Right of entry; tests and inspections.

    The Administrator or his authorized representative, upon 
presentation of appropriate credentials, shall have a right to enter 
upon or through any refinery, retail outlet, wholesale purchaser-
consumer facility, or detergent manufacturer facility; or the premises 
or property of any gasoline or detergent distributor, carrier, or 
importer; or any place where gasoline or detergent is stored; and shall 
have the right to make inspections, take samples, obtain information and 
records, and conduct tests to determine compliance with the requirements 
of this part.

[61 FR 35356, July 5, 1996]



Sec. 80.5  Penalties.

    Any person who violates these regulations 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. Any violation with respect to a 
regulation proscribed under section 211(c), (k), (l) or (m) of the Act 
which establishes a regulatory standard based upon a multi-day averaging 
period shall constitute a separate day of violation for each and every 
day in the averaging period. Civil penalties

[[Page 639]]

shall be assessed in accordance with section 205(b) and (c) of the Act.

[58 FR 65554, Dec. 15, 1993]



Sec. 80.7  Requests for information.

    (a) When the Administrator, the Regional Administrator, or their 
delegates have reason to believe that a violation of section 211(c) or 
section 211(n) of the Act and the regulations thereunder has occurred, 
they may require any refiner, distributor, wholesale purchaser-consumer, 
or retailer to report the following information regarding receipt, 
transfer, delivery, or sale of gasoline represented to be unleaded 
gasoline and to allow the reproduction of such information at all 
reasonable times.
    (1) For any bulk shipment of gasoline represented to be unleaded 
gasoline which is transferred, sold, or delivered within the previous 6 
months by a refiner or a distributor to a distributor, wholesale 
purchaser-consumer or a retail outlet, the refiner or distributor shall 
maintain and provide the following information as applicable:
    (i) Business or corporate name and address of distributors, 
wholesale purchaser-consumers or retail outlets to which the gasoline 
has been transferred, sold, or delivered.
    (ii) Quantity of gasoline involved.
    (iii) Date of delivery.
    (iv) Storage location of gasoline prior to transit via delivery 
vessel (e.g., location of a bulk terminal).
    (v) Business or corporate name and address of the person who 
delivered the gasoline.
    (vi) Identification of delivery vessel (e.g., truck number). This 
information shall be supplied by the person in paragraph (a)(1)(v) of 
this section who performed the delivery, e.g., common or contract 
carrier.
    (2) For any bulk shipment of gasoline represented to be unleaded 
gasoline received by a retail outlet or a wholesale-purchaser-consumer 
facility within the previous 6 months, whether by purchase or otherwise, 
the retailer or wholesale purchaser-consumer shall maintain 
accessibility to and provide the following information:
    (i) Business or corporate name and address of the distributor.
    (ii) Quantity of gasoline received.
    (iii) Date of receipt.
    (b) Upon request by the Administrator, the Regional Administrator, 
or their delegates, any retailer shall provide documentation of his 
annual total sales volume in gallons of gasoline for each retail outlet 
for each calendar year beginning with 1971.
    (c) Any refiner, distributor, wholesale purchaser-consumer, 
retailer, or importer shall provide such other information as the 
Administrator or his authorized representative may reasonably require to 
enable him to determine whether such refiner, distributor, wholesale 
purchaser-consumer, retailer, or importer has acted or is acting in 
compliance with sections 211(c) and 211(n) of the Act and the 
regulations thereunder and shall, upon request of the Administrator or 
his authorized representative, produce and allow reproduction of any 
relevant records at all reasonable times. Such information may include 
but is not limited to records of unleaded gasoline inventory at a 
wholesale purchaser-consumer facility or a retail outlet, unleaded pump 
meter readings at a wholesale purchaser-consumer facility or a retail 
outlet, and receipts providing the date of acquisition of signs, labels, 
and nozzles required by Sec. 80.22. No person shall be required to 
furnish information requested under this paragraph if he can establish 
that such information is not maintained in the normal course of his 
business.

(Secs. 211, 301, Clean Air Act, as amended (42 U.S.C. 1857f-6c, 1857g))

[40 FR 36336, Aug. 20, 1975, as amended at 42 FR 45307, Sept. 9, 1977; 
47 FR 49332, Oct. 29, 1982; 61 FR 3837, Feb. 2, 1996]



Sec. 80.8  Sampling methods for gasoline and diesel fuel.

    The sampling methods specified in this section shall be used to 
collect samples of gasoline and diesel fuel for purposes of determining 
compliance with the requirements of this part.
    (a) Manual sampling. Manual sampling of tanks and pipelines shall be 
performed according to the applicable procedures specified in American 
Society for Testing and Materials (ASTM) method D 4057-95(2000), 
entitled

[[Page 640]]

``Standard Practice for Manual Sampling of Petroleum and Petroleum 
Products.''
    (b) Automatic sampling. Automatic sampling of petroleum products in 
pipelines shall be performed according to the applicable procedures 
specified in ASTM method D 4177-95(2000), entitled ``Standard Practice 
for Automatic Sampling of Petroleum and Petroleum Products.''
    (c) Sampling and sample handling for volatility measurement. Samples 
to be analyzed for Reid Vapor Pressure (RVP) shall be collected and 
handled according to the applicable procedures in ASTM method D 5842-
95(2000), entitled ``Standard Practice for Sampling and Handling of 
Fuels for Volatility Measurement.''
    (d) Sample compositing. Composite samples shall be prepared using 
the applicable procedures in ASTM method D 5854-96(2000), entitled 
``Standard Practice for Mixing and Handling of Liquid Samples of 
Petroleum and Petroleum Products.''
    (e) Incorporations by reference. ASTM standard practices D 4057-
95(2000), D 4177-95(2000), D 5842-95(2000), and D 5854-96(2000), are 
incorporated by reference. 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. Copies may be obtained from the 
American Society for Testing and Materials, 100 Barr Harbor Dr., West 
Conshohocken, PA 19428-2959. Copies may be inspected at the Air Docket 
Section (LE-131), room M-1500, U.S. Environmental Protection Agency, 
Docket No. A-97-03, 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.

[67 FR 8736, Feb. 26, 2002]



Sec. 80.9  Rounding a test result for determining conformance with a fuels standard.

    (a) For purposes of determining compliance with the fuel standards 
of 40 CFR part 80, a test result will be rounded to the nearest unit of 
significant digits specified in the applicable fuel standard in 
accordance with the rounding method described in the ASTM standard 
practice, ASTM E 29-02[isin]1, entitled, ``Standard Practice 
for Using Significant Digits in Test Data to Determine Conformance with 
Specifications''.
    (b) ASTM standard practice, E 29-02[isin]1 is 
incorporated by reference. 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. A copy may be obtained from the American 
Society for Testing and Materials, 100 Barr Harbor Dr., West 
Conshohocken, PA 19428-2959. Copies may be inspected at the Air Docket, 
EPA/DC, EPA West, Room B102, 1301 Constitution Ave., NW., Washington, 
DC, 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.

[71 FR 16499, Apr. 3, 2006]



                   Subpart B_Controls and Prohibitions



Sec. Sec. 80.20-80.21  [Reserved]



Sec. 80.22  Controls and prohibitions.

    (a) After December 31, 1995, no person shall sell, offer for sale, 
supply, offer for supply, dispense, transport, or introduce into 
commerce gasoline represented to be unleaded gasoline unless such 
gasoline meets the defined requirements for unleaded gasoline in Sec. 
80.2(g); nor shall he dispense, or cause or allow the gasoline other 
than unleaded gasoline to be dispensed into any motor vehicle which is 
equipped with a gasoline tank filler inlet which is designed for the 
introduction of unleaded gasoline.
    (b) After December 31, 1995, no person shall sell, offer for sale, 
supply, offer for supply, dispense, transport, or introduce into 
commerce for use as fuel in any motor vehicle (as defined in Section 
216(2) of the Clean Air Act, 42 U.S.C. 7550(2)), any gasoline which is 
produced with the use of lead additives

[[Page 641]]

or which contains more than 0.05 gram of lead per gallon.
    (c)-(e) [Reserved]
    (f) Beginning January 1, 1996, every retailer and wholesale 
purchaser-consumer shall equip all gasoline pumps as follows:
    (1) [Reserved]
    (2) Each pump from which unleaded gasoline is dispensed into motor 
vehicles shall be equipped with a nozzle spout which meets the following 
specifications:
    (i) The outside diameter of the terminal end shall not be greater 
than 0.840 inch (2.134 centimeters);
    (ii) The terminal end shall have a straight section of at least 2.5 
inches (6.34 centimeters) in length; and
    (iii) The retaining spring shall terminate 3.0 inches (7.6 
centimeters) from the terminal end.
    (g)-(i) [Reserved]
    (j) After July 1, 1996 every retailer and wholesale purchaser-
consumer handling over 10,000 gallons (37,854 liters) of fuel per month 
shall limit each nozzle from which gasoline or methanol is introduced 
into motor vehicles to a maximum fuel flow rate not to exceed 10 gallons 
per minute (37.9 liters per minute). The flow rate may be controlled 
through any means in the pump/dispenser system, provided the nozzle flow 
rate does not exceed 10 gallons per minute (37.9 liters per minute). 
After January 1, 1998 this requirement applies to every retailer and 
wholesale purchaser-consumer. Any dispensing pump that is dedicated 
exclusively to heavy-duty vehicles, boats, or airplanes is exempt from 
this requirement.

[38 FR 1255, Jan. 10, 1973, as amended at 39 FR 16125, May 17, 1974; 39 
FR 43283, Dec. 12, 1974; 48 FR 4287, Jan. 31, 1983; 56 FR 13768, Apr. 4, 
1991; 58 FR 16019, Mar. 24, 1993; 61 FR 3837, Feb. 2, 1996; 61 FR 33039, 
June 26, 1996]



Sec. 80.23  Liability for violations.

    Liability for violations of paragraphs (a) and (b) of Sec. 80.22 
shall be determined as follows:
    (a)(1) Where the corporate, trade, or brand name of a gasoline 
refiner or any of its marketing subsidiaries appears on the pump stand 
or is displayed at the retail outlet or wholesale purchaser-consumer 
facility from which the gasoline was sold, dispensed, or offered for 
sale, the retailer or wholesale purchaser-consumer, the reseller (if 
any), and such gasoline refiner shall be deemed in violation. Except as 
provided in paragraph (b)(2) of this section, the refiner shall be 
deemed in violation irrespective of whether any other refiner, 
distributor, retailer, or wholesale purchaser-consumer or the employee 
or agent of any refiner, distributor, retailer, or wholesale purchaser-
consumer may have caused or permitted the violation.
    (2) Where the corporate, trade, or brand name of a gasoline refiner 
or any of its marketing subsidiaries does not appear on the pump stand 
and is not displayed at the retail outlet or wholesale purchaser-
consumer facility from which the gasoline was sold, dispensed, or 
offered for sale, the retailer or wholesale purchaser-consumer and any 
distributor who sold that person gasoline contained in the storage tank 
which supplied that pump at the time of the violation shall be deemed in 
violation.
    (b)(1) In any case in which a retailer or wholesale purchaser-
consumer and any gasoline refiner or distributor would be in violation 
under paragraph (a) (1) or (2) of this section, the retailer or 
wholesale purchaser-consumer shall not be liable if he can demonstrate 
that the violation was not caused by him or his employee or agent.
    (2) In any case in which a retailer or wholesale purchaser-consumer, 
a reseller (if any), and any gasoline refiner would be in violation 
under paragraph (a)(1) of this section, the refiner shall not be deemed 
in violation if he can demonstrate:
    (i) That the violation was not caused by him or his employee or 
agent, and
    (ii) That the violation was caused by an act in violation of law 
(other than the Act or this part), or an act of sabotage, vandalism, or 
deliberate commingling of gasoline which is produced with the use of 
lead additives or phosphorus additives with unleaded gasoline, whether 
or not such acts are violations of law in the jurisdiction where the 
violation of the requirements of this part occurred, or
    (iii) That the violation was caused by the action of a reseller or a 
retailer

[[Page 642]]

supplied by such reseller, in violation of a contractual undertaking 
imposed by the refiner on such reseller designed to prevent such action, 
and despite reasonable efforts by the refiner (such as periodic 
sampling) to insure compliance with such contractual obligation, or
    (iv) That the violation was caused by the action of a retailer who 
is supplied directly by the refiner (and not by a reseller), in 
violation of a contractual undertaking imposed by the refiner on such 
retailer designed to prevent such action, and despite reasonable efforts 
by the refiner (such as periodic sampling) to insure compliance with 
such contractual obligation, or
    (v) That the violation was caused by the action of a distributor 
subject to a contract with the refiner for transportation of gasoline 
from a terminal to a distributor, retailer or wholesale purchaser-
consumer, in violation of a contractual undertaking imposed by the 
refiner on such distributor designed to prevent such action, and despite 
reasonable efforts by the refiner (such as periodic sampling) to insure 
compliance with such contractual obligation, or
    (vi) That the violation was caused by a distributor (such as a 
common carrier) not subject to a contract with the refiner but engaged 
by him for transportation of gasoline from a terminal to a distributor, 
retailer or wholesale purchaser-consumer, despite reasonable efforts by 
the refiner (such as specification or inspection of equipment) to 
prevent such action, or
    (vii) That the violation occurred at a wholesale purchaser-consumer 
facility: Provided, however, That if such wholesale purchaser-consumer 
was supplied by a reseller, the refiner must demonstrate that the 
violation could not have been prevented by such reseller's compliance 
with a contractual undertaking imposed by the refiner on such reseller 
as provided in paragraph (b)(2)(iii) of this section.
    (viii) In paragraphs (b)(2)(ii) through (vi) hereof, the term ``was 
caused'' means that the refiner must demonstrate by reasonably specific 
showings by direct or circumstantial evidence that the violation was 
caused or must have been caused by another.
    (c) In any case in which a retailer or wholesale purchaser-consumer, 
a reseller, and any gasoline refiner would be in violation under 
paragraph (a)(1) of this section, the reseller shall not be deemed in 
violation if he can demonstrate that the violation was not caused by him 
or his employee or agent.
    (d) In any case in which a retailer or wholesale purchaser-consumer 
and any gasoline distributor would be in violation under paragraph 
(a)(2) of this section, the distributor will not be deemed in violation 
if he can demonstrate that the violation was not caused by him or his 
employee or agent.
    (e)(1) In any case in which a retailer or his employee or agent or a 
wholesale purchase-consumer or his employee or agent introduced gasoline 
other than unleaded gasoline into a motor vehicle which is equipped with 
a gasoline tank filler inlet designed for the introduction of unleaded 
gasoline, only the retailer or wholesale purchaser-consumer shall be 
deemed in violation.
    (2) [Reserved]

(Secs. 211, 301 of the Clean Air Act, as amended (42 U.S.C. 1857f-6c, 
1857g))

[38 FR 1255, Jan. 10, 1973, as amended at 39 FR 42360, Dec. 5, 1974; 39 
FR 43284, Dec. 12, 1974; 42 FR 45307, Sept. 9, 1977; 61 FR 3837, Feb. 2, 
1996]



Sec. 80.24  Controls applicable to motor vehicle manufacturers.

    (a) [Reserved]
    (b) The manufacturer of any motor vehicle equipped with an emission 
control device which the Administrator has determined will be 
significantly impaired by the use of gasoline other than unleaded 
gasoline shall manufacture such vehicle with each gasoline tank filler 
inlet having a restriction which prevents the insertion of a nozzle with 
a spout having a terminal end with an outside diameter of 0.930 inch 
(2.363 centimeters) or more and allows the insertion of a nozzle with a 
spout meeting the specifications of Sec. 80.22(f)(2).
    (c) A motorcycle, as defined at 40 CFR 86.402 for the applicable 
model

[[Page 643]]

year, is exempt from the requirements of paragraph (b) of this section.

[38 FR 26450, Sept. 21, 1973, as amended at 39 FR 34538, Sept. 26, 1974; 
46 FR 50472, Oct. 13, 1981; 48 FR 29692, June 28, 1983; 51 FR 33731, 
Sept. 22, 1986; 61 FR 3838, Feb. 2, 1996; 61 FR 8221, Mar. 4, 1996; 61 
FR 28766, June 6, 1996; 67 FR 36771, May 24, 2002]



Sec. 80.25  [Reserved]



Sec. 80.26  Confidentiality of information.

    Information obtained by the Administrator or his representatives 
pursuant to this part shall be treated, in so far as its confidentiality 
is concerned, in accordance with the provisions of 40 CFR part 2.

[38 FR 33741, Dec. 6, 1973]



Sec. 80.27  Controls and prohibitions on gasoline volatility.

    (a)(1) Prohibited activities in 1991. During the 1991 regulatory 
control periods, no refiner, importer, distributor, reseller, carrier, 
retailer or wholesale purchaser-consumer shall sell, offer for sale, 
dispense, supply, offer for supply, or transport gasoline whose Reid 
vapor pressure exceeds the applicable standard. As used in this section 
and Sec. 80.28, ``applicable standard'' means the standard listed in 
this paragraph for the geographical area and time period in which the 
gasoline is intended to be dispensed to motor vehicles or, if such area 
and time period cannot be determined, the standard listed in this 
paragraph that specifies the lowest Reid vapor pressure for the year in 
which the gasoline is being sampled. As used in this section and Sec. 
80.28, ``regulatory control periods'' mean June 1 to September 15 for 
retail outlets and wholesale purchaser-consumers and May 1 to September 
15 for all other facilities.

                                            Applicable Standards \1\
----------------------------------------------------------------------------------------------------------------
                     State                           May          June         July         Aug.        Sept.
----------------------------------------------------------------------------------------------------------------
Alabama........................................         10.5         10.5          9.5          9.5         10.5
Arizona:
    North of 34 degrees latitude and east of             9.5          9.0          9.0          9.5          9.5
     111 degrees longitude.....................
    All areas except North of 34 degrees                 9.5          9.0          9.0          9.0          9.5
     latitude and east of 111 degrees longitude
Arkansas.......................................         10.5         10.5          9.5          9.5         10.5
California: \2\
  North Coast..................................         10.5          9.5          9.5          9.5          9.5
  South Coast..................................          9.5          9.5          9.5          9.5          9.5
  Southeast....................................          9.5          9.5          9.5          9.5          9.5
  Interior.....................................          9.5          9.5          9.5          9.5          9.5
Colorado.......................................         10.5          9.5          9.5          9.5          9.5
Connecticut....................................         10.5         10.5         10.5         10.5         10.5
Delaware.......................................         10.5         10.5         10.5         10.5         10.5
District of Columbia...........................         10.5         10.5         10.5         10.5         10.5
Florida........................................         10.5         10.5         10.5         10.5         10.5
Georgia........................................         10.5         10.5          9.5          9.5         10.5
Idaho..........................................         10.5         10.5         10.5         10.5         10.5
Illinois:
  North of 40[deg] Latitude....................         10.5         10.5         10.5         10.5         10.5
  South of 40[deg] Latitude....................         10.5         10.5          9.5          9.5         10.5
Indiana........................................         10.5         10.5         10.5         10.5         10.5
Iowa...........................................         10.5         10.5         10.5         10.5         10.5
Kansas.........................................         10.5         10.5          9.5          9.5         10.5
Kentucky.......................................         10.5         10.5         10.5         10.5         10.5
Louisiana......................................         10.5         10.5          9.5          9.5         10.5
Maine..........................................         10.5         10.5         10.5         10.5         10.5
Maryland.......................................         10.5         10.5         10.5         10.5         10.5
Massachusetts..................................         10.5         10.5         10.5         10.5         10.5
Michigan.......................................         10.5         10.5         10.5         10.5         10.5
Minnesota......................................         10.5         10.5         10.5         10.5         10.5
Mississippi....................................         10.5         10.5          9.5          9.5         10.5
Missouri.......................................         10.5         10.5          9.5          9.5         10.5
Montana........................................         10.5         10.5         10.5         10.5         10.5
Nebraska.......................................         10.5         10.5         10.5         10.5         10.5
Nevada:
  North of 38[deg] Latitude....................         10.5          9.5          9.5          9.5          9.5
  South of 38[deg] Latitude....................          9.5          9.5          9.5          9.5          9.5
New Hampshire..................................         10.5         10.5         10.5         10.5         10.5
New Jersey.....................................         10.5         10.5         10.5         10.5         10.5

[[Page 644]]

 
New Mexico:
  North of 34[deg] Latitude....................          9.5          9.0          9.0          9.5          9.5
  South of 34[deg] Latitude....................          9.5          9.0          9.0          9.0          9.5
New York.......................................         10.5         10.5         10.5         10.5         10.5
North Carolina.................................         10.5         10.5          9.5          9.5         10.5
North Dakota...................................         10.5         10.5         10.5         10.5         10.5
Ohio...........................................         10.5         10.5         10.5         10.5         10.5
Oklahoma.......................................         10.5          9.5          9.5          9.5          9.5
Oregon:
  East of 122[deg] Longitude...................         10.5         10.5         10.5         10.5         10.5
  West of 122[deg] Longitude...................         10.5         10.5         10.5         10.5         10.5
Pennsylvania...................................         10.5         10.5         10.5         10.5         10.5
Rhode Island...................................         10.5         10.5         10.5         10.5         10.5
South Carolina.................................         10.5         10.5          9.5          9.5         10.5
South Dakota...................................         10.5         10.5         10.5         10.5         10.5
Tennessee......................................         10.5         10.5          9.5          9.5         10.5
Texas:
  East of 99[deg] Longitude....................          9.5          9.0          9.0          9.0          9.5
  West of 99[deg] Longitude....................          9.5          9.0          9.0          9.0          9.5
Utah...........................................         10.5          9.5          9.5          9.5          9.5
Vermont........................................         10.5         10.5         10.5         10.5         10.5
Virginia.......................................         10.5         10.5         10.5         10.5         10.5
Washington:
  East of 122[deg] Longitude...................         10.5         10.5         10.5         10.5         10.5
  West of 122[deg] Longitude...................         10.5         10.5         10.5         10.5         10.5
West Virginia..................................         10.5         10.5         10.5         10.5         10.5
Wisconsin......................................         10.5         10.5         10.5         10.5         10.5
Wyoming........................................         10.5         10.5         10.5         10.5         10.5
----------------------------------------------------------------------------------------------------------------
\1\ Standards are expressed in pounds per square inch (psi).
\2\ California areas include the following counties:
 North Coast--Alameda, Contra Costa, Del Norte, Humbolt, Lake, Marin, Mendocino, Monterey, Napa, San Benito, San
  Francisco, San Mateo, Santa Clara, Santa Cruz, Solano, Sonoma, and Trinity.
 Interior--Lassen, Modoc, Plumas, Sierra, Siskiyou, Alpine, Amador, Butte, Calaveras, Colusa, El Dorado, Fresno,
  Glenn, Kern (except that portion lying east of the Los Angeles County Aqueduct), Kings, Madera, Mariposa,
  Merced, Placer, Sacramento, San Joaquin, Shasta, Stanislaus, Sutter, Tehama, Tulare, Tuolumne, Yolo, Yuba, and
  Nevada.
 South Coast--Orange, San Diego, San Luis Obispo, Santa Barbara, Ventura, and Los Angeles (except that portion
  north of the San Gabriel mountain range and east of the Los Angeles County Aqueduct).
Southeast--Imperial, Riverside, San Bernardino, Los Angeles (that portion north of the San Gabriel mountain
  range and east of the Los Angeles County Aqueduct), Mono, Inyo, and Kern (that portion lying east of the Los
  Angeles County Aqueduct).

    (2) Prohibited activities in 1992 and beyond. During the 1992 and 
later high ozone seasons no person, including without limitation, no 
retailer or wholesale purchaser-consumer, and during the 1992 and later 
regulatory control periods, no refiner, importer, distributor, reseller, 
or carrier shall sell, offer for sale, dispense, supply, offer for 
supply, transport or introduce into commerce gasoline whose Reid vapor 
pressure exceeds the applicable standard. As used in this section and 
Sec. 80.28, ``applicable standard'' means:
    (i) 9.0 psi for all designated volatility attainment areas; and
    (ii) The standard listed in this paragraph for the state and time 
period in which the gasoline is intended to be dispensed to motor 
vehicles for any designated volatility nonattainment area within such 
State or, if such area and time period cannot be determined, the 
standard listed in this paragraph that specifies the lowest Reid vapor 
pressure for the year in which the gasoline is sampled. Designated 
volatility attainment and designated volatility nonattainment areas and 
their exact boundaries are described in 40 CFR part 81, or such part as 
shall later be designated for that purpose. As used in this section and 
Sec. 80.27, ``high ozone season'' means the period from June 1 to 
September 15 of any calendar year and ``regulatory control period'' 
means the period from May 1 to September 15 of any calendar year.

                               Applicable Standards \1\ 1992 and Subsequent Years
----------------------------------------------------------------------------------------------------------------
                     State                           May          June         July        August     September
----------------------------------------------------------------------------------------------------------------
Alabama........................................          9.0          7.8          7.8          7.8          7.8

[[Page 645]]

 
Arizona........................................          9.0          7.8          7.8          7.8          7.8
Arkansas.......................................          9.0          7.8          7.8          7.8          7.8
California.....................................          9.0          7.8          7.8          7.8          7.8
Colorado \2\...................................          9.0          7.8          7.8          7.8          7.8
Connecticut....................................          9.0          9.0          9.0          9.0          9.0
Delaware.......................................          9.0          9.0          9.0          9.0          9.0
District of Columbia...........................          9.0          7.8          7.8          7.8          7.8
Florida........................................          9.0          7.8          7.8          7.8          7.8
Georgia........................................          9.0          7.8          7.8          7.8          7.8
Idaho..........................................          9.0          9.0          9.0          9.0          9.0
Illinois.......................................          9.0          9.0          9.0          9.0          9.0
Indiana........................................          9.0          9.0          9.0          9.0          9.0
Iowa...........................................          9.0          9.0          9.0          9.0          9.0
Kansas.........................................          9.0          7.8          7.8          7.8          7.8
Kentucky.......................................          9.0          9.0          9.0          9.0          9.0
Louisiana:
    Grant Parish \4\...........................          9.0          9.0          9.0          9.0          9.0
    All other volatility nonattainment areas...          9.0          7.8          7.8          7.8          7.8
Maine..........................................          9.0          9.0          9.0          9.0          9.0
Maryland.......................................          9.0          7.8          7.8          7.8          7.8
Massachusetts..................................          9.0          9.0          9.0          9.0          9.0
Michigan.......................................          9.0          9.0          9.0          9.0          9.0
Minnesota......................................          9.0          9.0          9.0          9.0          9.0
Mississippi....................................          9.0          7.8          7.8          7.8          7.8
Missouri.......................................          9.0          7.8          7.8          7.8          7.8
Montana........................................          9.0          9.0          9.0          9.0          9.0
Nebraska.......................................          9.0          9.0          9.0          9.0          9.0
Nevada.........................................          9.0          7.8          7.8          7.8          7.8
New Hampshire..................................          9.0          9.0          9.0          9.0          9.0
New Jersey.....................................          9.0          9.0          9.0          9.0          9.0
New Mexico.....................................          9.0          7.8          7.8          7.8          7.8
New York.......................................          9.0          9.0          9.0          9.0          9.0
North Carolina.................................          9.0          7.8          7.8          7.8          7.8
North Dakota...................................          9.0          9.0          9.0          9.0          9.0
Ohio...........................................          9.0          9.0          9.0          9.0          9.0
Oklahoma.......................................          9.0          7.8          7.8          7.8          7.8
Oregon.........................................          9.0          7.8          7.8          7.8          7.8
Pennsylvania...................................          9.0          9.0          9.0          9.0          9.0
Rhode Island...................................          9.0          9.0          9.0          9.0          9.0
South Carolina \3\.............................          9.0          9.0          9.0          9.0          9.0
South Dakota...................................          9.0          9.0          9.0          9.0          9.0
Tennessee:.....................................
  Knox County..................................          9.0          9.0          9.0          9.0          9.0
  All other volatility nonattainment areas.....          9.0          7.8          7.8          7.8          7.8
Texas..........................................          9.0          7.8          7.8          7.8          7.8
Utah...........................................          9.0          7.8          7.8          7.8          7.8
Vermont........................................          9.0          9.0          9.0          9.0          9.0
Virginia.......................................          9.0          7.8          7.8          7.8          7.8
Washington.....................................          9.0          9.0          9.0          9.0          9.0
West Virginia..................................          9.0          9.0          9.0          9.0          9.0
Wisconsin......................................          9.0          9.0          9.0          9.0          9.0
Wyoming........................................          9.0          9.0          9.0          9.0          9.0
----------------------------------------------------------------------------------------------------------------
\1\ Standards are expressed in pounds per square inch (psi).
\2\ The standard for 1992 through 2001 in the Denver-Boulder area designated nonattainment for the 1-hour ozone
  NAAQS in 1991 (see 40 CFR 81.306) will be 9.0 for June 1 through September 15.
\3\ The standard for nonattainment areas in South Carolina from June 1 until September 15 in 1992 and 1993 was
  7.8 psi.
\4\ The standard for Grant Parish from June 1 until September 15 in 1992 through 2007 was 7.8 psi.

    (b) Determination of compliance. Compliance with the standards 
listed in paragraph (a) of this section shall be determined by the use 
of the sampling methodologies specified in Sec. 80.8 and the testing 
methodology specified in Sec. 80.46(c).
    (c) Liability. Liability for violations of paragraph (a) of this 
section shall be determined according to the provisions of Sec. 80.28. 
Where the terms refiner, importer, distributor, reseller, carrier, 
ethanol blender, retailer, or wholesale purchaser-consumer are expressed 
in the singular in Sec. 80.28, these terms shall include the plural.

[[Page 646]]

    (d) Special provisions for alcohol blends. (1) Any gasoline which 
meets the requirements of paragraph (d)(2) of this section shall not be 
in violation of this section if its Reid vapor pressure does not exceed 
the applicable standard in paragraph (a) of this section by more than 
one pound per square inch (1.0 psi).
    (2) In order to qualify for the special regulatory treatment 
specified in paragraph (d)(1) of this section, gasoline must contain 
denatured, anhydrous ethanol. The concentration of the ethanol, 
excluding the required denaturing agent, must be at least 9% and no more 
than 10% (by volume) of the gasoline. The ethanol content of the 
gasoline shall be determined by the use of one of the testing 
methodologies specified in Sec. 80.46(g). The maximum ethanol content 
shall not exceed any applicable waiver conditions under section 211(f) 
of the Clean Air Act.
    (3) Each invoice, loading ticket, bill of lading, delivery ticket 
and other document which accompanies a shipment of gasoline containing 
ethanol shall contain a legible and conspicuous statement that the 
gasoline being shipped contains ethanol and the percentage concentration 
of ethanol.
    (e) Testing exemptions. (1)(i) Any person may request a testing 
exemption by submitting an application that includes all the information 
listed in paragraphs (e)(3), (4), (5) and (6) of this section to:

Director (6406J), Field Operations and Support Division, U.S. 
Environmental Protection Agency, 1200 Pennsylvania Ave., NW., 
Washington, DC 20460

    (ii) For purposes of this section, ``testing exemption'' means an 
exemption from the requirements of Sec. 80.27(a) that is granted by the 
Administrator for the purpose of research or emissions certification.
    (2)(i) In order for a testing exemption to be granted, the applicant 
must demonstrate the following:
    (A) The proposed test program has a purpose that constitutes an 
appropriate basis for exemption;
    (B) The proposed test program necessitates the granting of an 
exemption;
    (C) The proposed test program exhibits reasonableness in scope; and
    (D) The proposed test program exhibits a degree of control 
consistent with the purpose of the program and the Environmental 
Protection Agency's (EPA's) monitoring requirements.
    (ii) Paragraphs (e)(3), (4), (5) and (6) of this section describe 
what constitutes a sufficient demonstration for each of the four 
elements in paragraphs (e)(2)(i) (A) through (D) of this section.
    (3) An appropriate purpose is limited to research or emissions 
certification. The testing exemption application must include a concise 
statement of the purpose(s) of the testing program.
    (4) With respect to the necessity that an exemption be granted, the 
applicant must demonstrate an inability to achieve the stated purpose in 
a practicable manner, during a period of the year in which the 
volatility regulations do not apply, or without performing or causing to 
be performed one or more of the prohibited activities under Sec. 
80.27(a). If any site of the proposed test program is located in an area 
that has been classified by the Administrator as a nonattainment area 
for purposes of the ozone national ambient air quality standard, the 
application must also demonstrate an inability to perform the test 
program in an area that is not so classified.
    (5) With respect to reasonableness, a test program must exhibit a 
duration of reasonable length, effect a reasonable number of vehicles or 
engines, and utilize a reasonable amount of high volatility fuel. In 
this regard, the testing exemption application must include:
    (i) An estimate of the program's duration;
    (ii) An estimate of the maximum number of vehicles or engines 
involved in the test program;
    (iii) The time or mileage duration of the test program;
    (iv) The range of volatility of the fuel (expressed in Reid Vapor 
Pressure (RVP)) expected to be used in the test program; and
    (v) The quantity of fuel which exceeds the applicable standard that 
is expected to be used in the test program.
    (6) With respect to control, a test program must be capable of 
affording EPA a monitoring capability. At a

[[Page 647]]

minimum, the testing exemption application must also include:
    (i) The technical nature of the test program;
    (ii) The site(s) of the test program (including the street address, 
city, county, State, and zip code);
    (iii) The manner in which information on vehicles and engines used 
in the test program will be recorded and made available to the 
Administrator;
    (iv) The manner in which results of the test program will be 
recorded and made available to the Administrator;
    (v) The manner in which information on the fuel used in the test 
program (including RVP level(s), name, address, telephone number, and 
contact person of supplier, quantity, date received from the supplier) 
will be recorded and made available to the Administrator;
    (vi) The manner in which the distribution pumps will be labeled to 
insure proper use of the test fuel;
    (vii) The name, address, telephone number and title of the person(s) 
in the organization requesting a testing exemption from whom further 
information on the request may be obtained; and
    (viii) The name, address, telephone number and title of the 
person(s) in the organization requesting a testing exemption who will be 
responsible for recording and making available to the Administrator the 
information specified in paragraphs (e)(6)(iii), (iv), and (v) of this 
section, and the location in which such information will be maintained.
    (7) A testing exemption will be granted by the Administrator upon a 
demonstration that the requirements of paragraphs (e)(2), (3), (4), (5) 
and (6) of this section have been met. The testing exemption will be 
granted in the form of a memorandum of exemption signed by the applicant 
and the Administrator (or his delegate), which shall include such terms 
and conditions as the Administrator determines necessary to monitor the 
exemption and to carry out the purposes of this section. Any violation 
of such a term or condition shall cause the exemption to be void.

[54 FR 11883, Mar. 22, 1989]

    Editorial Note: For Federal Register citations affecting Sec. 
80.27, see the List of CFR Sections Affected, which appears in the 
Finding Aids section of the printed volume and on GPO Access.



Sec. 80.28  Liability for violations of gasoline volatility 
controls and prohibitions.

    (a) Violations at refineries or importer facilities. Where a 
violation of the applicable standard set forth in Sec. 80.27 is 
detected at a refinery that is not an ethanol blending plant or at an 
importer's facility, the refiner or importer shall be deemed in 
violation.
    (b) Violations at carrier facilities. Where a violation of the 
applicable standard set forth in Sec. 80.27 is detected at a carrier's 
facility, whether in a transport vehicle, in a storage facility, or 
elsewhere at the facility, the following parties shall be deemed in 
violation:
    (1) The carrier, except as provided in paragraph (g)(1) of this 
section;
    (2) The refiner (if he is not an ethanol blender) at whose refinery 
the gasoline was produced or the importer at whose import facility the 
gasoline was imported, except as provided in paragraph (g)(2) of this 
section;
    (3) The ethanol blender (if any) at whose ethanol blending plant the 
gasoline was produced, except as provided in paragraph (g)(6) of this 
section; and
    (4) The distributor and/or reseller, except as provided in paragraph 
(g)(3) of this section.
    (c) Violations at branded distributor facilities, reseller 
facilities, or ethanol blending plants. Where a violation of the 
applicable standard set forth in Sec. 80.27 is detected at a 
distributor facility, a reseller facility, or an ethanol blending plant 
which is operating under the corporate, trade, or brand name of a 
gasoline refiner or any of its marketing subsidiaries, the following 
parties shall be deemed in violation:
    (1) The distributor or reseller, except as provided in paragraph 
(g)(3) or (g)(8) of this section;
    (2) The carrier (if any), if the carrier caused the gasoline to 
violate the applicable standard;
    (3) The refiner under whose corporate, trade, or brand name (or that 
of any of its marketing subsidiaries) the distributor, reseller, or 
ethanol blender is operating, except as provided in paragraph (g)(4) of 
this section; and

[[Page 648]]

    (4) The ethanol blender (if any) at whose ethanol blending plant the 
gasoline was produced, except as provided in paragraph (g)(6) or (g)(8) 
of this section.
    (d) Violations at unbranded distributor facilities or ethanol 
blending plants. Where a violation of the applicable standard set forth 
in Sec. 80.27 is detected at a distributor facility or an ethanol 
blending plant not operating under a refiner's corporate, trade, or 
brand name, or that of any of its marketing subsidiaries, the following 
parties shall be deemcd in violation:
    (1) The distributor, except as provided in paragraph (g)(3) or 
(g)(8) of this section;
    (2) The carrier (if any), if the carrier caused the gasoline to 
violate the applicable standard;
    (3) The refiner (if he is not an ethanol blender) at whose refinery 
the gasoline was produced or the importer at whose import facility the 
gasoline was imported, except as provided in paragraph (g)(2) of this 
section; and
    (4) The ethanol blender (if any) at whose ethanol blending plant the 
gasoline was produced, except as provided in paragraph (g)(6) or (g)(8) 
of this section.
    (e) Violations at branded retail outlets or wholesale purchaser-
consumer facilities. Where a violation of the applicable standard set 
forth in Sec. 80.27 is detected at a retail outlet or at a wholesale 
purchaser-consumer facility displaying the corporate, trade, or brand 
name of a gasoline refiner or any of its marketing subsidiaries, the 
following parties shall be deemed in violation:
    (1) The retailer or wholesale purchaser-consumer, except as provided 
in paragraph (g)(5) or (g)(8) of this section;
    (2) The distributor and/or reseller (if any), except as provided in 
paragraph (g)(3) or (g)(8) of this section;
    (3) The carrier (if any), if the carrier caused the gasoline to 
violate the applicable standard;
    (4) The refiner whose corporate, trade, or brand name (or that of 
any of its marketing subsidiaries) is displayed at the retail outlet or 
wholesale purchaser-consumer facility, except as provided in paragraph 
(g)(4) of this section; and
    (5) The ethanol blender (if any) at whose ethanol blending plant the 
gasoline was produced, except as provided in paragraph (g)(6) or (g)(8) 
of this section.
    (f) Violations at unbranded retail outlets or wholesale purchaser-
consumer facilities. Where a violation of the applicable standard set 
forth in Sec. 80.27 is detected at a retail outlet or at a wholesale 
purchaser-consumer facility not displaying the corporate, trade, or 
brand name of a refiner or any of its marketing subsidiaries, the 
following parties shall be deemed in violation:
    (1) The retailer or wholesale purchaser-consumer, except as provided 
in paragraph (g)(5) or (g)(8) of this section;
    (2) The distributor (if any), except as provided in paragraph (g)(3) 
or (g)(8) of this section;
    (3) The carrier (if any), if the carrier caused the gasoline to 
violate the applicable standard;
    (4) The ethanol blender (if any) at whose ethanol blending plant the 
gasoline was produced, except as provided in paragraph (g)(6) of this 
section; and
    (5) The refiner (if he is not an ethanol blender) at whose refinery 
the gasoline was produced and/or the importer at whose import facility 
the gasoline was imported, except as provided in paragraph (g)(2) of 
this section.
    (g) Defenses. (1) In any case in which a carrier would be in 
violation under paragraph (b)(1) of this section, the carrier shall not 
be deemed in violation if he can demonstrate:
    (i) That the violation was not caused by him or his employee or 
agent; and
    (ii) Evidence of an oversight program conducted by the carrier, such 
as periodic sampling and testing of incoming gasoline, for monitoring 
the volatility of gasoline stored or transported by that carrier.
    (iii) An oversight program under paragraph (g)(1)(ii) of this 
section need not include periodic sampling and testing of gasoline in a 
tank truck operated by a common carrier, but in lieu of such tank truck 
sampling and testing, the common carrier shall demonstrate evidence of 
an oversight program for monitoring compliance with the volatility 
requirements of Sec. 80.27 relating to the transport or storage of

[[Page 649]]

gasoline by tank truck, such as appropriate guidance to drivers on 
compliance with applicable requirements and the periodic review of 
records normally received in the ordinary course of business concerning 
gasoline quality and delivery.
    (2) In any case in which a refiner or importer would be in violation 
under paragraphs (b)(2), (d)(3), or (f)(5) of this section, the refiner 
or importer shall not be deemed in violation if he can demonstrate:
    (i) That the violation was not caused by him or his employee or 
agent; and
    (ii) Test results using the sampling methodology set forth in Sec. 
80.8 and the testing methodology set forth in Sec. 80.46(c), or any 
other test method where adequate correlation to Sec. 80.46(c) is 
demonstrated, which show evidence that the gasoline determined to be in 
violation was in compliance with the applicable standard when it was 
delivered to the next party in the distribution system.
    (3) In any case in which a distributor or reseller would be in 
violation under paragraph (b)(4), (c)(1), (d)(1), (e)(2), or (f)(2) of 
this section, the distributor or reseller shall not be deemed in 
violation if he can demonstrate:
    (i) That the violation was not caused by him or his employee or 
agent; and
    (ii) Evidence of an oversight program conducted by the distributor 
or reseller, such as periodic sampling and testing of gasoline, for 
monitoring the volatility of gasoline that the distributor or reseller 
sells, supplies, offers for sale or supply, or transports.
    (4) In any case in which a refiner would be in violation under 
paragraphs (c)(3) or (e)(4) of this section, the refiner shall not be 
deemed in violation if he can demonstrate all of the following:
    (i) Test results using the sampling methodology set forth in Sec. 
80.8 and the testing methodology set forth in Sec. 80.46(c), or any 
other test method where adequate correlation to Sec. 80.46(c) is 
demonstrated, which show evidence that the gasoline determined to be in 
violation was in compliance with the applicable standard when 
transported from the refinery.
    (ii) That the violation was not caused by him or his employee or 
agent; and
    (iii) That the violation:
    (A) Was caused by an act in violation of law (other than the Act or 
this part), or an act of sabotage or vandalism, whether or not such acts 
are violations of law in the jurisdiction where the violation of the 
requirements of this part occurred, or
    (B) Was caused by the action of a reseller, an ethanol blender, or a 
retailer supplied by such reseller or ethanol blender, in violation of a 
contractual undertaking imposed by the refiner on such reseller or 
ethanol blender designed to prevent such action, and despite reasonable 
efforts by the refiner (such as periodic sampling and testing) to insure 
compliance with such contractual obligation, or
    (C) Was caused by the action of a retailer who is supplied directly 
by the refiner (and not by a reseller), in violation of a contractual 
undertaking imposed by the refiner on such retailer designed to prevent 
such action, and despite reasonable efforts by the refiner (such as 
periodic sampling and testing) to insure compliance with such 
contractual obligation, or
    (D) Was caused by the action of a distributor or an ethanol blender 
subject to a contract with the refiner for transportation of gasoline 
from a terminal to a distributor, ethanol blender, retailer or wholesale 
purchaser-consumer, in violation of a contractual undertaking imposed by 
the refiner on such distributor or ethanol blender designed to prevent 
such action, and despite reasonable efforts by the refiner (such as 
periodic sampling and testing) to insure compliance with such 
contractual obligation, or
    (E) Was caused by a carrier or other distributor not subject to a 
contract with the refiner but engaged by him for transportation of 
gasoline from a terminal to a distributor, ethanol blender, retailer or 
wholesale purchaser-consumer, despite reasonable efforts by the refiner 
(such as specification or inspection of equipment) to prevent such 
action, or
    (F) Occurred at a wholesale purchaser-consumer facility: Provided, 
however, That if such wholesale purchaser-consumer was supplied by a 
reseller or ethanol blender, the refiner must demonstrate that the 
violation

[[Page 650]]

could not have been prevented by such reseller's or ethanol blender's 
compliance with a contractual undertaking imposed by the refiner on such 
reseller or ethanol blender as provided in paragraph (g)(4)(iii)(B) of 
this section.
    (iv) In paragraphs (g)(4)(iii)(A) through (E) of this section, the 
term ``was caused'' means that the refiner must demonstrate by 
reasonably specific showings, by direct or circumstantial evidence, that 
the violation was caused or must have been caused by another.
    (5) In any case in which a retailer or wholesale purchaser-consumer 
would be in violation under paragraphs (e)(1) or (f)(1) of this section, 
the retailer or wholesale purchaser-consumer shall not be deemed in 
violation if he can demonstrate that the violation was not caused by him 
or his employee or agent.
    (6) In any case in which an ethanol blender would be in violation 
under paragraphs (b)(3), (c)(4), (d)(4), (e)(5) or (f)(4) of this 
section, the ethanol blender shall not be deemed in violation if he can 
demonstrate:
    (i) That the violation was not caused by him or his employee or 
agent; and
    (ii) Evidence of an oversight program conducted by the ethanol 
blender, such as periodic sampling and testing of gasoline, for 
monitoring the volatility of gasoline that the ethanol blender sells, 
supplies, offers for sale or supply or transports; and
    (iii) That the gasoline determined to be in violation contained no 
more than 10% ethanol (by volume) when it was delivered to the next 
party in the distribution system.
    (7) In paragraphs (g)(1)(i), (g)(2)(i), (g)(3)(i), (g)(4)(ii), 
(g)(5), and (g)(6)(i) of this section, the respective party must 
demonstrate by reasonably specific showings, by direct or circumstantial 
evidence, that it or its employee or agent did not cause the violation.
    (8) In addition to the defenses provided in paragraphs (g)(1) 
through (g)(6) of this section, in any case in which an ethanol blender, 
distributor, reseller, carrier, retailer, or wholesale purchaser-
consumer would be in violation under paragraphs (b), (c), (d), (e) or 
(f), of this section, as a result of gasoline which contains between 9 
and 10 percent ethanol (by volume) but exceeds the applicable standard 
by more than one pound per square inch (1.0 psi), the ethanol blender, 
distributor, reseller, carrier, retailer or wholesale purchaser-consumer 
shall not be deemed in violation if such person can demonstrate, by 
showing receipt of a certification from the facility from which the 
gasoline was received or other evidence acceptable to the Administrator, 
that:
    (i) The gasoline portion of the blend complies with the Reid vapor 
pressure limitations of Sec. 80.27(a); and
    (ii) The ethanol portion of the blend does not exceed 10 percent (by 
volume); and
    (iii) No additional alcohol or other additive has been added to 
increase the Reid vapor pressure of the ethanol portion of the blend.

In the case of a violation alleged against an ethanol blender, 
distributor, reseller, or carrier, if the demonstration required by 
paragraphs (g)(8)(i), (ii), and (iii) of this section is made by a 
certification, it must be supported by evidence that the criteria in 
paragraphs (g)(8)(i), (ii), and (iii) of this section have been met, 
such as an oversight program conducted by or on behalf of the ethanol 
blender, distributor, reseller or carrier alleged to be in violation, 
which includes periodic sampling and testing of the gasoline or 
monitoring the volatility and ethanol content of the gasoline. Such 
certification shall be deemed sufficient evidence of compliance provided 
it is not contradicted by specific evidence, such as testing results, 
and provided that the party has no other reasonable basis to believe 
that the facts stated in the certification are inaccurate. In the case 
of a violation alleged against a retail outlet or wholesale purchaser-
consumer facility, such certification shall be deemed an adequate 
defense for the retailer or wholesale purchaser-consumer, provided that 
the retailer or wholesale purchaser-consumer is able to show 
certificates for all of the gasoline contained in the storage tank found 
in violation, and, provided that the retailer or wholesale purchaser-
consumer has no reasonable basis to

[[Page 651]]

believe that the facts stated in the certifications are inaccurate.

[54 FR 11885, Mar. 22, 1989; 54 FR 27017, June 27, 1989, as amended at 
56 FR 64711, Dec. 12, 1991; 58 FR 14484, Mar. 17, 1993; 62 FR 68205, 
Dec. 31, 1997; 67 FR 8736, Feb. 26, 2002]



Sec. 80.29  Controls and prohibitions on diesel fuel quality.

    (a) Prohibited activities. Beginning October 1, 1993 and continuing 
until the implementation dates for subpart I of part 80 as specified in 
Sec. 80.500, except as provided in 40 CFR 69.51, no person, including 
but not limited to, refiners, importers, distributors, resellers, 
carriers, retailers or wholesale purchaser-consumers, shall manufacture, 
introduce into commerce, sell, offer for sale, supply, store, dispense, 
offer for supply or transport any diesel fuel for use in motor vehicles, 
unless the diesel fuel:
    (1) Has a sulfur percentage, by weight, no greater than 0.05 
percent;
    (2)(i) Has a cetane index of at least 40; or
    (ii) Has a maximum aromatic content of 35 volume percent; and
    (3) Is free of visible evidence of the dye solvent red 164; unless 
it is used in a manner that is tax-exempt as defined under section 4082 
of the Internal Revenue Code (26 U.S.C. 4082).
    (b) Determination of compliance. (1) Any diesel fuel which does not 
show visible evidence of being dyed with dye solvent red 164 (which has 
a characteristic red color in diesel fuel) shall be considered to be 
available for use in diesel motor vehicles and motor vehicle engines, 
and shall be subject to the prohibitions of paragraph (a) of this 
section.
    (2) Compliance with the sulfur, cetane, and aromatics standards in 
paragraph (a) of this section shall be determined based on the level of 
the applicable component or parameter, using the sampling methodologies 
specified in Sec. 80.330(b), as applicable, and the appropriate testing 
methodologies specified in Sec. 80.580(a) for sulfur, Sec. 80.2(w) for 
cetane index, and Sec. 80.2(z) for aromatic content. Any evidence or 
information, including the exclusive use of such evidence or 
information, may be used to establish the level of the applicable 
component or parameter in the diesel fuel, if the evidence or 
information is relevant to whether that level would have been in 
compliance with the standard if the appropriate sampling and testing 
methodology had been correctly performed. Such evidence may be obtained 
from any source or location and may include, but is not limited to, test 
results using methods other than the compliance methods in this 
paragraph (b), business records, and commercial documents.
    (3) Determination of compliance with the requirements of this 
section other than the standards described in paragraph (a) of this 
section, and determination of liability for any violation of this 
section, may be based on information obtained from any source or 
location. Such information may include, but is not limited to, business 
records and commercial documents.
    (c) Transfer documents. (1) Any person that transfers custody or 
title of diesel fuel for use in motor vehicles which contains visible 
evidence of the dye solvent red 164 shall provide documents to the 
transferee which state that such fuel meets the applicable standards for 
sulfur and cetane index or aromatic content under these regulations and 
is only for tax-exempt use in diesel motor vehicles as defined under 
section 4082 of the Internal Revenue Code.
    (2) Any person that is the transferor or the transferee of diesel 
fuel for use in motor vehicles which contains visible evidence of the 
dye solvent red 164, shall retain the documents required under paragraph 
(c)(1) of this section for a period of five years from the date of 
transfer of such fuel and shall provide such documents to the 
Administrator or the Administrator's representative upon request.
    (d) Liability. Liability for violations of paragraph (a)(1) of this 
section shall be determined according to the provisions of Sec. 80.30. 
Any person that violates paragraph (a)(2) or (c) of this section shall 
be liable for penalties in accordance with paragraph (e) of this 
section.
    (e) Penalties. Penalties for violations of paragraph (a) or (c) of 
this section shall be determined according to the provisions of Sec. 
80.5.

[59 FR 35858, July 14, 1994, as amended at 63 FR 49465, Sept. 16, 1998; 
66 FR 5135, Jan. 18, 2001]

[[Page 652]]



Sec. 80.30  Liability for violations of diesel fuel control and prohibitions.

    (a) Violations at refiners or importers facilities. Where a 
violation of a diesel fuel standard set forth in Sec. 80.29 is detected 
at a refinery or importer's facility, the refiner or importer shall be 
deemed in violation.
    (b) Violations at carrier facilities. Where a violation of a diesel 
fuel standard set forth in Sec. 80.29 is detected at a carrier's 
facility, whether in a transport vehicle, in a storage facility, or 
elsewhere at the facility, the following parties shall be deemed in 
violation:
    (1) The carrier, except as provided in paragraph (g)(1) of this 
section; and
    (2) The refiner or importer at whose refinery or import facility the 
diesel fuel was produced or imported, except as provided in paragraph 
(g)(2) of this section.
    (c) Violations at branded distributor or reseller facilities. Where 
a violation of a diesel fuel standard set forth in Sec. 80.29 is 
detected at a distributor or reseller's facility which is operating 
under the corporate, trade or brand name of a refiner or any of its 
marketing subsidiaries, the following parties shall be deemed in 
violation:
    (1) The distributor or reseller, except as provided in paragraph 
(g)(3) of this section;
    (2) The carrier (if any), if the carrier caused the diesel fuel to 
violate the standard by fuel switching, blending, mislabeling, or any 
other means; and
    (3) The refiner under whose corporate, trade, or brand name (or that 
of any of its marketing subsidiaries) the distributor or reseller is 
operating, except as provided in paragraph (g)(4) of this section.
    (d) Violations at unbranded distributor facilities. Where a 
violation of a diesel fuel standard set forth in Sec. 80.29 is detected 
at the facility of a distributor not operating under a refiner's 
corporate, trade, or brand name, or that of any of its marketing 
subsidiaries, the following shall be deemed in violation:
    (1) The distributor, except as provided in paragraph (g)(3) of this 
section;
    (2) The carrier (if any), if the carrier caused the diesel fuel to 
violate the standard by fuel switching, blending, mislabeling, or any 
other means; and
    (3) The refiner or importer at whose refinery or import facility the 
diesel fuel was produced or imported, except as provided in paragraph 
(g)(2) of this section.
    (e) Violations at branded retail outlets or wholesale purchaser-
consumer facilities. Where a violation of a diesel fuel standard set 
forth in Sec. 80.29 is detected at a retail outlet or at a wholesale 
purchaser-consumer facility displaying the corporate, trade, or brand 
name of a refiner or any of its marketing subsidiaries, the following 
parties shall be deemed in violation:
    (1) The retailer or wholesale purchaser-consumer, except as provided 
in paragraph (g)(5) of this section;
    (2) The distributor and/or reseller (if any), except as provided in 
paragraph (g)(3) of this section;
    (3) The carrier (if any), if the carrier caused the diesel fuel to 
violate the standard by fuel switching, blending, mislabeling, or any 
other means; and
    (4) The refiner whose corporate, trade, or brand name, or that of 
any of its marketing subsidiaries, is displayed at the retail outlet or 
wholesale purchaser-consumer facility, except as provided in paragraph 
(g)(4) of this section.
    (f) Violations at unbranded retail outlets or wholesale purchaser-
consumer facilities. Where a violation of a diesel fuel standard set 
forth in Sec. 80.29 is detected at a retail outlet or at a wholesale 
purchaser-consumer facility not displaying the corporate, trade, or 
brand name of a refiner or any of its marketing subsidiaries, the 
following parties shall be deemed in violation:
    (1) The retailer or wholesale purchaser-consumer, except as provided 
in paragraph (g)(5) of this section;
    (2) The distributor (if any), except as provided in paragraph (g)(3) 
of this section;
    (3) The carrier (if any), if the carrier caused the diesel fuel to 
violate the standard by fuel switching, blending, mislabeling, or any 
other means; and
    (4) The refiner or importer at whose refinery or import facility the 
diesel fuel was produced or imported, except as provided in paragraph 
(g)(2) of this section.

[[Page 653]]

    (g) Defenses. (1) In any case in which a carrier would be in 
violation under paragraph (b)(1) of this section, the carrier shall not 
be deemed in violation if he can demonstrate:
    (i) Evidence of an oversight program conducted by the carrier, for 
monitoring the diesel fuel stored or transported by that carrier, such 
as periodic sampling and testing of the cetane index and sulfur 
percentage of incoming diesel fuel. Such an oversight program need not 
include periodic sampling and testing of diesel fuel in a tank truck 
operated by a common carrier, but in lieu of such tank truck sampling 
and testing the common carrier shall demonstrate evidence of an 
oversight program for monitoring compliance with the diesel fuel 
requirements of Sec. 80.29 relating to the transport or storage of 
diesel fuel by tank truck, such as appropriate guidance to drivers on 
compliance with applicable requirements and the periodic review of 
records normally received in the ordinary course of business concerning 
diesel fuel quality and delivery; and
    (ii) That the violation was not caused by the carrier or his 
employee or agent.
    (2) In any case in which a refiner or importer would be in violation 
under paragraphs (b)(2), (d)(3), or (f)(4) of this section, the refiner 
or importer shall not be deemed in violation if he can demonstrate:
    (i) That the violation was not caused by him or his employee or 
agent; and
    (ii) Test results, performed in accordance with the applicable 
sampling and testing methodologies set forth in Sec. Sec. 80.2(w), 
80.2(z), 80.2(bb), and 80.580, which evidence that the diesel fuel 
determined to be in violation was in compliance with the diesel fuel 
standards of Sec. 80.29(a) when it was delivered to the next party in 
the distribution system;
    (3) In any case in which a distributor or reseller would be in 
violation under paragraphs (c)(1), (d)(1), (e)(2) or (f)(2) of this 
section, the distributor or reseller shall not be deemed in violation if 
he can demonstrate:
    (i) That the violation was not caused by him or his employee or 
agent; and
    (ii) Evidence of an oversight program conducted by the distributor 
or reseller, such as periodic sampling and testing of diesel fuel, for 
monitoring the sulfur percentage and cetane index of the diesel fuel 
that the distributor or reseller sells, supplies, offers for sale or 
supply, or transports.
    (4) In any case in which a refiner would be in violation under 
paragraphs (c)(3) or (e)(4) of this section, the refiner shall not be 
deemed in violation if he can demonstrate all of the following:
    (i) Test results, performed in accordance with the applicable 
sampling and testing methodologies set forth in Sec. Sec. 80.2(w), 
80.2(z), 80.2(bb), and 80.580, which evidence that the diesel fuel 
determined to be in violation was in compliance with the diesel fuel 
standards of Sec. 80.29(a) when it was delivered to the next party in 
the distribution system;
    (ii) That the violation was not caused by him or his employee or 
agent; and
    (iii) That the violation:
    (A) Was caused by an act in violation of law (other than the Act or 
this part), or an act of sabotage or vandalism, whether or not such acts 
are violations of law in the jurisdiction where the violation of the 
requirements of this part occurred, or
    (B) Was caused by the action of a reseller or a retailer supplied by 
such reseller, in violation of a contractual undertaking imposed by the 
refiner on such reseller designed to prevent such action, and despite 
reasonable efforts by the refiner (such as periodic sampling and 
testing) to insure compliance with such contractual obligation, or
    (C) Was caused by the action of a retailer who is supplied directly 
by the refiner (and not by a reseller), in violation of a contractual 
undertaking imposed by the refiner on such retailer designed to prevent 
such action, and despite reasonable efforts by the refiner (such as 
periodic sampling and testing) to insure compliance with such 
contractual obligation, or
    (D) Was caused by the action of a distributor subject to a contract 
with the refiner for transportation of diesel fuel from a terminal to a 
distributor, retailer or wholesale purchaser-consumer, in violation of a 
contractual undertaking imposed by the refiner on such distributor 
designed to prevent such action, and despite reasonable efforts by the 
refiner (such as periodic

[[Page 654]]

sampling and testing) to ensure compliance with such contractual 
obligation, or
    (E) Was caused by a carrier or other distributor not subject to a 
contract with the refiner but engaged by him for transportation of 
diesel fuel from a terminal to a distributor, retailer or wholesale 
purchaser-consumer, despite reasonable efforts by the refiner (such as 
specification or inspection of equipment) to prevent such action, or
    (F) Occurred at a wholesale purchaser-consumer facility: Provided, 
however, That if such wholesale purchaser-consumer was supplied by a 
reseller, the refiner must demonstrate that the violation could not have 
been prevented by such reseller's compliance with a contractual 
undertaking imposed by the refiner on such reseller as provided in 
paragraph (g)(4)(iii)(B) of this section.
    (iv) In paragraphs (g)(4)(iii) (A) through (E) of this section, the 
term was caused means that the refiner must demonstrate by reasonably 
specific showings, by direct or circumstantial evidence, that the 
violation was caused or must have been caused by another.
    (5) In any case in which a retailer or wholesale purchaser-consumer 
would be in violation under paragraphs (e)(1) or (f)(1) of this section, 
the retailer or wholesale purchaser-consumer shall not be deemed in 
violation if he can demonstrate that the violation was not caused by him 
or his employee or agent.
    (6) In paragraphs (g)(1)(iii), (g)(2)(i), (g)(3)(i), (g)(4)(ii) and 
(g)(5) of this section, the respective party must demonstrate by 
reasonably specific showings, by direct or circumstantial evidence, that 
it or its employee or agent did not cause the violation.
    (7) In the case of any distributor or reseller that would be in 
violation under paragraph (e)(2) or (f)(2) of this section or any 
wholesale purchaser-consumer or retailer that would be in violation 
under paragraph (e)(1) or (f)(1) of this section for diesel fuel for use 
in motor vehicles which contains visible evidence of the dye solvent red 
164, the distributor or reseller or wholesale purchaser-consumer or 
retailer shall not be deemed in violation if he can:
    (i) Demonstrate that the violation was not caused by him or his 
employee or agent,
    (ii) Demonstrate that the fuel has been supplied, offered for 
supply, transported or available for tax-exempt use as defined under 
section 4082 of the Internal Revenue Code, and
    (iii) Provide evidence from the supplier in the form of 
documentation that the fuel met the applicable standards under paragraph 
(a)(1) of this section for sulfur and cetane index or aromatics content 
for use in motor vehicles.
    (h) Detection of violations. In paragraphs (a) through (f) of this 
section, the term ``is detected at'' means that the violation existed at 
the facility in question, and the existence of the violation at that 
facility may be established through evidence obtained or created at that 
facility, at any other location, and by any party.

[55 FR 34138, Aug. 21, 1990, as amended at 59 FR 35859, July 14, 1994; 
62 FR 68205, Dec. 31, 1997; 66 FR 5135, Jan. 18, 2001]



Sec. 80.32  Controls applicable to liquefied petroleum gas retailers and wholesale purchaser-consumers.

    After January 1, 1998 every retailer and wholesale purchaser- 
consumer handling over 13,660 gallons of liquefied petroleum gas per 
month shall equip each pump from which liquefied petroleum gas is 
introduced into motor vehicles with a nozzle that has no greater than 
2.0 cm\3\ dead space from which liquefied petroleum gas will be released 
upon nozzle disconnect from the vehicle, as measured from the nozzle 
face which seals against the vehicle receptacle ``O'' ring, and as 
determined by calculation of the geometric shape of the nozzle. After 
January 1, 2000 this requirement applies to every liquefied petroleum 
gas retailer and wholesale purchaser- consumer. Any dispensing pump 
shown to be dedicated to heavy-duty vehicles is exempt from this 
requirement.

[59 FR 48490, Sept. 21, 1994]

[[Page 655]]



Sec. 80.33  Controls applicable to natural gas retailers and
wholesale purchaser-consumers.

    (a) After January 1, 1998 every retailer and wholesale purchaser-
consumer handling over 1,215,000 standard cubic feet of natural gas per 
month shall equip each pump from which natural gas is introduced into 
natural gas motor vehicles with a nozzle and hose configuration which 
vents no more than 1.2 grams of natural gas to the atmosphere per 
refueling of a vehicle complying with Sec. 86.098-8(d)(1)(iv) of this 
chapter, as determined by calculation of the geometric shape of the 
nozzle and hose. After January 1, 2000 this requirement applies to every 
natural gas retailer and wholesale purchaser-consumer. Any dispensing 
pump shown to be dedicated to heavy-duty vehicles is exempt from this 
requirement.
    (b) The provisions of paragraph (a) of this section can be waived 
for refueling stations which were in operation on or before January 1, 
1998 provided the station operator can demonstrate, to the satisfaction 
of the Administrator, that compliance with paragraph (a) of this section 
would require additional compression equipment or other modifications 
with costs similar to or greater than the cost of additional compression 
equipment.

[59 FR 48490, Sept. 21, 1994]



                      Subpart C_Oxygenated Gasoline



Sec. 80.35  Labeling of retail gasoline pumps; oxygenated gasoline.

    (a) For oxygenated gasoline programs with a minimum oxygen content 
per gallon or minimum oxygen content requirement in conjunction with a 
credit program, the following shall apply:
    (1) Each gasoline pump stand from which oxygenated gasoline is 
dispensed at a retail outlet in the control area shall be affixed during 
the control period with a legible and conspicuous label which contains 
the following statement:

The gasoline dispensed from this pump is oxygenated and will reduce 
carbon monoxide pollution from motor vehicles.

    (2) The posting of the above statement shall be in block letters of 
no less than 20-point bold type; in a color contrasting with the 
intended background. The label shall be placed on the vertical surface 
of the pump on each side with gallonage and price meters and shall be on 
the upper two-thirds of the pump, clearly readable to the public.
    (3) The retailer shall be responsible for compliance with the 
labeling requirements of this section.
    (b) For oxygenated gasoline programs with a credit program and no 
minimum oxygen content requirement, the following shall apply:
    (1) Each gasoline pump stand from which oxygenated gasoline is 
dispensed at a retail outlet in the control area shall be affixed during 
the control period with a legible and conspicuous label which contains 
the following statement:

The fuel dispensed from this pump meets the requirements of the Clean 
Air Act as part of a program to reduce carbon monoxide pollution from 
motor vehicles.

    (2) The posting of the above statement shall be in block letters of 
no less than 20-point bold type; in a color contrasting with the 
intended background. The label shall be placed on the vertical surface 
of the pump on each side with gallonage and price meters and shall be on 
the upper two-thirds of the pump, clearly readable to the public.
    (3) The retailer shall be responsible for compliance with the 
labeling requirements of this section.

[57 FR 47771, Oct. 20, 1992]



Sec. Sec. 80.36-80.39  [Reserved]



                     Subpart D_Reformulated Gasoline

    Source: 59 FR 7813, Feb. 16, 1994, unless otherwise noted.



Sec. 80.40  Fuel certification procedures.

    (a) Gasoline that complies with one of the standards specified in 
Sec. 80.41 (a) through (f) that is relevant for the gasoline, and that 
meets all other relevant requirements prescribed under Sec. 80.41, 
shall be deemed certified.
    (b) Any refiner or importer may, with regard to a specific fuel 
formulation,

[[Page 656]]

request from the Administrator a certification that the formulation 
meets one of the standards specified in Sec. 80.41 (a) through (f).
    (c)(1) ``Adjusted VOC gasoline'' for purposes of the general 
requirements in Sec. 80.65(d)(2)(ii), and the certification procedures 
in this section is gasoline that contains 10 volume percent ethanol, or 
RBOB intended for blending with 10 volume percent ethanol, that is 
intended for use in the areas described at Sec. 80.70(f) and (i), and 
is designated by the refiner as adjusted VOC gasoline subject to less 
stringent VOC standards in Sec. 80.41(e) and (f). In order for 
``adjusted VOC gasoline'' to qualify for the regulatory treatment 
specified in Sec. 80.41(e) and (f), reformulated gasoline must contain 
denatured, anhydrous ethanol. The concentration of the ethanol, 
excluding the required denaturing agent, must be at least 9% and no more 
than 10% (by volume) of the gasoline. The ethanol content of the 
gasoline shall be determined by use of one of the testing methodologies 
specified in Sec. 80.46(g).
    (2) Refiners may choose not to designate as adjusted VOC gasoline or 
RBOB that otherwise meets the requirements of paragraph (c)(1) of this 
section, in which case the more stringent VOC standards in Sec. 80.41 
apply.
    (3) For purposes of Sec. 80.78(a)(1)(v), the ``Adjusted VOC 
gasoline'' standards under Sec. 80.41 are the applicable VOC emissions 
performance standards only for adjusted VOC gasoline that is intended 
for use in or sold for use by an ultimate consumer in the covered areas 
described at Sec. 80.70(f) and (i). For purposes of Sec. 
80.78(a)(1)(v), gasoline designated as adjusted VOC gasoline that is 
intended for use or that is sold for use by an ultimate consumer in any 
covered area in VOC-Control Region 2 other than those described at Sec. 
80.70(f) and (i), is subject to the VOC performance standards in Sec. 
80.41 applicable to all other gasoline designated for VOC-Control Region 
2.

[59 FR 7813, Feb. 16, 1994, as amended at 66 FR 37164, July 17, 2001; 67 
FR 8736, Feb. 26, 2002]



Sec. 80.41  Standards and requirements for compliance.

    (a) Simple model per-gallon standards. The ``simple model'' 
standards for compliance when achieved on a per-gallon basis are as 
follows:

                    Simple Model Per-Gallon Standards
Reid vapor pressure (in pounds per square inch):
  Gasoline designated for VOC-Control Region 1................    <=7.2
  Gasoline designated for VOC-Control Region 2................    <=8.1
Oxygen content (percent, by weight)...........................  X emissions performance reduction specified 
in paragraph (e)(1) of this section shall no longer apply beginning 
January 1, 2007, except as provided in paragraph (e)(2)(ii) of this 
section.
    (ii) For a refiner subject to the small refiner gasoline sulfur 
standards at Sec. 80.240, the NOX emissions performance 
reduction specified in paragraph (e)(1) of this section shall no longer 
apply beginning January 1, 2008. For a refiner subject to the gasoline 
sulfur standards at Sec. 80.240 that has received an extension of its 
small refiner gasoline sulfur standards under Sec. 80.553, the 
NOX emissions performance reduction specified in paragraph 
(e)(1) of this section shall no longer apply beginning January 1, 2011.
    (3)(i) Beginning January 1, 2011, or January 1, 2015 for small 
refiners approved under Sec. 80.1340, the toxic air pollutants 
emissions performance reduction and benzene content specified in 
paragraph (e)(1) of this section shall apply to reformulated gasoline 
that is not subject to the benzene standard of Sec. 80.1230, pursuant 
to the provisions of Sec. 80.1235.
    (ii) The toxic air pollutants emissions performance reduction and 
benzene content specified in paragraph (e)(1) of this section shall not 
apply to reformulated gasoline produced by a refinery approved under 
Sec. 80.1334, pursuant to Sec. 80.1334(c).
    (f)(1) Phase II complex model averaged standards. The Phase II 
``complex model'' standards for compliance when achieved on average are 
as follows:

                Phase II Complex Model Averaged Standards
VOC emissions performance reduction (percent):
    Gasoline designated for VOC-Control Region 1
        Standard...............................................  X emissions performance reduction specified 
in paragraph (f)(1) of this section shall no longer apply beginning 
January 1, 2007, except as provided in paragraph (f)(2)(ii) of this 
section.
    (ii) For a refiner subject to the small refiner gasoline sulfur 
standards at Sec. 80.240, the NOX emissions performance 
reduction specified in paragraph (f)(1) of this section shall no longer 
apply beginning January 1, 2008. For a refiner subject to the gasoline 
sulfur standards at Sec. 80.240 that has received an extension of its 
small refiner gasoline sulfur standards under Sec. 80.553, the 
NOX emissions performance reduction specified in paragraph 
(f)(1) of this section shall no longer apply beginning January 1, 2011.
    (3)(i) Beginning January 1, 2011, or January 1, 2015 for small 
refiners approved under Sec. 80.1340, the toxic air pollutants 
emissions performance reduction and benzene content specified in 
paragraph (f)(1) of this section shall apply only to reformulated 
gasoline

[[Page 658]]

that is not subject to the benzene standard of Sec. 80.1230, pursuant 
to the provisions of Sec. 80.1235.
    (ii) The toxic air pollutants emissions performance reduction and 
benzene content specified in paragraph (f)(1) of this section shall not 
apply to reformulated gasoline produced by a refinery approved under 
Sec. 80.1334, pursuant to Sec. 80.1334(c).
    (g) Oxygen maximum standard. (1) The per-gallon standard for maximum 
oxygen content, which applies to reformulated gasoline subject to the 
simple model per-gallon or average standards, is as follows:
    (i) Oxygen content shall not exceed 3.2 percent by weight from 
ethanol within the boundaries of any State if the State notifies the 
Administrator that the use of an oxygenate will interfere with 
attainment or maintenance of an ambient air quality standard or will 
contribute to an air quality problem.
    (ii) A State may request the standard specified in paragraph 
(g)(1)(i) of this section separately for reformulated gasoline 
designated as VOC-controlled and reformulated gasoline not designated as 
VOC-controlled.
    (2) The standard in paragraph (g)(1)(i) of this section shall apply 
60 days after the Administrator publishes a notice in the Federal 
Register announcing such a standard.
    (h) Additional standard requirements. In addition to the standards 
specified in paragraphs (a) through (g) of this section, the following 
standards apply for all reformulated gasoline:
    (1) The standard for heavy metals, including lead or manganese, on a 
per-gallon basis, is that reformulated gasoline may contain no heavy 
metals. The Administrator may waive this prohibition for a heavy metal 
(other than lead) if the Administrator determines that addition of the 
heavy metal to the gasoline will not increase, on an aggregate mass or 
cancer-risk basis, toxic air pollutant emissions from motor vehicles.
    (2) In the case of any refinery or importer subject to the simple 
model standards:
    (i) The annual average levels for sulfur, T-90, and olefins cannot 
exceed that refinery's or importer's 1990 baseline levels for each of 
these parameters; and
    (ii) The 1990 baseline levels and the annual averages for these 
parameters shall be established using the methodology set forth in 
Sec. Sec. 80.91 through 80.92; and
    (iii) In the case of a refiner that operates more than one refinery, 
the standards specified under this paragraph (h)(2) shall be met using 
the refinery grouping selected by the refiner under Sec. 80.101(h).
    (i) Use of simple and complex models. (1) During each calendar year 
1995 through 1997, any refinery or importer shall be subject to either 
the simple model standards specified in paragraphs (a) and (b) of this 
section, or the Phase I complex model standards specified in paragraphs 
(c) and (d) of this section, at the option of the refiner or importer, 
provided that:
    (i) No refinery or importer may be subject to a combination of 
simple and complex standards during any calendar year; and
    (ii) Any refiner or importer that elects to achieve compliance with 
the anti-dumping requirements using the:
    (A) Simple model shall meet the requirements of this subpart D using 
the simple model standards; or
    (B) Complex model or optional complex model shall meet the 
requirements of this subpart D using the complex model standards.
    (2) During the period January 1, 1998 through December 31, 1999, any 
refiner or importer shall be subject to the Phase I complex model 
standards specified in paragraphs (c) and (d) of this section.
    (3) Beginning on January 1, 2000, any refiner or importer shall be 
subject to the Phase II complex model standards specified in paragraphs 
(e) and (f) of this section.
    (j) Complex model early use. Before January 1, 1998, the VOC, 
toxics, and NOX emissions performance standards for any 
refinery or importer subject to the Phase I complex model standards 
shall be determined by evaluating all of the following parameter levels 
in the Phase I complex model (specified in Sec. 80.45) at one time:

[[Page 659]]

    (1) The simple model values for benzene, RVP, and oxygen specified 
in Sec. 80.41 (a) or (b), as applicable;
    (2) The aromatics value which, together with the values for benzene, 
RVP, and oxygen determined under paragraph (j)(1) of this section, meets 
the Simple Model toxics requirement specified in paragraph (a) or (b) of 
this section, as applicable;
    (3) The refinery's or importer's individual baseline values for 
sulfur, E-300, and olefins, as established under Sec. 80.91; and
    (4) The appropriate seasonal value of E-200 specified in Sec. 
80.45(b)(2).
    (k) Effect of VOC survey failure. (1) On each occasion during 1995 
or 1996 that a covered area fails a simple model VOC emissions reduction 
survey conducted pursuant to Sec. 80.68, the RVP requirements for that 
covered area beginning in the year following the failure shall be 
adjusted to be more stringent as follows:
    (i) The required average RVP level shall be decreased by an 
additional 0.1 psi; and
    (ii) The maximum RVP level for each gallon of averaged gasoline 
shall be decreased by an additional 0.1 psi.
    (2) On each occasion that a covered area fails a complex model VOC 
emissions reduction survey conducted pursuant to Sec. 80.68, or fails a 
simple model VOC emissions reduction survey conducted pursuant to Sec. 
80.68 during 1997, the VOC emissions performance standard for that 
covered area beginning in the year following the failure shall be 
adjusted to be more stringent as follows:
    (i) The required average VOC emissions reduction shall be increased 
by an additional 1.0%; and
    (ii) The minimum VOC emissions reduction, for each gallon of 
averaged gasoline, shall be increased by an additional 1.0%.
    (3) In the event that a covered area for which required VOC 
emissions reductions have been made more stringent passes all VOC 
emissions reduction surveys in two consecutive years, the averaging 
standards VOC emissions reduction for that covered area beginning in the 
year following the second year of passed survey series shall be made 
less stringent as follows:
    (i) The required average VOC emissions reduction shall be decreased 
by 1.0%; and
    (ii) The minimum VOC emissions reduction shall be decreased by 1.0%.
    (4) In the event that a covered area for which the required VOC 
emissions reductions have been made less stringent fails a subsequent 
VOC emissions reduction survey:
    (i) The required average VOC emission reductions for that covered 
area beginning in the year following this subsequent failure shall be 
made more stringent by increasing the required average and the minimum 
VOC emissions reduction by 1.0%; and
    (ii) The required VOC emission reductions for that covered area 
thereafter shall not be made less stringent regardless of the results of 
subsequent VOC emissions reduction surveys.
    (l) Effect of toxics survey failure. (1) On each occasion during 
1995 or 1996 that a covered area fails a simple model toxics emissions 
reduction survey series, conducted pursuant to Sec. 80.68, the simple 
model toxics emissions reduction requirement for that covered area 
beginning in the year following the year of the failure is made more 
stringent by increasing the average toxics emissions reduction by an 
additional 1.0%.
    (2) On each occasion that a covered area fails a complex model 
toxics emissions reduction survey series, conducted pursuant to Sec. 
80.68, or fails a simple model toxics emissions reduction survey series 
conducted pursuant to Sec. 80.68 during 1997, the complex model toxics 
emissions reduction requirement for that covered area beginning in the 
year following the year of the failure is made more stringent by 
increasing the average toxics emissions reduction by an additional 1.0%.
    (3) In the event that a covered area for which the toxics emissions 
standard has been made more stringent passes all toxics emissions survey 
series in two consecutive years, the averaging standard for toxics 
emissions reductions for that covered area beginning in the year 
following the second year of passed survey series shall be made less 
stringent by decreasing the average toxics emissions reduction by 1.0%.

[[Page 660]]

    (4) In the event that a covered area for which the toxics emissions 
reduction standard has been made less stringent fails a subsequent 
toxics emissions reduction survey series:
    (i) The standard for toxics emissions reduction for that covered 
area beginning in the year following this subsequent failure shall be 
made more stringent by increasing the average toxics emissions reduction 
by 1.0%; and
    (ii) The standard for toxics emissions reduction for that covered 
area thereafter shall not be made less stringent regardless of the 
results of subsequent toxics emissions reduction surveys.
    (m) Effect of NOX survey or survey series failure. (1) On 
each occasion that a covered area fails a NOX emissions 
reduction survey or survey series conducted pursuant to Sec. 80.68, the 
required average NOX emissions reductions for that covered 
area beginning in the year following the failure shall be increased in 
stringency by an additional 1.0%.
    (2) In the event that a covered area for which required 
NOX emissions reductions have been made more stringent passes 
all NOX emissions reduction surveys and survey series in two 
consecutive years, the required average NOX emissions 
reductions for that covered area beginning in the year following the 
second year of passed surveys and survey series shall be decreased in 
stringency by 1.0%.
    (3) In the event that a covered area for which the required 
NOX emissions reductions have been made less stringent fails 
a subsequent NOX emissions reduction survey or survey series:
    (i) The required average NOX emission reductions for that 
covered area beginning in the year following this subsequent failure 
shall be increased in stringency by 1.0%; and
    (ii) The required NOX emission reductions for that 
covered area thereafter shall not be made less stringent regardless of 
the results of subsequent NOX emissions reduction surveys or 
survey series.
    (n) Effect of benzene survey failure. (1) On each occasion that a 
covered area fails a benzene content survey series, conducted pursuant 
to Sec. 80.68, the benzene content standards for that covered area 
beginning in the year following the year of the failure shall be made 
more stringent as follows:
    (i) The average benzene content shall be decreased by 0.05% by 
volume; and
    (ii) The maximum benzene content for each gallon of averaged 
gasoline shall be decreased by 0.10% by volume.
    (2) In the event that a covered area for which the benzene standards 
have been made more stringent passes all benzene content survey series 
conducted in two consecutive years, the benzene standards for that 
covered area beginning in the year following the second year of passed 
survey series shall be made less stringent as follows:
    (i) The average benzene content shall be increased by 0.05% by 
volume; and
    (ii) The maximum benzene content for each gallon of averaged 
gasoline shall be increased by 0.10% by volume.
    (3) In the event that a covered area for which the benzene standards 
have been made less stringent fails a subsequent benzene content survey 
series:
    (i) The standards for benzene content for that covered area 
beginning in the year following this subsequent failure shall be the 
more stringent standards which were in effect prior to the operation of 
paragraph (n)(2) of this section; and
    (ii) The standards for benzene content for that covered area 
thereafter shall not be made less stringent regardless of the results of 
subsequent benzene content surveys.
    (o) [Reserved]
    (p) Effective date for changed minimum or maximum standards. In the 
case of any minimum or maximum standard that is changed to be more 
stringent by operation of paragraphs (k), (m), (n), or (o) of this 
section, the effective date for such change shall be the following 
number of days after the date EPA announces the change:
    (1) 90 days for refinery or import facilities;
    (2) 180 days for retail outlets and wholesale purchaser-consumer 
facilities; and
    (3) 150 days for all other facilities.
    (q) Refineries and importers subject to adjusted standards. 
Standards for average compliance that are adjusted to be more or less 
stringent by operation of

[[Page 661]]

paragraphs (k), (l) (m) or (n) of this section apply to average 
reformulated gasoline produced at each refinery or imported by each 
importer as follows:
    (1) Adjusted standards for a covered area apply to averaged 
reformulated gasoline that is produced at a refinery if:
    (i) Any averaged reformulated gasoline from that refinery supplied 
the covered area during any year a survey was conducted which gave rise 
to a standards adjustment; or
    (ii) Any averaged reformulated gasoline from that refinery supplies 
the covered area during any year that the standards are more stringent 
than the initial standards; unless
    (iii) The refiner is able to show that the volume of averaged 
reformulated gasoline from a refinery that supplied the covered area 
during any years under paragraphs (q)(1)(i) or (ii) of this section was 
less than one percent of the reformulated gasoline produced at the 
refinery during that year, or 100,000 barrels, whichever is less.
    (2) Adjusted standards for a covered area apply to averaged 
reformulated gasoline that is imported by an importer if:
    (i) The covered area with the adjusted standard is located in 
Petroleum Administration for Defense District (PADD) I, and the gasoline 
is imported at a facility located in PADDs I, II or III;
    (ii) The covered area with the adjusted standard is located in PADD 
II, and the gasoline is imported at a facility located in PADDs I, II, 
III, or IV;
    (iii) The covered area with the adjusted standard is located in PADD 
III, and the gasoline is imported at a facility located in PADDs II, 
III, or IV;
    (iv) The covered area with the adjusted standard is located in PADD 
IV, and the gasoline is imported at a facility located in PADDs II, or 
IV; or
    (v) The covered area with the adjusted standard is located in PADD 
V, and the gasoline is imported at a facility located in PADDs III, IV, 
or V; unless
    (vi) Any gasoline which is imported by an importer at any facility 
located in any PADD supplies the covered area, in which case the 
adjusted standard also applies to averaged gasoline imported at that 
facility by that importer.
    (3) Any gasoline that is transported in a fungible manner by a 
pipeline, barge, or vessel shall be considered to have supplied each 
covered area that is supplied with any gasoline by that pipeline, or 
barge or vessel shipment, unless the refiner or importer is able to 
establish that the gasoline it produced or imported was supplied only to 
a smaller number of covered areas.
    (4) Adjusted standards apply to all averaged reformulated gasoline 
produced by a refinery or imported by an importer identified in this 
paragraph (q), except:
    (i) In the case of adjusted VOC standards for a covered area located 
in VOC Control Region 1, the adjusted VOC standards apply only to 
averaged reformulated gasoline designated as VOC-controlled intended for 
use in VOC Control Region 1; and
    (ii) In the case of adjusted VOC standards for a covered area 
located in VOC Control Region 2, the adjusted VOC standards apply only 
to averaged reformulated gasoline designated as VOC-controlled intended 
for use in VOC Control Region 2.
    (r) Definition of PADD. For the purposes of this section only, the 
following definitions of PADDs apply:
    (1) The following States are included in PADD I:

Connecticut
Delaware
District of Columbia
Florida
Georgia
Maine
Maryland
Massachusetts
New York
New Hampshire
New Jersey
North Carolina
Pennsylvania
Rhode Island
South Carolina
Vermont
Virginia
West Virginia

    (2) 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

    (3) The following States are included in PADD III:


[[Page 662]]


Alabama
Arkansas
Louisiana
Mississippi
New Mexico
Texas

    (4) The following States are included in PADD IV:

Colorado
Idaho
Montana
Utah
Wyoming

    (5) The following States are included in PADD V:

Arizona
California
Nevada
Oregon
Washington

[59 FR 7813, Feb. 16, 1994, as amended at 59 FR 36958, July 20, 1994; 61 
FR 12041, Mar. 25, 1996; 62 FR 68205, Dec. 31, 1997; 64 FR 37689, July 
13, 1999; 66 FR 37164, July 17, 2001; 71 FR 74566, Dec. 15, 2005; 71 FR 
8972, Feb. 22, 2006; 71 FR 26698, May 8, 2006; 72 FR 8543, Feb. 26, 
2007]



Sec. 80.42  Simple emissions model.

    (a) VOC emissions. The following equations shall comprise the simple 
model for VOC emissions. The simple model for VOC emissions shall be 
used only in determining toxics emissions:

Summer = The period of May 1 through September 15
Winter = The period of September 16 through April 30
EXHVOCS1 = Exhaust nonmethane, nonethane VOC emissions from the fuel in 
question, in grams per mile, for VOC control region 1 during the summer 
period.
EXHVOCS2 = Exhaust nonmethane, nonethane VOC emissions from the fuel in 
question, in grams per mile, for VOC control region 2 during the summer 
period.
EXHVOCW = Exhaust nonmethane, nonethane VOC emissions from the fuel in 
question, in grams per mile, during the winter period.
EVPVOCS1 = Evaporative nonmethane, nonethane VOC emissions from the fuel 
in question, in grams per mile, for VOC control region 1 during the 
summer period.
EVPVOCS2 = Evaporative nonmethane, nonethane VOC emissions from the fuel 
in question, in grams per mile, for VOC control region 2 during the 
summer period.
RLVOCS1 = Running loss nonmethane, nonethane VOC emissions from the fuel 
in question, in grams per mile, for VOC control region 1 during the 
summer period.
RLVOCS2 = Running loss nonmethane, nonethane VOC emissions from the fuel 
in question, in grams per mile, for VOC control region 2 during the 
summer period.
REFVOCS1 = Refueling nonmethane, nonethane VOC emissions from the fuel 
in question, in grams per mile, for VOC control region 1 during the 
summer period.
REFVOCS2 = Refueling nonmethane, nonethane VOC emissions from the fuel 
in question, in grams per mile, for VOC control region 2 during the 
summer period.
OXCON = Oxygen content of the fuel in question, in terms of weight 
percent (as measured under Sec. 80.46)
RVP = Reid vapor pressure of the fuel in question, in pounds per square 
inch (psi)

    (1) The following equations shall comprise the simple model for VOC 
emissions in VOC Control Region 1 during the summer period:

EXHVOCS1 = 0.444x(1-(0.127/2.7)xOXCON)
EVPVOCS1 = 0.7952-0.2461xRVP +0.02293xRVPxRVP
RLVOCS1 = -0.734+0.1096xRVP +0.002791xRVPxRVP
REFVOCS1 = 0.04x((0.1667xRVP)-0.45)

    (2) The following equations shall comprise the simple model for VOC 
emissions in VOC Control Region 2 during the summer period:

EXHVOCS2 = 0.444 x (1 - (0.127/2.7) x OXCON)
EVPVOCS2 = 0.813 - 0.2393 x RVP + 0.021239 x RVP x RVP
RLVOCS2 = 0.2963 - 0.1306 x RVP + 0.016255 x RVP x RVP
REFVOCS2 = 0.04 x ((0.1667 x RVP) - 0.45)

    (3) The following equation shall comprise the simple model for VOC 
emissions during the winter period:

EXHVOCW = 0.656 x (1 - (0.127/2.7) x OXCON)

    (b) Toxics emissions. The following equations shall comprise the 
simple model for toxics emissions:

EXHBEN = Exhaust benzene emissions from the fuel in question, in 
milligrams per mile
EVPBEN = Evaporative benzene emissions from the fuel in question, in 
milligrams per mile
HSBEN = Hot soak benzene emissions from the fuel in question, in 
milligrams per mile
DIBEN = Diurnal benzene emissions from the fuel in question, in 
milligrams per mile
RLBEN = Running loss benzene emissions from the fuel in question, in 
milligrams per mile
REFBEN = Refueling benzene emissions from the fuel in question, in 
milligrams per mile
MTBE = Oxygen content of the fuel in question in the form of MTBE, in 
terms of weight percent (as measured under Sec. 80.46)
ETOH = Oxygen content of the fuel in question in the form of ethanol, in 
terms of weight percent (as measured under Sec. 80.46)
ETBE = Oxygen content of the fuel in question in the form of ETBE, in 
terms of weight percent (as measured under Sec. 80.46)

[[Page 663]]

FORM = Formaldehyde emissions from the fuel in question, in milligrams 
per mile
ACET = Acetaldehyde emissions from the fuel in question, in milligrams 
per mile
POM = Emissions of polycyclic organic matter from the fuel in question, 
in milligrams per mile
BUTA = Emissions of 1,3-Butadiene from the fuel in question, in 
milligrams per mile
FBEN = Fuel benzene of the fuel in question, in terms of volume percent 
(as measured under Sec. 80.46)
FAROM = Fuel aromatics of the fuel in question, in terms of volume 
percent (as measured under Sec. 80.46)
TOXREDS1 = Total toxics reduction of the fuel in question during the 
summer period for VOC control region 1 in percent
TOXREDS2 = Total toxics reduction of the fuel in question during the 
summer period for VOC control region 2 in percent
TOXREDW = Total toxics reduction of the fuel in question during the 
winter period in percent

    (1) The following equations shall comprise the simple model for 
toxics emissions in VOC control region 1 during the summer period:

TOXREDS1 = [100 x (53.2 -EXHBEN - EVPBEN - RLBEN - REFBEN - FORM - ACET 
- BUTA - POM)] / 53.2
EXHBEN = [1.884+0.949 x FBEN + 0.113 x (FAROM - FBEN)) / 100] x 1000 x 
EXHVOCS1
EVPBEN = HSBEN + DIBEN
HSBEN = FBEN x (EVPVOCS1 x 0.679) x 1000 x [(1.4448 - (0.0684 x MTBE/
2.0) - (0.080274 x RVP)) / 100]
DIBEN = FBEN x (EVPVOCS1 x 0.321) x 1000 x [(1.3758 - (0.0579 x MTBE/
2.0) - (0.080274 x RVP)) / 100]
RLBEN = FBEN x RLVOCS1 x 1000 x [(1.4448 - (0.0684 x MTBE/2.0) - 
(0.080274 x RVP)) / 100]
REFBEN = FBEN x REFVOCS1 x 1000 x [(1.3972 - (0.0591 x MTBE / 2.0) - 
(0.081507 x RVP)) / 100] BUTA = 0.00556 x EXHVOCS1 x 1000
POM = 3.15 x EXHVOCS1

    (i) For any oxygenate or mixtures of oxygenates, the formaldehyde 
and acetaldehyde shall be calculated with the following equations:

FORM = 0.01256 x EXHVOCS1 x 1000 x [1 + (0.421 / 2.7) x MTBE + TAME) + 
(0.358 / 3.55) x ETOH + (0.137 / 2.7) x (ETBE + ETAE)]
ACET = 0.00891 x EXHVOCS1 x 1000 x [1 + (0.078 / 2.7) x (MTBE + TAME) + 
(0.865 / 3.55) x ETOH + (0.867 / 2.7) x (ETBE + ETAE)]

    (ii) When calculating formaldehyde and acetaldehyde emissions using 
the equations in paragraph (b)(1)(i) of this section, oxygen in the form 
of alcohols which are more complex or have higher molecular weights than 
ethanol shall be evaluated as if it were in the form of ethanol. Oxygen 
in the form of methyl ethers other than TAME and MTBE shall be evaluated 
as if it were in the form of MTBE. Oxygen in the form of ethyl ethers 
other than ETBE shall be evaluated as if it were in the form of ETBE. 
Oxygen in the form of non-methyl, non-ethyl ethers shall be evaluated as 
if it were in the form of ETBE. Oxygen in the form of methanol or non-
alcohol, non-ether oxygenates shall not be evaluated with the Simple 
Model, but instead must be evaluated through vehicle testing under the 
Complex Model per Sec. 80.48.
    (2) The following equations shall comprise the simple model for 
toxics emissions in VOC control region 2 during the summer period:

TOXREDS2 = 100 x (52.1 - EXHBEN - EVPBEN - RLBEN - REFBEN - FORM - ACET 
- BUTA - POM) / 52.1
EXHBEN = [(1.884 + 0.949 x FBEN + 0.113 x (FAROM - FBEN)) / 100] x 1000 
x EXHVOCS2
EVPBEN = HSBEN + DIBEN
HSBEN = FBEN x (EVPVOCS2 x 0.679) x 1000 x [(1.4448 - (0.0684 x MTBE / 
2.0) - (0.080274 x RVP)) / 100]
DIBEN = FBEN x (EVPVOCS2 x 0.321) x 1000 x [(1.3758 - (0.0579 x MTBE / 
2.0) - (0.080274 x RVP)) / 100]
RLBEN = FBEN x RLVOCS2 x 1000 x [(1.4448 - (0.0684 x MTBE / 2.0) - 
(0.080274 x RVP)) / 100]
REFBEN = FBEN x REFVOCS2 x 1000 x [(1.3972 - (0.0591 x MTBE / 2.0) - 
(0.081507 x RVP)) / 100]
BUTA = 0.00556 x EXHVOCS2 x 1000
POM = 3.15 x EXHVOCS2

    (i) For any oxygenate or mixtures of oxygenates, the formaldehyde 
and acetaldehyde shall be calculated with the following equations:

FORM = 0.01256 x EEXHVOCS2 x 1000 x [1 + (0.421 / 2.7) x (MTBE + TAME) + 
(0.358 / 3.55) x ETOH + (0.137 / 2.7) x (ETBE + ETAE)]
ACET = 0.00891 x EXHVOCS2 x 1000 x [1 + (0.078 / 2.7) x (MTBE + TAME) + 
(0.865 / 3.55) x ETOH + (0.867 / 2.7) x (ETBE + ETAE)]

    (ii) When calculating formaldehyde and acetaldehyde emissions using 
the equations in paragraph (b)(2)(i) of this section, oxygen in the form 
of alcohols which are more complex or have higher molecular weights than 
ethanol shall be evaluated as if it were in the form of

[[Page 664]]

ethanol. Oxygen in the form of methyl ethers other than TAME and MTBE 
shall be evaluated as if it were in the form of MTBE. Oxygen in the form 
of ethyl ethers other than ETBE shall be evaluated as if it were in the 
form of ETBE. Oxygen in the form of non-methyl, non-ethyl ethers shall 
be evaluated as if it were in the form of ETBE. Oxygen in the form of 
methanol or non-alcohol, non-ether oxygenates shall not be evaluated 
with the Simple Model, but instead must be evaluated through vehicle 
testing under the Complex Model per Sec. 80.48.
    (3) The following equations shall comprise the simple model for 
toxics emissions during the winter period:

TOXREDW = 100 x (55.5 - EXHBEN - FORM - ACET - BUTA - POM) / 55.5
EXHBEN = [(1.884 + 0.949 x FBEN + 0.113 x (FAROM - FBEN)) / 100] x 1000 
x EXHVOCW
BUTA = 0.00556 x EXHVOCW x 1000
POM = 2.13 x EXHVOCW

    (i) For any oxygenate or mixtures of oxygenates, the formaldehyde 
and acetaldehyde shall be calculated with the following equations:

FORM = 0.01256 x EXHVOCS1 x 1000 x [1 + (0.421 / 2.7) x (MTBE + TAME) + 
(0.358 / 3.55) x ETOH + (0.137 / 2.7) x (ETBE + ETAE)]
ACET = 0.00891 x EXHVOCS1 x 1000 x [1 + (0.078 / 2.7) x (MTBE + TAME) + 
(0.865 / 3.55) x ETOH + (0.867 / 2.7) x (ETBE + ETAE)]

    (ii) When calculating formaldehyde and acetaldehyde emissions using 
the equations in paragraph (b)(3)(i) of this section, oxygen in the form 
of alcohols which are more complex or have higher molecular weights than 
ethanol shall be evaluated as if it were in the form of ethanol. Oxygen 
in the form of methyl ethers other than TAME and MTBE shall be evaluated 
as if it were in the form of MTBE. Oxygen in the form of ethyl ethers 
other than ETBE shall be evaluated as if it were in the form of ETBE. 
Oxygen in the form of non-methyl, non-ethyl ethers shall be evaluated as 
if it were in the form of ETBE. Oxygen in the form of methanol or non-
alcohol, non-ether oxygenates shall not be evaluated with the Simple 
Model, but instead must be evaluated through vehicle testing under the 
Complex Model per Sec. 80.48.
    (4) If the fuel aromatics content of the fuel in question is less 
than 10 volume percent, then an FAROM value of 10 volume percent shall 
be used when evaluating the toxics emissions equations given in 
paragraphs (b)(1), (b)(2), and (b)(3) of this section.
    (c) Limits of the model. (1) The model given in paragraphs (a) and 
(b) of this section shall be used as given to determine VOC and toxics 
emissions, respectively, if the properties of the fuel being evaluated 
fall within the ranges shown in this paragraph (c). If the properties of 
the fuel being evaluated fall outside the range shown in this paragraph 
(c), the model may not be used to determine the VOC or toxics 
performance of the fuel:

------------------------------------------------------------------------
             Fuel parameter                           Range
------------------------------------------------------------------------
Benzene content........................  0.0-4.9 vol %.
RVP....................................  6.6-9.0 psi.\1\
Oxygenate content......................  0-4.0 wt %.
Aromatics content......................  0-55 vol %.
------------------------------------------------------------------------
\1\ For gasoline sold in California, the applicable RVP range shall be
  6.4-9.0 psi.

    (2) The model given in paragraphs (a) and (b) of this section shall 
be effective from January 1, 1995 through December 31, 1997, unless 
extended by action of the Administrator.

[59 FR 7813, Feb. 16, 1994, as amended at 59 FR 36958, July 20, 1994; 61 
FR 20738, May 8, 1996]



Sec. Sec. 80.43-80.44  [Reserved]



Sec. 80.45  Complex emissions model.

    (a) Definition of terms. For the purposes of this section, the 
following definitions shall apply:

Target fuel = The fuel which is being evaluated for its emissions 
performance using the complex model
OXY = Oxygen content of the target fuel in terms of weight percent
SUL = Sulfur content of the target fuel in terms of parts per million by 
weight
RVP = Reid Vapor Pressure of the target fuel in terms of pounds per 
square inch
E200 = 200 [deg]F distillation fraction of the target fuel in terms of 
volume percent
E300 = 300 [deg]F distillation fraction of the target fuel in terms of 
volume percent
ARO = Aromatics content of the target fuel in terms of volume percent
BEN = Benzene content of the target fuel in terms of volume percent
OLE = Olefins content of the target fuel in terms of volume percent

[[Page 665]]

MTB = Methyl tertiary butyl ether content of the target fuel in terms of 
weight percent oxygen
ETB = Ethyl tertiary butyl ether content of the target fuel in terms of 
weight percent oxygen
TAM = Tertiary amyl methyl ether content of the target fuel in terms of 
weight percent oxygen
ETH = Ethanol content of the target fuel in terms of weight percent 
oxygen
exp = The function that raises the number e (the base of the natural 
logarithm) to the power in its domain
Phase I = The years 1995-1999
Phase II = Year 2000 and beyond

    (b) Weightings and baselines for the complex model. (1) The 
weightings for normal and higher emitters (w1 and 
w2, respectively) given in table 1 shall be used to calculate 
the exhaust emission performance of any fuel for the appropriate 
pollutant and Phase:

   Table 1--Normal and Higher Emitter Weightings for Exhaust Emissions
------------------------------------------------------------------------
                                           Phase I          Phase II
                                     -----------------------------------
                                       VOC &             VOC &
                                       toxics    NOX     toxics    NOX
------------------------------------------------------------------------
Normal Emitters (w1)................     0.52     0.82    0.444    0.738
Higher Emitters (w2)................     0.48     0.18    0.556    0.262
------------------------------------------------------------------------

    (2) The following properties of the baseline fuels shall be used 
when determining baseline mass emissions of the various pollutants:

           Table 2--Summer and Winter Baseline Fuel Properties
------------------------------------------------------------------------
                   Fuel property                      Summer     Winter
------------------------------------------------------------------------
Oxygen (wt %).....................................       0.0        0.0
Sulfur (ppm)......................................     339        338
RVP (psi).........................................       8.7       11.5
E200 (%)..........................................      41.0       50.0
E300 (%)..........................................      83.0       83.0
Aromatics (vol %).................................      32.0       26.4
Olefins (vol %)...................................       9.2       11.9
Benzene (vol %)...................................       1.53       1.64
------------------------------------------------------------------------

    (3) The baseline mass emissions for VOC, NOX and toxics 
given in tables 3, 4 and 5 of this paragraph (b)(3) shall be used in 
conjunction with the complex model during the appropriate Phase and 
season:

                   Table 3--Baseline Exhaust Emissions
------------------------------------------------------------------------
                                           Phase I          Phase II
                                     -----------------------------------
          Exhaust pollutant            Summer   Winter   Summer   Winter
                                        (mg/     (mg/     (mg/     (mg/
                                       mile)    mile)    mile)    mile)
------------------------------------------------------------------------
VOC.................................    446.0    660.0    907.0   1341.0
NOX.................................    660.0    750.0   1340.0   1540.0
Benzene.............................    26.10    37.57    53.54    77.62
Acetaldehyde........................     2.19     3.57     4.44     7.25
Formaldehyde........................     4.85     7.73     9.70    15.34
1,3-Butadiene.......................     4.31     7.27     9.38    15.84
POM.................................     1.50     2.21     3.04     4.50
------------------------------------------------------------------------


          Table 4--Baseline Non-Exhaust Emissions (Summer Only)
------------------------------------------------------------------------
                                           Phase I          Phase II
                                     -----------------------------------
        Non-exhaust pollutant          Region   Region   Region   Region
                                       1 (mg/   2 (mg/   1 (mg/   2 (mg/
                                       mile)    mile)    mile)    mile)
------------------------------------------------------------------------
VOC.................................   860.48   769.10   559.31   492.07
Benzene.............................     9.66     8.63     6.24     5.50
------------------------------------------------------------------------


                                                  Table 5--Total Baseline VOC, NOX and Toxics Emissions
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                                         Summer (mg/mile)                                Winter (mg/mile)
                                                         -----------------------------------------------------------------------------------------------
                        Pollutant                                 Phase I                Phase II                 Phase I                Phase II
                                                         -----------------------------------------------------------------------------------------------
                                                           Region 1    Region 2    Region 1    Region 2    Region 1    Region 2    Region 1    Region 2
--------------------------------------------------------------------------------------------------------------------------------------------------------
NOX.....................................................      660.0       660.0      1340.0      1340.0       750.0       750.0      1540.0      1540.0
VOC.....................................................     1306.5      1215.1      1466.3      1399.1       660.0       660.0      1341.0      1341.0
Toxics..................................................       48.61       47.58       86.34       85.61       58.36       58.36      120.55      120.55
--------------------------------------------------------------------------------------------------------------------------------------------------------

    (c) VOC performance. (1) The exhaust VOC emissions performance of 
gasolines shall be given by the following equations:

VOCE = VOC(b)+(VOC(b)xYvoc(t)/100)
Yvoc(t) = 
    [lsqbb](w1xNv)+(w2xHv)-
    1[rsqbb]x100

where

VOCE = Exhaust VOC emissions in milligrams/mile
Yvoc(t) = Exhaust VOC performance of the target fuel in terms 
of percentage change from baseline

[[Page 666]]

VOC(b) = Baseline exhaust VOC emissions as defined in paragraph (b)(2) 
of this section for the appropriate Phase and season
Nv = [exp v1(t)]/[exp v1(b)]
Hv = [exp v2(t)]/[exp v2(b)]
w1 = Weighting factor for normal emitters as defined in 
paragraph (b)(1) of this section for the appropriate Phase
w2 = Weighting factor for higher emitters as defined in 
paragraph (b)(1) of this section for the appropriate Phase
v1(t) = Normal emitter VOC equation as defined in paragraph 
(c)(1)(i) of this section, evaluated using the target fuel's properties 
subject to paragraphs (c)(1) (iii) and (iv) of this section
v2(t) = Higher emitter VOC equation as defined in paragraph 
(c)(1)(ii) of this section, evaluated using the target fuel's properties 
subject to paragraphs (c)(1) (iii) and (iv) of this section
v1(b) = Normal emitter VOC equation as defined in paragraph 
(c)(1)(i) of this section, evaluated using the base fuel's properties
v2(b) = Higher emitter VOC equation as defined in paragraph 
(c)(1)(ii) of this section, evaluated using the base fuel's properties

    (i) Consolidated VOC equation for normal emitters.

v1 = (-0.003641 x OXY) + (0.0005219 x SUL) + (0.0289749 x 
    RVP) + (-0.014470 x E200) + (-0.068624 x E300) + (0.0323712 x ARO) + 
    (-0.002858 x OLE) + (0.0001072 x E2002) + (0.0004087 x E3002) + (-
    0.0003481 x ARO x E300)

    (ii) VOC equation for higher emitters.

v2 = (-0.003626 x OXY) + (-5.40x10-5 x SUL) + 
    (0.043295 x RVP) + (-0.013504 x E200) + (-0.062327 x E300) + 
    (0.0282042 x ARO) + (-0.002858 x OLE) + (0.000106 x E200\2\) + 
    (0.000408 x E300\2\) + (-0.000287 x ARO x E300)

    (iii) Flat line extrapolations. (A) During Phase I, fuels with E200 
values greater than 65.83 percent shall be evaluated with the E200 fuel 
parameter set equal to 65.83 percent when calculating Yvoc(t) 
and VOCE using the equations described in paragraphs (c)(1) (i) and (ii) 
of this section. Fuels with E300 values greater than E300* (calculated 
using the equation E300* = 80.32+[0.390xARO]) shall be evaluated with 
the E300 parameter set equal to E300* when calculating VOCE using the 
equations described in paragraphs (c)(1) (i) and (ii) of this section. 
For E300* values greater than 94, the linearly extrapolated model 
presented in paragraph (c)(1)(iv) of this section shall be used.
    (B) During Phase II, fuels with E200 values greater than 65.52 
percent shall be evaluated with the E200 fuel parameter set equal to 
65.52 percent when calculating VOCE using the equations described in 
paragraphs (c)(1) (i) and (ii) of this section. Fuels with E300 values 
greater than E300* (calculated using the equation E300* = 79.75+[0.385 x 
ARO]) shall be evaluated with the E300 parameter set equal to E300* when 
calculating VOCE using the equations described in paragraphs (c)(1) (i) 
and (ii) of this section. For E300* values greater than 94, the linearly 
extrapolated model presented in paragraph (c)(1)(iv) of this section 
shall be used.
    (iv) Linear extrapolations. (A) The equations in paragraphs (c)(1) 
(i) and (ii) of this section shall be used within the allowable range of 
E300, E200, and ARO for the appropriate Phase, as defined in table 6:

 Table 6--Allowable Ranges of E200, E300, and ARO for the Exhaust VOC Equations in Paragraphs (c)(1)(i) and (ii)
                                                 of This Section
----------------------------------------------------------------------------------------------------------------
                                                        Phase I                            Phase II
                                         -----------------------------------------------------------------------
             Fuel parameter                Lower                               Lower
                                           limit          Higher limit         limit          Higher limit
----------------------------------------------------------------------------------------------------------------
E200....................................    33.00  65.83....................    33.00  65.52
E300....................................    72.00  Variable\1\..............    72.00  Variable \2\
ARO.....................................    18.00  46.00....................    18.00  46.00
----------------------------------------------------------------------------------------------------------------
\1\ Higher E300 limit = lower of 94.0 or 80.32+[0.390x(ARO)].
\2\ Higher E300 limit = lower of 94.0 or 79.75+[0.385x(ARO)].

    (B) For fuels with E200, E300 and/or ARO levels outside the ranges 
defined in table 6, YVOC(t) shall be defined:
    (1) For Phase I:

YVOC(t) = 100% x 0.52 x [exp(v1(et)) / 
    exp(v1(b)) - 1] + 100% x 0.48 x [exp(v2(et)) / 
    exp(v2(b)) - 1] + {100% x 0.52 x [exp(v\1\(et)) / 
    exp(v1(b))] x [{[(0.0002144 x E200et) - 
    0.014470] x [Delta]E200{time}  + {[(0.0008174 x E300et) - 
    0.068624 - (0.000348 x AROet)] x [Delta]E300{time}  + 
    {[(-0.000348 x E300et) + .0323712] x 
    [Delta]ARO{time} ]{time}  + {100% x 0.48 x [exp(v1(et)) / 
    exp(v2(b)){time} ] x [{[(0.000212 x E200et) - 
    0.01350] x [Delta]E200{time}  + {[(0.000816 x E300et) - 
    0.06233 - (0.00029 x AROet)] x [Delta]E300{time}  + {[(-
    0.00029 x E300{time} ) + 0.028204] x [Delta]ARO{time} ]{time} 

    (2) For Phase II:


[[Page 667]]


YVOC(t) = 100% x 0.444 x [exp(v1(et)) / 
    exp(v1(b)) - 1] + 100% x 0.556 x [exp(v2(et)) 
    / exp(v2(b)) - 1] + {100% x 0.444 x 
    [exp(v1(et)) / exp(v1(b))] x [{[(0.0002144 x 
    E200et) - 0.014470] x [Delta]E200{time}  + {[(0.0008174 x 
    E300et) - 0.068624 - (0.000348 x AROet)] x 
    [Delta]E300{time}  + {[(-0.000348 x E300et) + 0.0323712] 
    x [Delta]ARO{time} ]{time}  + {100% x 0.556 x 
    [exp(v2(et)) / exp(v2(b))] x [{[(0.000212 x 
    E200et) - 0.01350] x [Delta]E200{time}  + {[(0.000816 x 
    E300et) - 0.06233 - (0.00029 x AROet)] x 
    [Delta]E300{time}  + {[(-0.00029 x E300et) + 0.028204] x 
    [Delta]ARO{time} ]{time} 

    (C) During Phase I, the ``edge target'' fuel shall be identical to 
the target fuel for all fuel parameters, with the following exceptions:
    (1) If the E200 level of the target fuel is less than 33 volume 
percent, then the E200 value for the ``edge target'' fuel shall be set 
equal to 33 volume percent.
    (2) If the aromatics level of the target fuel is less than 18 volume 
percent, then the ARO value for the ``edge target'' fuel shall be set 
equal to 18 volume percent.
    (3) If the aromatics level of the target fuel is greater than 46 
volume percent, then the ARO value for the ``edge target'' fuel shall be 
set equal to 46 volume percent.
    (4) If the E300 level of the target fuel is less than 72 volume 
percent, then the E300 value for the ``edge target'' fuel shall be set 
equal to 72 volume percent.
    (5) If the E300 level of the target fuel is greater than 95 volume 
percent, then the E300 value of the target fuel shall be set equal to 95 
volume percent for the purposes of calculating VOC emissions with the 
Phase I equation given in paragraph (c)(1)(iv)(B) of this section.
    (6) If [80.32 + (0.390 x ARO)] exceeds 94 for the target fuel, and 
the target fuel value for E300 exceeds 94, then the E300 value for the 
``edge target'' fuel shall be set equal to 94 volume percent.
    (7) If the E200 level of the target fuel is less than 33 volume 
percent, then [Delta]E200 shall be set equal to (E200-33 volume 
percent).
    (8) If the E200 level of the target fuel equals or exceeds 33 volume 
percent, then [Delta]E200 shall be set equal to zero.
    (9) If the aromatics level of the target fuel is less than 18 volume 
percent, then [Delta]ARO shall be set equal to (ARO-18 volume percent). 
If the aromatics level of the target fuel is less than 10 volume 
percent, then [Delta]ARO shall be set equal to -8 volume percent.
    (10) If the aromatics level of the target fuel is greater than 46 
volume percent, then [Delta]ARO shall be set equal to (ARO-46 volume 
percent).
    (11) If neither of the conditions established in paragraphs 
(c)(1)(iv)(C)(9) and (10) of this section are met, then [Delta]ARO shall 
be set equal to zero.
    (12) If the E300 level of the target fuel is less than 72 percent, 
then [Delta]E300 shall be set equal to (E300-72 percent).
    (13) If the E300 level of the target fuel is greater than 94 volume 
percent and [80.32+(0.390xARO)] also is greater than 94, then 
[Delta]E300 shall be set equal to (E300-94 volume percent). If the E300 
level of the target fuel is greater than 95 volume percent and 
[80.32+(0.390xARO)] also is greater than 94, then [Delta]E300 shall be 
set equal to 1 volume percent.
    (14) If neither of the conditions established in paragraphs 
(c)(1)(iv)(C)(12) and (13) of this section are met, then [Delta]E300 
shall be set equal to zero.
    (D) During Phase II, the ``edge target'' fuel is identical to the 
target fuel for all fuel parameters, with the following exceptions:
    (1) If the E200 level of the target fuel is less than 33 volume 
percent, then the E200 value for the ``edge target'' fuel shall be set 
equal to 33 volume percent.
    (2) If the aromatics level of the target fuel is less than 18 volume 
percent, then the ARO value for the ``edge target'' fuel shall be set 
equal to 18 volume percent.
    (3) If the aromatics level of the target fuel is greater than 46 
volume percent, then the ARO value for the ``edge target'' fuel shall be 
set equal to 46 volume percent.
    (4) If the E300 level of the target fuel is less than 72 volume 
percent, then the E300 value for the ``edge target'' fuel shall be set 
equal to 72 volume percent.
    (5) If the E300 level of the target fuel is greater than 95 volume 
percent, then the E300 value of the target fuel shall be set equal to 95 
volume percent for the purposes of calculating VOC emissions with the 
Phase II equation given

[[Page 668]]

in paragraph (c)(1)(iv)(B) of this section.
    (6) If [79.75 + (0.385 x ARO)] exceeds 94 for the target fuel, and 
the target fuel value for E300 exceeds 94, then the E300 value for the 
``edge target'' fuel shall be set equal to 94 volume percent.
    (7) If the E200 level of the target fuel is less than 33 volume 
percent, then [Delta]E200 shall be set equal to (E200-33 volume 
percent).
    (8) If the E200 level of the target fuel equals or exceeds 33 volume 
percent, then [Delta]E200 shall be set equal to zero.
    (9) If the aromatics level of the target fuel is less than 18 volume 
percent and greater than or equal to 10 volume percent, then [Delta]ARO 
shall be set equal to (ARO-18 volume percent). If the aromatics level of 
the target fuel is less than 10 volume percent, then [Delta]ARO shall be 
set equal to -8 volume percent.
    (10) If the aromatics level of the target fuel is greater than 46 
volume percent, then [Delta]ARO shall be set equal to (ARO - 46 volume 
percent).
    (11) If neither of the conditions established in paragraphs 
(c)(1)(iv)(D)(9) and (10) of this section are met, then [Delta]ARO shall 
be set equal to zero.
    (12) If the E300 level of the target fuel is less than 72 percent, 
then [Delta]E300 shall be set equal to (E300 - 72 percent).
    (13) If the E300 level of the target fuel is greater than 94 volume 
percent and (79.75 + (0.385 x ARO)) also is greater than 94, then 
[Delta]E300 shall be set equal to (E300 - 94 volume percent). If the 
E300 level of the target fuel is greater than 95 volume percent and 
(79.75 + (0.385 x ARO)) also is greater than 94, then ``E300 shall be 
set equal to 1 volume percent.
    (2) The winter exhaust VOC emissions performance of gasolines shall 
be given by the equations presented in paragraph (c)(1) of this section 
with the RVP value set to 8.7 psi for both the baseline and target 
fuels.
    (3) The nonexhaust VOC emissions performance of gasolines in VOC 
Control Region 1 shall be given by the following equations, where:

VOCNE1 = Total nonexhaust emissions of volatile organic compounds in VOC 
Control Region 1 in grams per mile
VOCDI1 = Diurnal emissions of volatile organic compounds in VOC Control 
Region 1 in grams per mile
VOCHS1 = Hot soak emissions of volatile organic compounds in VOC Control 
Region 1 in grams per mile
VOCRL1 = Running loss emissions of volatile organic compounds in VOC 
Control Region 1 in grams per mile
VOCRF1 = Refueling emissions of volatile organic compounds in VOC 
Control Region 1 in grams per mile

    (i) During Phase I:

VOCNE1 = VOCDI1 + VOCHS1 + VOCRL1 + VOCRF1
VOCDI1 = [0.00736 x (RVP\2\)] - [0.0790 x RVP] + 0.2553
VOCHS1 = [0.01557 x (RVP\2\)] - [0.1671 x RVP] + 0.5399
VOCRL1 = [0.00279 x (RVP\2\)] + [0.1096 x RVP] - 0.7340
VOCRF1 = [0.006668 x RVP] - 0.0180

    (ii) During Phase II:

VOCNE1 = VOCDI1 + VOCHS1 + VOCRL1 + VOCRF1
VOCDI1 = [0.007385 x (RVP\2\)] - [0.08981 x RVP] + 0.3158
VOCHS1 = [0.006654 x (RVP\2\)] - [0.08094 x RVP] + 0.2846
VOCRL1 = [0.017768 x (RVP\2\)] - [0.18746 x RVP] + 0.6146
VOCRF1 = [0.004767 x RVP] + 0.011859

    (4) The nonexhaust VOC emissions performance of gasolines in VOC 
Control Region 2 shall be given by the following equations, where:

VOCNE2 = Total nonexhaust emissions of volatile organic compounds in VOC 
Control Region 2 in grams per mile
VOCDI2 = Diurnal emissions of volatile organic compounds in VOC Control 
Region 2 in grams per mile
VOCHS2 = Hot soak emissions of volatile organic compounds in VOC Control 
Region 2 in grams per mile
VOCRL2 = Running loss emissions of volatile organic compounds in VOC 
Control Region 2 in grams per mile
VOCRF2 = Refueling emissions of volatile organic compounds in VOC 
Control Region 2 in grams per mile

    (i) During Phase I:

VOCNE2 = VOCDI2 + VOCHS2 + VOCRL2 + VOCRF2
VOCDI2 = [0.006818 x (RVP\2\)] - [0.07682 x RVP] + 0.2610
VOCHS2 = [0.014421 x (RVP\2\)] - [0.16248 x RVP] + 0.5520
VOCRL2 = [0.016255 x (RVP\2\)] - [0.1306 x RVP] + 0.2963
VOCRF2 = [0.006668 x RVP] - 0.0180


[[Page 669]]


    (ii) During Phase II:

VOCNE2 = VOCDI2 + VOCHS2 + VOCRL2 + VOCRF2
VOCDI2 = [0.004775 x (RVP\2\)] - [0.05872 x RVP] + 0.21306
VOCHS2 = [0.006078 x (RVP\2\)] - [0.07474 x RVP] + 0.27117
VOCRL2 = [0.016169 x (RVP\2\)] - [0.17206 x RVP] + 0.56724
VOCRF2 = [0.004767 x RVP] + 0.011859

    (5) Winter VOC emissions shall be given by VOCE, as defined in 
paragraph (c)(2) of this section, using the appropriate baseline 
emissions given in paragraph (b)(3) of this section. Total nonexhaust 
VOC emissions shall be set equal to zero under winter conditions.
    (6) Total VOC emissions. (i) Total summer VOC emissions shall be 
given by the following equations:

VOCS1 = (VOCE / 1000) + VOCNE1
VOCS2 = (VOCE / 1000) + VOCNE2
VOCS1 = Total summer VOC emissions in VOC Control Region 1 in terms of 
grams per mile
VOCS2 = Total summer VOC emissions in VOC Control Region 2 in terms of 
grams per mile

    (ii) Total winter VOC emissions shall be given by the following 
equations:

VOCW = (VOCE/1000)
VOCW = Total winter VOC emissions in terms of grams per mile

    (7) Phase I total VOC emissions performance. (i) The total summer 
VOC emissions performance of the target fuel in percentage terms from 
baseline levels shall be given by the following equations during Phase 
I:

VOCS1% = [100% x (VOCS1-1.306 g/mi)]/(1.306 g/mi)
VOCS2% = [100% x (VOCS2-1.215 g/mi)]/(1.215 g/mi)
VOC1% = Percentage change in VOC emissions from baseline levels in VOC 
    Control Region 1
VOC2% = Percentage change in VOC emissions from baseline levels in VOC 
    Control Region 2

    (ii) The total winter VOC emissions performance of the target fuel 
in percentage terms from baseline levels shall be given by the following 
equations during Phase I:

VOCW% = [100% x (VOCW-0.660 g/mi)]/(0.660 g/mi)
VOCW% = Percentage change in winter VOC emissions from baseline levels

    (8) Phase II total VOC emissions performance. (i) The total summer 
VOC emissions performance of the target fuel in percentage terms from 
baseline levels shall be given by the following equations during Phase 
II:

VOCS1% = [100% x (VOCS1-1.4663 g/mi)]/(1.4663 g/mi)
VOCS2% = [100% x (VOCS2-1.3991 g/mi)]/(1.3991 g/mi)

    (ii) The total winter VOC emissions performance of the target fuel 
in percentage terms from baseline levels shall be given by the following 
equation during Phase II:

VOCW% = [100% x (VOC -1.341 g/mi)] / (1.341 g/mi)

    (d) NOX performance. (1) The summer NOX 
emissions performance of gasolines shall be given by the following 
equations:

NOX = NOX(b)+[NOX(b) x Y(t)/100]
YNOX(t) = [lsqbb](w1 x 
    Nn)+(w2 x Hn)-1[rsqbb] x 100

where

NOX = NOX emissions in milligrams/mile
YNOx(t) = NOX performance of target fuel in terms 
of percentage change from baseline
NOX(b) = Baseline NOX emissions as defined in 
paragraph (b)(2) of this section for the appropriate phase and season
Nn = exp n1(t)/exp n1(b)
Hn = exp n2(t)/exp n2(b)
w1 = Weighting factor for normal emitters as defined in 
paragraph (b)(1) of this section for the appropriate Phase
w2 = Weighting factor for higher emitters as defined in 
paragraph (b)(1) of this section for the appropriate Phase
n1(t) = Normal emitter NOX equation as defined in 
paragraph (d)(1)(i) of this section, evaluated using the target fuel's 
properties subject to paragraphs (d)(1)(iii) and (iv) of this section
n2(t) = Higher emitter NOX equation as defined in 
paragraph (d)(1)(ii) of this section, evaluated using the target fuel's 
properties subject to paragraphs (d)(1)(iii) and (iv) of this section
n1(b) = Normal emitter NOX equation as defined in 
paragraph (d)(1)(i) of this section, evaluated using the base fuel's 
properties
n2(b) = Higher emitter NOX equation as defined in 
paragraph (d)(1)(ii) of this section, evaluated using the base fuel's 
properties

    (i) Consolidated equation for normal emitters.


[[Page 670]]


n1 = (0.0018571 x OXY) + (0.0006921 x SUL) + (0.0090744 x 
    RVP) + (0.0009310 x E200)+ (0.0008460 x E300)+ (0.0083632 x ARO) + 
    (-0.002774 x OLE) + (-6.63x10-7 x SUL\2\) + (-0.000119 x 
    ARO\2\) + (0.0003665 x OLE\2\)

    (ii) Equation for higher emitters.

n2 = (-0.00913 x OXY) + (0.000252 x SUL) + (-0.01397 x RVP) + 
    (0.000931 x E200) + (-0.00401 x E300) + (0.007097 x ARO) + (-0.00276 
    x OLE) + (0.0003665 x OLE\2\) + (-7.995x10-5 x ARO\2\)

    (iii) Flat line extrapolations. (A) During Phase I, fuels with 
olefin levels less than 3.77 volume percent shall be evaluated with the 
OLE fuel parameter set equal to 3.77 volume percent when calculating 
NOX performance using the equations described in paragraphs 
(d)(1)(i) and (ii) of this section. Fuels with aromatics levels greater 
than 36.2 volume percent shall be evaluated with the ARO fuel parameter 
set equal to 36.2 volume percent when calculating NOX 
performance using the equations described in paragraphs (d)(1)(i) and 
(ii) of this section.
    (B) During Phase II, fuels with olefin levels less than 3.77 volume 
percent shall be evaluated with the OLE fuel parameter set equal to 3.77 
volume percent when calculating NOX performance using the 
equations described in paragraphs (d)(1)(i) and (ii) of this section. 
Fuels with aromatics levels greater than 36.8 volume percent shall be 
evaluated with the ARO fuel parameter set equal to 36.8 volume percent 
when calculating NOX performance using the equations 
described in paragraphs (d)(1)(i) and (ii) of this section.
    (iv) Linear extrapolations. (A) The equations in paragraphs 
(d)(1)(i) and (ii) of this section shall be used within the allowable 
range of SUL, OLE, and ARO for the appropriate Phase, as defined in the 
following table 7:

 Table 7--Allowable Ranges of SUL, OLE, and ARO for the NOX Equations in
              Paragraphs/(d)(1)(i) and (ii) of This Section
------------------------------------------------------------------------
                                         Phase I            Phase II
                                   -------------------------------------
          Fuel parameter                        High               High
                                     Low end    end     Low end    end
------------------------------------------------------------------------
SUL...............................     10.0     450.0     10.0     450.0
OLE...............................      3.77     19.0      3.77     19.0
ARO...............................     18.0      36.2     18.0      36.8
------------------------------------------------------------------------

    (B) For fuels with SUL, OLE, and/or ARO levels outside the ranges 
defined in Table 7 of paragraph (d)(1)(iv)(A) of this section, 
YNOx(t) shall be defined as:

(1) For Phase I:

YNOx(t) = 100% x 0.82 x [exp(n1(et))/
    exp(n1(b)) - 1]
+ 100% x 0.18 x [exp(n2(et))/exp(n2(b)) - 1]
+ {100% x 0.82 x [exp(n1(et))/exp(n1(b))] x [{[(-
    0.00000133 x SULet) + 0.000692] x [Delta]SUL{time} 
+ {[(-0.000238 x AROet) + 0.0083632] x [Delta]ARO{time} 
+ {[(0.000733 x OLEet) - 0.002774] x 
    [Delta]OLE{time} ]{time} 
+ {100% x 0.18 x [exp(n2(et))/exp(n2(b))]
x [{0.000252 x [Delta]SUL{time}  +
+ {[(-0.0001599 x AROet) + 0.007097] x [Delta]ARO{time} 
+ {[(0.000732 x OLEet) - 0.00276] x [Delta]OLE{time} ]{time} 

    (2) For Phase II:

YNOX(t) = 100% x 0.738 x [exp(n1(et))/
    exp(n1(b)) - 1]
+ 100% x 0.262 x [exp(n2(et)/exp(n2(b)) - 1]
+ [100% x 0.738 x [exp(n1(et))/exp(n1(b))]
x [{[(-0.00000133 x SULet) + 0.000692] x [Delta]SUL{time} 
+ {[(-0.000238 x AROet) + 0.0083632] x [Delta]ARO{time} 
+ {[(0.000733 x OLEet) - 0.002774] x 
    [Delta]OLE{time} ]{time} 
+ {100% x 0.262 x [exp(n2(et))/exp(n2(b))]
x [{0.000252 x [Delta]SUL{time}  +
x [{(-0.0001599 x AROet) + 0.007097] x [Delta]ARO{time} 
+ {[(0.000732 x OLEet) - 0.00276] x [Delta]OLE{time} ]{time} 

Where:

n1, n2 = The equations defined in paragraphs 
    (d)(1) (i) and (ii) of this section.
et = Collection of fuel parameters for the ``edge target'' fuel. These 
    parameters are defined in paragraphs (d)(1)(iv) (C) and (D) of this 
    section.
n1(et) = The function n1 evaluated with ``edge 
    target'' fuel parameters, which are defined in paragraph 
    (d)(1)(iv)(C) of this section.
n2(et) = The function n2 evaluated with ``edge 
    target'' fuel parameters, which are defined in paragraph 
    (d)(1)(iv)(C) of this section.

[[Page 671]]

n1(b) = The function n1 evaluated with the 
    appropriate baseline fuel parameters defined in paragraph (b)(2) of 
    this section.
n2(b) = The function n2 evaluated with the 
    appropriate baseline fuel parameters defined in paragraph (b)(2) of 
    this section.
SULet = The value of SUL for the ``edge target'' fuel, as 
    defined in paragraph (d)(1)(iv)(C) of this section.
AROet = The value of ARO for the ``edge target'' fuel, as 
    defined in paragraph (d)(1)(iv)(C) of this section.
OLEet = The value of OLE for the ``edge target'' fuel, as 
    defined in paragraph (d)(1)(iv)(C) of this section.

    (C) For both Phase I and Phase II, the ``edge target'' fuel is 
identical to the target fuel for all fuel parameters, with the following 
exceptions:
    (1) If the sulfur level of the target fuel is less than 10 parts per 
million, then the value of SUL for the ``edge target'' fuel shall be set 
equal to 10 parts per million.
    (2) If the sulfur level of the target fuel is greater than 450 parts 
per million, then the value of SUL for the ``edge target'' fuel shall be 
set equal to 450 parts per million.
    (3) If the aromatics level of the target fuel is less than 18 volume 
percent, then the value of ARO for the ``edge target'' fuel shall be set 
equal to 18 volume percent.
    (4) If the olefins level of the target fuel is greater than 19 
volume percent, then the value of OLE for the ``edge target'' fuel shall 
be set equal to 19 volume percent.
    (5) If the E300 level of the target fuel is greater than 95 volume 
percent, then the E300 value of the target fuel shall be set equal to 95 
volume percent for the purposes of calculating NOX emissions 
with the equations given in paragraph (d)(1)(iv)(B) of this section.
    (6) If the sulfur level of the target fuel is less than 10 parts per 
million, then [Delta]SUL shall be set equal to (SUL-10 parts per 
million).
    (7) If the sulfur level of the target fuel is greater than 450 parts 
per million, then [Delta]SUL shall be set equal to (SUL-450 parts per 
million).
    (8) If the sulfur level of the target fuel is neither less than 10 
parts per million nor greater than 450 parts per million, [Delta]SUL 
shall be set equal to zero.
    (9) If the aromatics level of the target fuel is less than 18 volume 
percent and greater than 10 volume percent, then [Delta]ARO shall be set 
equal to (ARO-18 volume percent). If the aromatics level of the target 
fuel is less than 10 volume percent, then [Delta]ARO shall be set equal 
to -8 volume percent.
    (10) If the aromatics level of the target fuel is greater than or 
equal to 18 volume percent, then [Delta]ARO shall be set equal to zero.
    (11) If the olefins level of the target fuel is greater than 19 
volume percent, then [Delta]OLE shall be set equal to (OLE-19 volume 
percent).
    (12) If the olefins level of the target fuel is less than or equal 
to 19 volume percent, then [Delta]OLE shall be set equal to zero.
    (2) The winter NOX emissions performance of gasolines 
shall be given by the equations presented in paragraph (d)(1) of this 
section with the RVP value set to 8.7 psi.
    (3) The NOX emissions performance of the target fuel in 
percentage terms from baseline levels shall be given by the following 
equations:

For Phase I:

Summer NOX% = [100% x (NOX-0.660 g/mi)]/(0.660 g/
    mi)
Winter NOX% = [100% x (NOX-0.750 g/mi)]/(0.750 g/
    mi)


For Phase II:

Summer NOX% = [100% x (NOX-1.340 g/mi)]/(1.340 g/
    mi)
Winter NOX% = [100% x (NOX-1.540 g/mi)]/(1.540 g/
    mi)
Summer NOX% = Percentage change in NOX emissions 
    from summer baseline levels
Winter NOX% = Percentage change in NOX emissions 
    from winter baseline levels

    (e) Toxics performance--(1) Summer toxics performance. (i) Summer 
toxic emissions performance of gasolines in VOC Control Regions 1 and 2 
shall be given by the following equations:

TOXICS1 = EXHBZ + FORM + ACET + BUTA + POM + NEBZ1
TOXICS2 = EXHBZ + FORM + ACET + BUTA + POM + NEBZ2


[[Page 672]]


where

TOXICS1 = Summer toxics performance in VOC Control Region 1 in terms of 
milligrams per mile.
TOXICS2 = Summer toxics performance in VOC Control Region 2 in terms of 
milligrams per mile.
EXHBZ = Exhaust emissions of benzene in terms of milligrams per mile, as 
determined in paragraph (e)(4) of this section.
FORM = Emissions of formaldehyde in terms of milligrams per mile, as 
determined in paragraph (e)(5) of this section.
ACET = Emissions of acetaldehyde in terms of milligrams per mile, as 
determined in paragraph (e)(6) of this section.
BUTA = Emissions of 1,3-butadiene in terms of milligrams per mile, as 
determined in paragraph (e)(7) of this section.
POM = Polycyclic organic matter emissions in terms of milligrams per 
mile, as determined in paragraph (e)(8) of this section.
NEBZ1 = Nonexhaust emissions of benzene in VOC Control Region 1 in 
milligrams per mile, as determined in paragraph (e)(9) of this section.
NEBZ2 = Nonexhaust emissions of benzene in VOC Control Region 2 in 
milligrams per mile, as determined in paragraph (e)(10) of this section.

    (ii) The percentage change in summer toxics performance in VOC 
Control Regions 1 and 2 shall be given by the following equations:

For Phase I:

TOXICS1% = [100% x (TOXICS1 -48.61 mg/mi)]/(48.61 mg/mi)
TOXICS2% = [100% x (TOXICS2 - 47.58 mg/mi)] / (47.58 mg/mi)


For Phase II:

TOXICS1% = [100% x (TOXICS1 - 86.34 mg/mi)] / (86.34 mg/mi)
TOXICS2% = [100% x (TOXICS2 - 85.61 mg/mi)]/(85.61 mg/mi)

where

TOXICS1% = Percentage change in summer toxics emissions in VOC Control 
Region 1 from baseline levels.
TOXICS2% = Percentage change in summer toxics emissions in VOC Control 
Region 2 from baseline levels.

    (2) Winter toxics performance. (i) Winter toxic emissions 
performance of gasolines in VOC Control Regions 1 and 2 shall be given 
by the following equation, evaluated with the RVP set at 8.7 psi:

TOXICW = [EXHBZ + FORM + ACET + BUTA + POM]

where

TOXICW = Winter toxics performance in VOC Control Regions 1 and 2 in 
terms of milligrams per mile.
EXHBZ = Exhaust emissions of benzene in terms of milligrams per mile, as 
determined in paragraph (e)(4) of this section.
FORM = Emissions of formaldehyde in terms of milligrams per mile, as 
determined in paragraph (e)(5) of this section.
ACET = Emissions of acetaldehyde in terms of milligrams per mile, as 
determined in paragraph (e)(6) of this section.
BUTA = Emissions of 1,3-butadiene in terms of milligrams per mile, as 
determined in paragraph (e)(7) of this section.
POM = Polycyclic organic matter emissions in terms of milligrams per 
mile, as determined in paragraph (e)(8) of this section.

    (ii) The percentage change in winter toxics performance in VOC 
Control Regions 1 and 2 shall be given by the following equation:

For Phase I:

TOXICW% = [100%x(TOXICW-58.36 mg/mi)] / (58.36 mg/mi)


For Phase II:

TOXICW% = [100%x(TOXICW-120.55 mg/mi)] / (120.55 mg/mi)

where

TOXICW% = Percentage change in winter toxics emissions in VOC Control 
Regions 1 and 2 from baseline levels.

    (3) The year-round toxics performance in VOC Control Regions 1 and 2 
shall be derived from volume-weighted performances of individual batches 
of fuel as described in Sec. 80.67(g).
    (4) Exhaust benzene emissions shall be given by the following 
equation, subject to paragragh (e)(4)(iii) of this section:

EXHBZ = BENZ(b) + (BENZ(b) x YBEN(t)/100)
YBEN(t) = [lsqbb](w1 x Nb) + 
    (w2 x Hb) - 1[rsqbb] x 100

where

EXHBZ = Exhaust benzene emissions in milligrams/mile
YBEN(t) = Benzene performance of target fuel in terms of 
percentage change from baseline.
BENZ(b) = Baseline benzene emissions as defined in paragraph (b)(2) of 
this section for the appropriate phase and season.
Nb = exp b1(t)/exp b1(b)
Hb = exp b2(t)/exp b2(b)

[[Page 673]]

w1 = Weighting factor for normal emitters as defined in 
paragraph (b)(1) of this section for the appropriate Phase.
w2 = Weighting factor for higher emitters as defined in 
paragraph (b)(1) of this section for the appropriate Phase.
b1(t) = Normal emitter benzene equation, as defined in 
paragraph (e)(4)(i) of this section, evaluated using the target fuel's 
properties subject to paragraph (e)(4)(iii) of this section.
b2(t) = Higher emitter benzene equation as defined in 
paragraph (e)(4)(ii) of this section, evaluated using the target fuel's 
properties subject to paragraph (e)(4)(iii) of this section.
b1(b) = Normal emitter benzene equation as defined in 
paragraph (e)(4)(i) of this section, evaluated for the base fuel's 
properties.
b2(b) = Higher emitter benzene equation, as defined in 
paragraph (e)(4)(ii) of this section, evaluated for the base fuel's 
properties.

    (i) Consolidated equation for normal emitters.

b1 = (0.0006197 x SUL) + (-0.003376 x E200) + (0.0265500 x 
    ARO) + (0.2223900 x BEN)

    (ii) Equation for higher emitters.

b2 = (-0.096047 x OXY) + (0.0003370 x SUL) + (0.0112510 x 
    E300) + (0.0118820 x ARO) + (0.2223180 x BEN)

    (iii) If the aromatics value of the target fuel is less than 10 
volume percent, then an aromatics value of 10 volume percent shall be 
used when evaluating the equations given in paragraphs (e)(4) (i) and 
(ii) of this section. If the E300 value of the target fuel is greater 
than 95 volume percent, then an E300 value of 95 volume percent shall be 
used when evaluating the equations in paragraphs (e)(4)(i) and (ii) of 
this section.
    (5) Formaldehyde mass emissions shall be given by the following 
equation, subject to paragraphs (e)(5) (iii) and (iv) of this section:

FORM = FORM(b) + (FORM(b) x YFORM(t) / 100)
YFORM(t) = [(w1 x Nf) + (w2 
    x Hf) - 1] x 100

where

FORM = Exhaust formaldehyde emissions in terms of milligrams/mile.
YFORM(t) = Formaldehyde performance of target fuel in terms 
of percentage change from baseline.
FORM(b) = Baseline formaldehyde emissions as defined in paragraph (b)(2) 
of this section for the appropriate Phase and season.
Nf = exp f1(t)/exp f1(b)
Hf = exp f2(t)/exp f2(b)
w1 = Weighting factor for normal emitters as defined in 
paragraph (b)(1) of this section for the appropriate Phase.
w2 = Weighting factor for higher emitters as defined in 
paragraph (b)(1) of this section for the appropriate Phase.
f1(t) = Normal emitter formaldehyde equation as defined in 
paragraph (e)(5)(i) of this section, evaluated using the target fuel's 
properties subject to paragraphs (e)(5) (iii) and (iv) of this section.
f2(t) = Higher emitter formaldehyde equation as defined in 
paragraph (e)(5)(ii) of this section, evaluated using the target fuel's 
properties subject to paragraphs (e)(5) (iii) and (iv) of this section.
f1(b) = Normal emitter formaldehyde equation as defined in 
paragraph (e)(5)(i) of this section, evaluated for the base fuel's 
properties.
f2(b) = Higher emitter formaldehyde equation as defined in 
paragraph (e)(5)(ii) of this section, evaluated for the base fuel's 
properties.

    (i) Consolidated equation for normal emitters.

f1 = (-0.010226 x E300) + (-0.007166 x ARO) + (0.0462131 x 
    MTB)

    (ii) Equation for higher emitters.

f2 = (-0.010226 x E300) + (-0.007166 x ARO) + (-0.031352 x 
    OLE) + (0.0462131 x MTB)

    (iii) If the aromatics value of the target fuel is less than 10 
volume percent, then an aromatics value of 10 volume percent shall be 
used when evaluating the equations given in paragraphs (e)(5) (i) and 
(ii) of this section. If the E300 value of the target fuel is greater 
than 95 volume percent, then an E300 value of 95 volume percent shall be 
used when evaluating the equations given in paragraphs (e)(5) (i) and 
(ii) of this section.
    (iv) When calculating formaldehyde emissions and emissions 
performance, oxygen in the form of alcohols which are more complex or 
have higher molecular weights than ethanol shall be evaluated as if it 
were in the form of ethanol. Oxygen in the form of methyl ethers other 
than TAME and MTBE shall be evaluated as if it were in the form of MTBE. 
Oxygen in the form of ethyl ethers other than ETBE shall be evaluated as 
if it were in the form of

[[Page 674]]

ETBE. Oxygen in the form of non-methyl, non-ethyl ethers shall be 
evaluated as if it were in the form of ETBE. Oxygen in the form of 
methanol or non-alcohol, non-ether oxygenates shall not be evaluated 
with the Complex Model, but instead must be evaluated through vehicle 
testing per Sec. 80.48.
    (6) Acetaldehyde mass emissions shall be given by the following 
equation, subject to paragraphs (e)(6) (iii) and (iv) of this section:

ACET = ACET(b) + (ACET(b)xYACET(t)/100)
YACET(t) = [(w1xNa) + 
    (w2xHa)-1]x100

where

ACET = Exhaust acetaldehyde emissions in terms of milligrams/mile
YACET(t) = Acetaldehyde performance of target fuel in terms 
of percentage change from baseline
ACET(b) = Baseline acetaldehyde emissions as defined in paragraph (b)(2) 
of this section for the appropriate phase and season
Na = exp a1(t)/exp a1(b)
Ha = exp a2(t)/exp a2(b)
w1 = Weighting factor for normal emitters as defined in 
paragraph (b)(1) of this section for the appropriate phase
w2 = Weighting factor for higher emitters as defined in 
paragraph (b)(1) of this section for the appropriate phase
a1(t) = Normal emitter acetaldehyde equation as defined in 
paragraph (e)(6)(i) of this section, evaluated using the target fuel's 
properties, subject to paragraphs (e)(6) (iii) and (iv) of this section
a2(t) = Higher emitter acetaldehyde equation as defined in 
paragraph (e)(6)(ii) of this section, evaluated using the target fuel's 
properties, subject to paragraphs (e)(6) (iii) and (iv) of this section
a1(b) = Normal emitter acetaldehyde equation as defined in 
paragraph (e)(6)(i) of this section, evaluated for the base fuel's 
properties
f2(b) = Higher emitter acetaldehyde equation as defined in 
paragraph (e)(6)(ii) of this section, evaluated for the base fuel's 
properties

    (i) Consolidated equation for normal emitters.

a1 = (0.0002631xSUL)+ (0.0397860xRVP) + (-0.012172xE300) + (-
    0.005525xARO) + (-0.009594xMTB) + (0.3165800xETB) + (0.2492500xETH)

    (ii) Equation for higher emitters.

a2 = (0.0002627xSUL)+ (-0.012157xE300) + (-0.005548xARO) + (-
    0.055980xMTB) + (0.3164665xETB) + (0.2493259xETH)

    (iii) If the aromatics value of the target fuel is less than 10 
volume percent, then an aromatics value of 10 volume percent shall be 
used when evaluating the equations given in paragraphs (e)(6) (i) and 
(ii) of this section. If the E300 value of the target fuel is greater 
than 95 volume percent, then an E300 value of 95 volume percent shall be 
used when evaluating the equations given in paragraphs (e)(6) (i) and 
(ii) of this section.
    (iv) When calculating acetaldehyde emissions and emissions 
performance, oxygen in the form of alcohols which are more complex or 
have higher molecular weights than ethanol shall be evaluated as if it 
were in the form of ethanol. Oxygen in the form of methyl ethers other 
than TAME and MTBE shall be evaluated as if it were in the form of MTBE. 
Oxygen in the form of ethyl ethers other than ETBE shall be evaluated as 
if it were in the form of ETBE. Oxygen in the form of non-methyl, non-
ethyl ethers shall be evaluated as if it were in the form of ETBE. 
Oxygen in the form of methanol or non-alcohol, non-ether oxygenates 
shall not be evaluated with the Complex Model, but instead must be 
evaluated through vehicle testing per Sec. 80.48.
    (7) 1,3-butadiene mass emissions shall be given by the following 
equations, subject to paragraph (e)(7)(iii) of this section:

BUTA = BUTA(b) + (BUTA(b)xYBUTA(t)/100)
YBUTA(t) = [(w1xNd) + 
    (w2xHd)-1]x100

where

BUTA = Exhaust 1,3-butadiene emissions in terms of milligrams/mile
YBUTA(t) = 1,3-butadiene performance of target fuel in terms 
of percentage change from baseline
BUTA(b) = Baseline 1,3-butadiene emissions as defined in paragraph 
(b)(2) of this section for the appropriate phase and season
Nd = exp d1(t)/exp d1(b)
Hd = exp d2(t)/exp d2(b)
w1 = eighting factor for normal emitters as defined in 
paragraph (b)(1) of this section for the appropriate phase
w2 = Weighting factor for higher emitters as defined in 
paragraph (b)(1) of this section for the appropriate Phase.
d1(t) = Normal emitter 1,3-butadiene equation as defined in 
paragraph (e)(7)(i) of this section, evaluated using the target fuel's 
properties, subject to paragraph (e)(7)(iii) of this section.

[[Page 675]]

d2(t) = Higher emitter 1,3-butadiene equation as defined in 
paragraph (e)(7)(ii) of this section, evaluated using the target fuel's 
properties, subject to paragraph (e)(7)(iii) of this section.
d1(b) = Normal emitter 1,3-butadiene equation as defined in 
paragraph (e)(7)(i) of this section, evaluated for the base fuel's 
properties.
d2(b) = Higher emitter 1,3-butadiene equation as defined in 
paragraph (e)(7)(ii) of this section, evaluated for the base fuel's 
properties.

    (i) Consolidated equation for normal emitters.

d1 = (0.0001552xSUL)+ (-0.007253xE200) + (-0.014866xE300) + 
    (-0.004005xARO) + (0.0282350xOLE)

    (ii) Equation for higher emitters.

d2 = (-0.060771xOXY)+ (-0.007311xE200) + (-0.008058xE300) + 
    (-0.004005xARO) + (0.0436960xOLE)

    (iii) If the aromatics value of the target fuel is less than 10 
volume percent, then an aromatics value of 10 volume percent shall be 
used when evaluating the equations given in paragraphs (e)(7) (i) and 
(ii) of this section. If the E300 value of the target fuel is greater 
than 95 volume percent, then an E300 value of 95 volume percent shall be 
used when evaluating the equations given in paragraphs (e)(7) (i) and 
(ii) of this section.
    (8) Polycyclic organic matter mass emissions shall be given by the 
following equation:

POM=0.003355xVOCE
POM = Polycyclic organic matter emissions in terms of milligrams per 
    mile
VOCE = Non-methane, non-ethane exhaust emissions of volatile organic 
    compounds in grams per mile.

    (9) Nonexhaust benzene emissions in VOC Control Region 1 shall be 
given by the following equations for both Phase I and Phase II:

NEBZ1 = DIBZ1 + HSBZ1 + RLBZ1 + RFBZ1
HSBZ1 = 10 x BEN x VOCHS1 x [(-0.0342 x MTB) + (-0.080274 x RVP) + 
    1.4448]
DIBZ1 = 10 x BEN x VOCD11 x [(-0.0290 x MTB) + (-0.080274 x RVP) + 
    1.3758]
RLBZ1 = 10 x BEN x VOCRL1 x [(-0.0342 x MTB) + (-0.080274 x RVP) + 
    1.4448]
RFBZ1 = 10 x BEN x VOCRF1 x [(-0.0296 x MTB) + (-0.081507 x RVP) + 
    1.3972

where

NEBZ1 = Nonexhaust emissions of volatile organic compounds in VOC 
Control Region 1 in milligrams per mile.
DIBZ1 = Diurnal emissions of volatile organic compounds in VOC Control 
Region 1 in milligrams per mile.
HSBZ1 = Hot soak emissions of volatile organic compounds in VOC Control 
Region 1 in milligrams per mile.
RLBZ1 = Running loss emissions of volatile organic compounds in VOC 
Control Region 1 in milligrams per mile.
RFBZ1 = Refueling emissions of volatile organic compounds in VOC Control 
Region 1 in grams per mile.
VOCDI1 = Diurnal emissions of volatile organic compounds in VOC Control 
Region 1 in milligrams per mile, as determined in paragraph (c)(3) of 
this section.
VOCHS1 = Hot soak emissions of volatile organic compounds in VOC Control 
Region 1 in milligrams per mile, as determined in paragraph (c)(3) of 
this section.
VOCRL1 = Running loss emissions of volatile organic compounds in VOC 
Control Region 1 in milligrams per mile, as determined in paragraph 
(c)(3) of this section.
VOCRF1 = Refueling emissions of volatile organic compounds in VOC 
Control Region 1 in milligrams per mile, as determined in paragraph 
(c)(3) of this section.

    (10) Nonexhaust benzene emissions in VOC Control Region 2 shall be 
given by the following equations for both Phase I and Phase II:

NEBZ2 = DIBZ2 + HSBZ2 + RLBZ2 + RFBZ2
HSBZ2 = 10 x BEN x VOCHS2 x [(-0.0342 x MTB) + (-0.080274 x RVP) + 
    1.4448]
DIBZ2 = 10 x BEN x VOCD12 x [(-0.0290 x MTB) + (-0.080274 x RVP) + 
    1.3758]
RLBZ2 = 10 x BEN x VOCRL2 x [(-0.0342 x MTB) + (-0.080274 x RVP) + 
    1.4448]
RFBZ2 = 10 x BEN x VOCRF2 x [(-0.0296 x MTB) + (-0.081507 x RVP) + 
    1.3972

where

NEBZ2 = Nonexhaust emissions of volatile organic compounds in VOC 
Control Region 2 in milligrams per mile.
DIBZ2 = Diurnal emissions of volatile organic compounds in VOC Control 
Region 2 in milligrams per mile.
HSBZ2 = Hot soak emissions of volatile organic compounds in VOC Control 
Region 2 in milligrams per mile.

[[Page 676]]

RLBZ2 = Running loss emissions of volatile organic compounds in VOC 
Control Region 2 in milligrams per mile.
RFBZ2 = Refueling emissions of volatile organic compounds in VOC Control 
Region 2 in grams per mile.
VOCDI2 = Diurnal emissions of volatile organic compounds in VOC Control 
Region 2 in milligrams per mile, as determined in paragraph (c)(4) of 
this section.
VOCHS2 = Hot soak emissions of volatile organic compounds in VOC Control 
Region 2 in milligrams per mile, as determined in paragraph (c)(4) of 
this section.
VOCRL2 = Running loss emissions of volatile organic compounds in VOC 
Control Region 2 in milligrams per mile, as determined in paragraph 
(c)(4) of this section.
VOCRF2 = Refueling emissions of volatile organic compounds in VOC 
Control Region 2 in milligrams per mile, as determined in paragraph 
(c)(4) of this section.

    (f) Limits of the model. (1) The equations described in paragraphs 
(c), (d), and (e) of this section shall be valid only for fuels with 
fuel properties that fall in the following ranges for reformulated 
gasolines and conventional gasolines:
    (i) For reformulated gasolines:

------------------------------------------------------------------------
            Fuel property                      Acceptable range
------------------------------------------------------------------------
Oxygen..............................  0.0-4.0 weight percent.
Sulfur..............................  0.0-500.0 parts per million by
                                       weight.
RVP.................................  6.4-10.0 pounds per square inch.
E200................................  30.0-70.0 percent evaporated.
E300................................  70.0-100.0 percent evaporated.
Aromatics...........................  0.0-50.0 volume percent.
Olefins.............................  0.0-25.0 volume percent.
Benzene.............................  0.0-2.0 volume percent.
------------------------------------------------------------------------

    (ii) For conventional gasoline:

------------------------------------------------------------------------
            Fuel property                      Acceptable range
------------------------------------------------------------------------
Oxygen..............................  0.00-4.0 weight percent.
Sulfur..............................  0.0-1000.0 parts per million by
                                       weight.
RVP.................................  6.4-11.0 pounds per square inch.
E200................................  30.0-70.0 evaporated percent.
E300................................  70.0-100.0 evaporated percent.
Aromatics...........................  0.0-55.0 volume percent.
Olefins.............................  0.0-30.0 volume percent.
Benzene.............................  0.0-4.9 volume percent.
------------------------------------------------------------------------

    (2) Fuels with one or more properties that do not fall within the 
ranges described in above shall not be certified or evaluated for their 
emissions performance using the complex emissions model described in 
paragraphs (c), (d), and (e) of this section.

[59 FR 7813, Feb. 16, 1994, as amended at 59 FR 36959, July 20, 1994; 62 
FR 68206, Dec. 31, 1997; 71 FR 74566, Dec. 15, 2005]



Sec. 80.46  Measurement of reformulated gasoline fuel parameters.

    (a) Sulfur. Sulfur content of gasoline and butane must be determined 
by use of the following methods:
    (1) The sulfur content of gasoline must be determined by use of 
American Society for Testing and Materials (ASTM) standard method D 
2622-03, entitled ``Standard Test Method for Sulfur in Petroleum 
Products by Wavelength Dispersive X-Ray Fluorescence Spectrometry'' or 
by one of the alternative method specified in paragraph (a)(3) of this 
section.
    (2) Beginning January 1, 2004, the sulfur content of butane must be 
determined by the use of ASTM standard test method D 6667-01, entitled, 
``Standard Test Method for Determination of Total Volatile Sulfur in 
Gaseous Hydrocarbons and Liquefied Petroleum Gases by Ultraviolet 
Fluorescence'' or by the alternative method specified in paragraph 
(a)(4) of this section.
    (3) Any refiner or importer may use any of the following methods for 
determining the sulfur content of gasoline; provided the refiner or 
importer test result is correlated with the method specified in 
paragraph (a)(1) of this section:
    (i) ASTM standard method D 5453-03a, entitled, ``Standard Test 
Method for Determination of Total Sulfur in Light Hyrdocarbons, Motor 
Fuels and Motor Oils by Ultraviolet Fluorescence,'' or
    (ii) ASTM standard method D 6920-03, entitled, ``Standard Test 
Method for Total Sulfur in Naphthas, Distillates, Reformulated 
Gasolines, Diesels, Biodiesels, and Motor Fuels by Oxidative Combustion 
and Electrochemical Detection,'' or
    (iii) ASTM standard method D 3120-03a, entitled, ``Standard Test 
Method for Trace Quantities of Sulfur in Light Liquid Petroleum 
Hydrocarbons by Oxidative Microcoulometry.''
    (iv) ASTM standard method D 7039-04, entitled, ``Standard Test 
Method for Sulfur in Gasoline and Diesel Fuel by Monochromatic 
Wavelength Dispersive X-ray Fluorescence Spectrometry.''
    (4) Beginning January 1, 2004, any refiner or importer may determine 
the sulfur content of butane using any of

[[Page 677]]

the following methods; provided the refiner or importer test result is 
correlated with the method specified in paragraph (a)(2) of this 
section:
    (i) ASTM standard method D 4468-85 (Reapproved 2000), ``Standard 
Test Method for Total Sulfur in Gaseous Fuels by Hydrogenolysis and 
Rateometric Colorimetry,'' or
    (ii) ASTM standard method D 3246-96, entitled, ``Standard Test 
Method for Sulfur in Petroleum Gas by Oxidative Microcoulemetry.''
    (b) Olefins. Olefin content shall be determined using ASTM standard 
method D 1319B03, entitled ``Standard Test Method for Hydrocarbon Types 
in Liquid Petroleum Products by Fluorescent Indicator Adsorption.''
    (c) Reid vapor pressure (RVP). Reid vapor pressure (RVP) shall be 
determined using ASTM standard method D 5191-01, entitled ``Standard 
Test Method for Vapor Pressure of Petroleum Products (Mini Method),'' 
except that the following correlation equation must be used:

RVP psi = (0.956 * X) -0.347
RVP kPa = (0.956 * X) -2.39

Where:

X = total measured vapor pressure in psi or kPa.

    (d) Distillation. Distillation parameters shall be determined using 
ASTM standard method D 86-01, entitled'' Standard Test Method for 
Distillation of Petroleum Products at Atmospheric Pressure.''
    (e) Benzene. (1) Benzene content shall be determined using ASTM 
standard method D-3606-99, entitled ``Standard Test Method for 
Determination of Benzene and Toluene in Finished Motor and Aviation 
Gasoline by Gas Chromatography''; except that
    (2) Instrument parameters shall be adjusted to ensure complete 
resolution of the benzene, ethanol and methanol peaks because ethanol 
and methanol may cause interference with ASTM standard method D-3606-99 
when present.
    (f)(1) Aromatic content shall be determined using ASTM D 5769-98, 
entitled, ``Standard Test Method for Determination of Benzene, Toluene, 
and Total Aromatics in Finished Gasolines by Gas Chromatography/Mass 
Spectrometry'', except that the sample chilling requirements in section 
8 of this standard method are optional.
    (2) [Reserved]
    (3)(i) Any refiner or importer may determine aromatics content using 
ASTM standard method D 1319-03, entitled ``Standard Test Method for 
Hydrocarbon Types in Liquid Petroleum Products by Flourescent Indicator 
Adsorption,'' for purposes of meeting any testing requirement involving 
aromatics content; provided that
    (ii) The refiner or importer test result is correlated with the 
method specified in paragraph (f)(1) of this section.
    (g) Oxygen and oxygenate content analysis. (1) Oxygen and oxygenate 
content shall be determined using ASTM standard method D 5599-00, 
entitled ``Standard Test Method for Determination of Oxygenates in 
Gasoline by Gas Chromatography and Oxygen Selective Flame Ionization 
Detection.''
    (2)(i) When oxygenates present are limited to MTBE, ETBE, TAME, 
DIPE, tertiary-amyl alcohol and C1 to C4 alcohols, 
any refiner, importer, or oxygenate blender may determine oxygen and 
oxygen content using ASTM standard method D 4815-03 entitled, ``Standard 
Test Method for Determination of MTBE, ETBE, TAME, DIPE, tertiary-Amyl 
Alcohol and C1 to C4 Alcohols in Gasoline by Gas 
Chromatography,'' for purposes of meeting any testing requirement; 
provided that
    (ii) The refiner or importer test result is correlated with the 
method specified in paragraph (g)(1) of this section.
    (h) Incorporations by reference. ASTM standard methods D 3606-99, 
entitled ``Standard Test Method for Determination of Benzene and Toluene 
in Finished Motor and Aviation Gasoline by Gas Chromatography;'' D 1319-
03, entitled ``Standard Test Method for Hydrocarbon Types in Liquid 
Petroleum Products by Fluorescent Indicator Adsorption;'' D 4815-03, 
entitled ``Standard Test Method for Determination of MTBE, ETBE, TAME, 
DIPE, tertiary-Amyl Alcohol and C1 to C4 Alcohols 
in Gasoline by Gas Chromatography;'' D 2622-03, entitled ``Standard Test 
Method for Sulfur in Petroleum Products by

[[Page 678]]

Wavelength Dispersive X-Ray Fluorescence Spectrometry;'' D 3246-96, 
entitled ``Standard Test Method for Sulfur in Petroleum Gas by Oxidative 
Microcoulometry;'' D 5191-01, entitled, ``Standard Test Method for Vapor 
Pressure of Petroleum Products (Mini Method);'' D 5599-00, entitled, 
``Standard Test Method for Determination of Oxygenates in Gasoline by 
Gas Chromatography and Oxygen Selective Flame Ionization Detection;'' D 
5769-98, entitled, ``Standard Test Method for Determination of Benzene, 
Toluene, and Total Aromatics in Finished Gasolines by Gas 
Chromatography/Mass Spectrometry,'' and D 86-01, entitled, ``Standard 
Test Method for Distillation of Petroleum Products at Atmospheric 
Pressure;'' D 5453-03a, entitled, ``Standard Test Method for 
Determination of Total Sulfur in Light Hydrocarbons, Motor Fuels and 
Oils by Ultraviolet Fluorescence,'' D 6920-03, entitled, ``Standard Test 
Method for Total Sulfur in Naphthas, Distillates, Reformulated 
Gasolines, Diesels, Biodiesels, and Motor Fuels by Oxidative Combustion 
and Electrochemical Detection,'' D 3120-03a, entitled, ``Standard Test 
Method for Trace Quantities of Sulfur in Light Petroleum Hydrocarbons by 
Oxidative Microcoulometry,'' D 7039-04, entitled, ``Standard Test Method 
for Sulfur in Gasoline and Diesel Fuel by Monochromatic Wavelength 
Dispersive X-ray Fluorescence Spectrometry,'' D 6667-01, entitled, 
``Standard Test Method for Determination of Total Volatile Sulfur in 
Gaseous Hydrocarbons and Liquefied Petroleum Gases by Ultraviolet 
Fluorescence,'' and D 4468-85 (Reapproved 2000), ``Standard Test Method 
for Total Sulfur in Gaseous Fuels by Hydrogenolysis and Rateometric 
Colorimetry'' are incorporated by reference in this section. 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. Copies 
may be obtained from the American Society for Testing and Materials, 100 
Barr Harbor Dr., West Conshohocken, PA 19428-2959. Copies may be 
inspected at the Air Docket, EPA/DC, EPA West, Room B102, 1301 
Constitution Ave., NW., Washington, DC, 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.

[59 FR 7813, Feb. 16, 1994, as amended at 59 FR 36961, July 20, 1994; 61 
FR 58306, Nov. 13, 1996; 63 FR 63793, Nov. 17, 1998; 65 FR 6822, Feb. 
10, 2000; 65 FR 53189, Sept. 1, 2000; 66 FR 17263, Mar. 29, 2001; 67 FR 
8737, Feb. 26, 2002; 67 FR 40181, June 12, 2002; 68 FR 56781, Oct. 2, 
2003; 68 FR 57819, Oct. 7, 2003; 71 FR 16499, Apr. 3, 2006]



Sec. 80.47  [Reserved]



Sec. 80.48  Augmentation of the complex emission model
by vehicle testing.

    (a) The provisions of this section apply only if a fuel claims 
emission reduction benefits from fuel parameters that are not included 
in the complex emission model or complex emission model database, or if 
the values of fuel parameters included in the complex emission model set 
forth in Sec. 80.45 fall outside the range of values for which the 
complex emission model is deemed valid.
    (b) To augment the complex emission model described at Sec. 80.45, 
the following requirements apply:
    (1) The petitioner must obtain prior approval from the Administrator 
for the design of the test program before beginning the vehicle testing 
process. To obtain approval, the petitioner must at minimum provide the 
following information: the fuel parameter to be evaluated for emission 
effects; the number and description of vehicles to be used in the test 
fleet, including model year, model name, vehicle identification number 
(VIN), mileage, emission performance (exhaust THC emission level), 
technology type, and manufacturer; a description of the methods used to 
procure and prepare the vehicles; the properties of the fuels to be used 
in the testing program (as specified at Sec. 80.49); the pollutants and 
emission categories intended to be evaluated; the precautions used to 
ensure that the effects of the parameter in question are independent of 
the effects of other parameters already included in the model; a 
description of the quality assurance procedures to be used during

[[Page 679]]

the test program; the statistical analysis techniques to be used in 
analyzing the test data, and the identity and location of the 
organization performing the testing.
    (2) Exhaust emissions shall be measured per the requirements of this 
section and Sec. 80.49 through Sec. 80.62.
    (3) The nonexhaust emission model (including evaporative, running 
loss, and refueling VOC and toxics emissions) shall not be augmented by 
vehicle testing.
    (4) The Agency reserves the right to observe and monitor any testing 
that is performed pursuant to the requirements of this section.
    (5) The Agency reserves the right to evaluate the quality and 
suitability of data submitted pursuant to the requirements of this 
section and to reject, re-analyze, or otherwise evaluate such data as is 
technically warranted.
    (6) Upon a showing satisfactory to the Administrator, the 
Administrator may approve a petition to waive the requirements of this 
section and Sec. 80.49, Sec. 80.50(a), Sec. 80.60(d)(3), and Sec. 
80.60(d)(4) in order to better optimize the test program to the needs of 
the particular fuel parameter. Any such waiver petition should provide 
information justifying the requested waiver, including an acceptable 
rationale and supporting data. Petitioners must obtain approval from the 
Administrator prior to conducting testing for which the requirements in 
question are waived. The Administrator may waive the noted requirements 
in whole or in part, and may impose appropriate conditions on any such 
waiver.
    (c) In the case of petitions to augment the complex model defined at 
Sec. 80.45 with a new parameter, the effect of the parameter being 
tested shall be determined separately, for each pollutant and for each 
emitter class category. If the parameter is not included in the complex 
model but is represented in whole or in part by one or more parameters 
included in the model, the petitioner shall be required to demonstrate 
the emission effects of the parameter in question independent of the 
effects of the already-included parameters. The petitioner shall also 
have to demonstrate the effects of the already-included parameters 
independent of the effects of the parameter in question. The emission 
performance of each vehicle on the fuels specified at Sec. 80.49, as 
measured through vehicle testing in accordance with Sec. 80.50 through 
Sec. 80.62, shall be analyzed to determine the effects of the fuel 
parameter being tested on emissions according to the following 
procedure:
    (1) The analysis shall fit a regression model to the natural 
logarithm of emissions measured from addition fuels 1, 2, and 3 only (as 
specified at Sec. 80.49(a) and adjusted as per paragraph (c)(1)(iv) of 
this section and Sec. 80.49(d)) that includes the following terms:
    (i) A term for each vehicle that shall reflect the effect of the 
vehicle on emissions independent of fuel compositions. These terms shall 
be of the form DixVi, where Di is the 
coefficient for the term and Vi is a dummy variable which 
shall have the value 1.0 for the ith vehicle and the value 0 for all 
other vehicles.
    (ii) A linear term in the parameter being tested for each emitter 
class, of the form Aix(P1-P1 
(avg))xEi, where Ai is the coefficient for the 
term, P1 is the level of the parameter in question, 
P1 (avg) is the average level of the parameter in question 
for all seven test fuels specified at Sec. 80.49(a)(1), and 
Ei is a dummy variable representing emitter class, as defined 
at Sec. 80.62. For normal emitters, E1 = 1 and E2 
= 0. For higher emitters, E1 = 0 and E2 = 1.
    (iii) For the VOC and NOX models, a squared term in the 
parameter being tested for each emitter class, of the form 
Bix(P1-P1 (avg))\2\xEi, 
where Bi is the coefficient for the term and where 
P1 , P1 (avg), and Ei are as defined in 
paragraph (c)(1)(ii) of this section.
    (iv) To the extent that the properties of fuels 1, 2, and 3 which 
are incorporated in the complex model differ in value among the three 
fuels, the complex model shall be used to adjust the observed emissions 
from test vehicles on those fuels to compensate for those differences 
prior to fitting the regression model.
    (v) The Ai and Bi terms and coefficients 
developed by the regression described in this paragraph (c) shall be 
evaluated against the statistical criteria defined in paragraph (e) of 
this

[[Page 680]]

section. If both terms satisfy these criteria, then both terms shall be 
retained. If the Bi term satisfies these criteria and the 
Ai term does not, then both terms shall be retained. If the 
Bi term does not satisfy these criteria, then the 
Bi term shall be dropped from the regression model and the 
model shall be re-estimated. If, after dropping the Bi term 
and re-estimating the model, the Ai term does not satisfy 
these criteria, then both terms shall be dropped, all test data shall be 
reported to EPA, and the augmentation request shall be denied.
    (2) After completing the steps outlined in paragraph (c)(1) of this 
section, the analysis shall fit a regression model to a combined data 
set that includes vehicle testing results from all seven addition fuels 
specified at Sec. 80.49(a), the vehicle testing results used to develop 
the model specified at Sec. 80.45, and vehicle testing results used to 
support any prior augmentation requests which the Administrator deems 
necessary.
    (i) The analysis shall fit the regression models described in 
paragraphs (c)(2) (ii) through (v) of this section to the natural 
logarithm of measured emissions.
    (ii) All regressions shall include a term for each vehicle that 
shall reflect the effect of the vehicle on emissions independent of fuel 
compositions. These terms shall be of the form 
DixVi, where Di is the coefficient for 
the term and Vi is a dummy variable which shall have the 
value 1.0 for the ith vehicle and the value 0 for all other vehicles. 
Vehicles shall be represented by separate terms for each test program in 
which they were tested. The vehicle terms for the vehicles included in 
the test program undertaken by the petitioner shall be calculated based 
on the results from all seven fuels specified at Sec. 80.49(a). Note 
that the Di estimates for the petitioner's test vehicles in 
this regression are likely to differ from the Di estimates 
discussed in paragraph (c)(1)(i) of this section since they will be 
based on a different set of fuels.
    (iii) All regressions shall include existing complex model terms and 
their coefficients, including those augmentations that the Administrator 
deems necessary. All terms and coefficients shall be expressed in 
centered form. The Administrator shall make available upon request 
existing complex model terms and coefficients in centered form.
    (iv) All regressions shall include the linear and squared terms, and 
their coefficients, estimated in the final regression model described in 
paragraph (c)(1) of this section.
    (v) The VOC and NOX regressions shall include those 
interactive terms with other fuel parameters, of the form 
Ci(1, j)x(P1-P1 (avg))x(Pj-
Pj (avg))xEi, where Ci(1, j) is the 
coefficient for the term, P1 is the level of the parameter 
being added to the model, P1 (avg) is the average level of 
the parameter being added for all seven addition fuels specified at 
Sec. 80.49(a), Pj is the level of the other fuel parameter, 
Pj (avg) is the centering value for the other fuel parameter 
used to develop the complex model or used in the other parameter's 
augmentation study, and Ei is as defined in paragraph (c)(1) 
of this section, which are found to satisfy the statistical criteria 
defined in paragraph (e) of this section. Such terms shall be added to 
the regression model in a stepwise manner.
    (3) The model described in paragraphs (c) (1) and (2) of this 
section shall be developed separately for normal-emitting and higher-
emitting vehicles. Each emitter class shall be treated as a distinct 
population for the purposes of determining regression coefficients.
    (4) Once the augmented models described in paragraphs (c) (1) 
through (3) of this section have been developed, they shall be converted 
to an uncentered form through appropriate algebraic manipulation.
    (5) The augmented model described in paragraph (c)(4) of this 
section shall be used to determine the effects of the parameter in 
question at levels between the levels in Fuels 1 and 3, as defined at 
Sec. 80.49(a)(1), for all fuels which claim emission benefits from the 
parameter in question.
    (d)(1) In the case of petitions to augment the complex model defined 
at Sec. 80.45 by extending the range of an existing complex model 
parameter, the effect of the parameter being tested shall be determined 
separately, for each pollutant and for each technology

[[Page 681]]

group and emitter class category, at levels between the extension level 
and the nearest limit of the core of the data used to develop the 
unaugmented complex model as follows:

------------------------------------------------------------------------
                                                       Data core limits
                   Fuel parameter                    -------------------
                                                        Lower     Upper
------------------------------------------------------------------------
Sulfur, ppm.........................................      10       450
RVP, psi............................................       7        10
E200, vol %.........................................      33        66
E300, vol %.........................................      72        94
Aromatics, vol %....................................      18        46
Benzene, vol %......................................       0.4       1.8
Olefins, vol %......................................       1        19
Oxygen, wt %........................................
  As ethanol........................................       0         3.4
  All others:.......................................       0         2.7
------------------------------------------------------------------------

    (2) The emission performance of each vehicle on the fuels specified 
at Sec. 80.49(b)(2), as measured through vehicle testing in accordance 
with Sec. Sec. 80.50 through 80.62, shall be analyzed to determine the 
effects of the fuel parameter being tested on emissions according to the 
following procedure:
    (i) The analysis shall incorporate the vehicle testing data from the 
extension fuels specified at Sec. 80.49(b), the vehicle testing results 
used to develop the model specified at Sec. 80.45, and vehicle testing 
results used to support any prior augmentation requests which the 
Administrator deems necessary. A regression incorporating the following 
terms shall be fitted to the natural logarithm of emissions contained in 
this combined data set:
    (A) A term for each vehicle that shall reflect the effect of the 
vehicle on emissions independent of fuel compositions. These terms shall 
be of the form Di x Vi, where Di is the 
coefficient for the term and Vi is a dummy variable which 
shall have the value 1.0 for the ith vehicle and the value 0 for all 
other vehicles. Vehicles shall be represented by separate terms for each 
test program in which they were tested. The vehicle terms for the 
vehicles included in the test program undertaken by the petitioner shall 
be calculated based on the results from all three fuels specified at 
Sec. 80.49(b)(2).
    (B) Existing complex model terms that do not include the parameter 
being extended and their coefficients, including those augmentations 
that the Administrator deems necessary. The centering values for these 
terms shall be identical to the centering values used to develop the 
complex model described at Sec. 80.45.
    (C) Existing complex model terms that include the parameter being 
extended. The coefficients for these terms shall be estimated by the 
regression. The centering values for these terms shall be identical to 
the centering values used to develop the complex model described at 
Sec. 80.45.
    (D) If the unaugmented VOC or NOX complex models do not 
contain a squared term for the parameter being extended, such a term 
should be added in a stepwise fashion after completing the model 
described in paragraphs (d)(2)(i)(A) through (C) of this section. The 
coefficient for this term shall be estimated by the regression. The 
centering value for this term shall be identical to the centering value 
used to develop the complex model described at Sec. 80.45.
    (E) The terms defined in paragraphs (d)(2)(i)(C) and (D) of this 
section shall be evaluated against the statistical criteria defined in 
paragraph (e) of this section.
    (ii) The model described in paragraph (d)(2)(i) of this section 
shall be developed separately for normal-emitting and higher-emitting 
vehicles, as defined at Sec. 80.62. Each emitter class shall be treated 
as a distinct population for the purposes of determining regression 
coefficients.
    (e) Statistical criteria. (1) The petitioner shall be required to 
submit evidence with the petition which demonstrates the statistical 
validity of the regression described in paragraph (c) or (d) of this 
section, including at minimum:
    (i) Evidence demonstrating that colinearity problems are not severe, 
including but not limited to variance inflation statistics of less than 
10 for the second-order and interactive terms included in the regression 
model.
    (ii) Evidence demonstrating that the regression residuals are 
normally distributed, including but not limited to the skewness and 
Kurtosis statistics for the residuals.
    (iii) Evidence demonstrating that overfitting and underfitting risks 
have been balanced, including but not limited to the use of Mallow's 
Cp criterion.

[[Page 682]]

    (2) The petitioner shall be required to submit evidence with the 
petition which demonstrates that the appropriate terms have been 
included in the regression, including at minimum:
    (i) Descriptions of the analysis methods used to develop the 
regressions, including any computer code used to analyze emissions data 
and the results of regression runs used to develop the proposed 
augmentation, including intermediate regressions produced during the 
stepwise regression process.
    (ii) Evidence demonstrating that the significance level used to 
include terms in the model was equal to 0.90.
    (f) The complex emission model shall be augmented with the results 
of vehicle testing as follows:
    (1) The terms and coefficients determined in paragraph (c) or (d) of 
this section shall be used to supplement the complex emission model 
equation for the corresponding pollutant and emitter category. These 
terms and coefficients shall be weighted to reflect the contribution of 
the emitter category to in-use emissions as shown at Sec. 80.45.
    (2) If the candidate parameter is not included in the unaugmented 
complex model and is not represented in whole or in part by one or more 
parameters included in the model, the modification shall be accomplished 
by adding the terms and coefficients to the complex model equation for 
that pollutant, technology group, and emitter category.
    (3) If the parameter is included in the complex model but is being 
tested at levels beyond the current range of the model, the terms and 
coefficients determined in paragraph (d) of this section shall be used 
to supplement the complex emission model equation for the corresponding 
pollutant.
    (i) The terms and coefficients of the complex model described at 
Sec. 80.45 shall be used to evaluate the emissions performance of fuels 
with levels of the parameter being tested that are within the valid 
range of the model, as defined at Sec. 80.45.
    (ii) The emissions performance of fuels with levels of the parameter 
that are beyond the valid range of the unaugmented model shall be given 
in percentage change terms by 100 - [(100 + A) x (100 + C) / (100 + B)], 
where:
    (A) ``A'' shall be set equal to the percentage change in emissions 
for a fuel with identical fuel property values to the fuel being 
evaluated except for the parameter being extended, which shall be set 
equal to the nearest limit of the data core, using the unaugmented 
complex model.
    (B) ``B'' shall be set equal to the percentage change in emissions 
for the fuel described in paragraph (f)(3)(i) of this section according 
to the augmented complex model.
    (C) ``C'' shall be set equal to the percentage change in emissions 
of the actual fuel being evaluated using the augmented complex model.
    (g) EPA reserves the right to analyze the data generated during 
vehicle testing, to use such analyses to determine the validity of other 
augmentation petitions, and to use such data to update the complex model 
for use in certifying all reformulated gasolines.
    (h) Duration of acceptance of emission effects determined through 
vehicle testing:
    (1) If the Agency does not accept, modify, or reject a particular 
augmentation for inclusion in an updated complex model (performed 
through rulemaking), then the augmentation shall remain in effect until 
the next update to the complex model takes effect.
    (2) If the Agency does reject or modify a particular augmentation 
for inclusion in an updated complex model, then the augmentation shall 
no longer be able to be used as of the date the updated complex model is 
deemed to take effect, unless the following conditions and limitations 
apply:
    (i) The augmentation in question may continue to be used by those 
fuel suppliers which can prove, to the Administrator's satisfaction, 
that the fuel supplier had already begun producing a fuel utilizing the 
augmentation at the time the revised model is promulgated.
    (ii) The augmentation in question may only be used to evaluate the 
emissions performance of fuels in conjunction with the complex emission 
model in effect as of the date of production of the fuels.
    (iii) The augmentation may only be used for three years of fuel 
production, or a total of five years from the date

[[Page 683]]

the augmentation first took effect, whichever is shorter.
    (3) The Administrator shall determine when sufficient new 
information on the effects of fuel properties on vehicle emissions has 
been obtained to warrant development of an updated complex model.

[59 FR 7813, Feb. 16, 1994, as amended at 59 FR 36962, July 20, 1994]



Sec. 80.49  Fuels to be used in augmenting the complex emission model through vehicle testing.

    (a) Seven fuels (hereinafter called the ``addition fuels'') shall be 
tested for the purpose of augmenting the complex emission model with a 
parameter not currently included in the complex emission model. The 
properties of the addition fuels are specified in paragraphs (a)(1) and 
(2) of this section. The addition fuels shall be specified with at least 
the same level of detail and precision as in paragraph (a)(5)(i) of this 
section, and this information must be included in the petition submitted 
to the Administrator requesting augmentation of the complex emission 
model.
    (1) The seven addition fuels to be tested when augmenting the 
complex model specified at Sec. 80.45 with a new fuel parameter shall 
have the properties specified as follows:

              Properties of Fuels To Be Tested When Augmenting the Model With a New Fuel Parameter
----------------------------------------------------------------------------------------------------------------
                                                                     Fuels
        Fuel property        -----------------------------------------------------------------------------------
                                   1           2           3           4           5           6           7
----------------------------------------------------------------------------------------------------------------
Sulfur, ppm.................  150         150         150         35          35          500         500
Benzene, vol %..............  1.0         1.0         1.0         0.5         0.5         1.3         1.3
RVP, psi....................  7.5         7.5         7.5         6.5         6.5         8.1         8.1
E200, %.....................  50          50          50          62          62          37          37
E300, %.....................  85          85          85          92          92          79          79
Aromatics, vol %............  27          27          27          20          20          45          45
Olefins, vol %..............  9.0         9.0         9.0         2.0         2.0         18          18
Oxygen, wt %................  2.1         2.1         2.1         2.7         2.7         1.5         1.5
Octane, (R+M)/2.............  87          87          87          87          87          87          87
New Parameter \1\...........  C           (C+B)/2     B           C           B           C           B
----------------------------------------------------------------------------------------------------------------
\1\ C = Candidate level, B = Baseline level.

    (i) For the purposes of vehicle testing, the ``baseline'' level of 
the parameter shall refer to the level of the parameter in Clean Air Act 
baseline gasoline. The ``candidate'' level of the parameter shall refer 
to the most extreme value of the parameter, relative to baseline levels, 
for which the augmentation shall be valid.
    (ii) If the fuel parameter for which the fuel supplier is 
petitioning EPA to augment the complex emission model (hereinafter 
defined as the ``candidate parameter'') is not specified for Clean Air 
Act summer baseline fuel, then the baseline level for the candidate 
parameter shall be set at the levels found in typical gasoline. This 
level and the justification for this level shall be included in the 
petitioner's submittal to EPA prior to initiating the test program, and 
EPA must approve this level prior to the start of the program.
    (iii) If the candidate parameter is not specified for Clean Air Act 
summer baseline fuel, and is not present in typical gasoline, its 
baseline level shall be zero.
    (2) The addition fuels shall contain detergent control additives in 
accordance with section 211(l) of the Clean Air Act Amendments of 1990 
and the associated EPA requirements for such additives.
    (3) The addition fuels shall be specified with at least the same 
level of detail and precision as in paragraph (a)(5)(i) of this section, 
and this information shall be included in the petition submitted to the 
Administrator requesting augmentation of the complex emission model.
    (i) Paraffin levels in Fuels 1 and 2 shall be altered from the 
paraffin level in Fuel 3 to compensate for the addition or removal of 
the candidate parameter, if necessary. Paraffin levels in Fuel 4 shall 
be altered from the paraffin level in Fuel 5 to compensate for

[[Page 684]]

the addition or removal of the candidate parameter, if necessary. 
Paraffin levels in Fuel 6 shall be altered from the paraffin level in 
Fuel 7 to compensate for the addition or removal of the candidate 
parameter, if necessary.
    (ii) Other properties of Fuels 4 and 6 shall not vary from the 
levels for Fuels 5 and 7, respectively, unless such variations are the 
naturally-occurring result of the changes described in paragraphs (a)(1) 
and (2) of this section. Other properties of Fuels 1 and 2 shall not 
vary from the levels for Fuel 3, unless such variations are the 
naturally- occurring result of the changes described in paragraphs 
(a)(1) and (2) of this section.
    (iii) The addition fuels shall be specified with at least the same 
level of detail and precision as defined in paragraph (a)(5)(i) of this 
section, and this information must be included in the petition submitted 
to the Administrator requesting augmentation of the complex emission 
model.
    (4) The properties of the addition fuels shall be within the 
blending tolerances defined in this paragraph (a)(4) relative to the 
values specified in paragraphs (a)(1) and (2) of this section. Fuels 
that do not meet these tolerances shall require the approval of the 
Administrator to be used in vehicle testing to augment the complex 
emission model:

------------------------------------------------------------------------
              Fuel parameter                     Blending tolerance
------------------------------------------------------------------------
Sulfur content............................  25
                                             ppm.
Benzene content...........................  0.2
                                             vol %.
RVP.......................................  0.2
                                             psi.
E200 level................................  2 %.
E300 level................................  4 %.
Oxygenate content.........................  1.0
                                             vol %.
Aromatics content.........................  2.7
                                             vol %.
Olefins content...........................  2.5
                                             vol %.
Saturates content.........................  2.0
                                             vol %.
Octane....................................  0.5.
Detergent control additives...............  10% of
                                             the level required by EPA's
                                             detergents rule.
Candidate parameter.......................  To be determined as part of
                                             the augmentation process.
------------------------------------------------------------------------

    (5) The composition and properties of the addition fuels shall be 
determined by averaging a series of independent tests of the properties 
and compositional factors defined in paragraph (a)(5)(i) of this section 
as well as any additional properties or compositional factors for which 
emission benefits are claimed.
    (i) The number of independent tests to be conducted shall be 
sufficiently large to reduce the measurement uncertainty for each 
parameter to a sufficiently small value. At a minimum the 95% confidence 
limits (as calculated using a standard t-test) for each parameter must 
be within the following range of the mean measured value of each 
parameter:

------------------------------------------------------------------------
              Fuel  parameter                  Measurement uncertainty
------------------------------------------------------------------------
API gravity...............................  0.2[deg]API
Sulfur content............................  10 ppm
Benzene content...........................  0.02
                                             vol %
RVP.......................................  0.05
                                             psi
Octane....................................  0.2
                                             (R+M/2)
E200 level................................  2%
E300 level................................  2%
Oxygenate content.........................  0.2
                                             vol %
Aromatics content.........................  0.5
                                             vol %
Olefins content...........................  0.3
                                             vol %
Saturates content.........................  1.0
                                             vol %
Detergent control Additives...............  2% of
                                             the level required by EPA's
                                             detergents rule.
------------------------------------------------------------------------

    (ii) The 95% confidence limits for measurements of fuel parameters 
for which emission reduction benefits are claimed and for which 
tolerances are not defined in paragraph (a)(5)(i) of this section must 
be within 5% of the mean measured value.
    (iii) Each test must be conducted in the same laboratory in 
accordance with the procedures outlined at Sec. 80.46.
    (b) Three fuels (hereinafter called ``extention fuels'') shall be 
tested for purpose of extending the valid range of the complex emission 
model for a parameter currently included in the complex emission model. 
The properties of the extension fuels are specified in paragraphs (b)(2) 
through (4) of this section. The extension fuels shall be specified with 
at least the same level of detail and precision as in paragraph 
(a)(5)(i) of this section, and this information must be included in the 
petition submitted to the Administrator requesting augmentation of the 
complex emission model. Each set of three extension fuels shall be used 
only to extend the range of a single complex model parameter.
    (1) The ``extension level'' shall refer to the level to which the 
parameter being tested is to be extended. The three fuels to be tested 
when extending

[[Page 685]]

the range of fuel parameters already included in the complex model or a 
prior augmentation to the complex model shall be referred to as 
``extension fuels.''
    (2) The composition and properties of the extension fuels shall be 
as described in paragraphs (b)(2) (i) and (ii) of this section.
    (i) The extension fuels shall have the following levels of the 
parameter being extended:

        Level of Existing Complex Model Parameters Being Extended
------------------------------------------------------------------------
                                 Extension fuel    Extension   Extension
 Fuel property being extended         No. 1       fuel No. 2  fuel No. 3
------------------------------------------------------------------------
Sulfur, ppm...................  Extension level.        80         450
Benzene, vol %................  Extension level.         0.5         1.5
RVP, psi......................  Extension level.         6.7         8.0
E200, %.......................  Extension level.        38          61
E300, %.......................  Extension level.        78          92
Aromatics, vol %..............  Extension level.        20          45
Olefins, vol %................  Extension level.         3.0        18
Oxygen, wt %..................  Extension level.         1.7         2.7
Octane, R+M/2.................  87..............        87          87
------------------------------------------------------------------------

    (ii) The levels of parameters other than the one being extended 
shall be given by the following table for all three extension fuels:

       Levels for Fuel Parameters Other Than Those Being Extended
------------------------------------------------------------------------
                                         Extension  Extension  Extension
             Fuel property                fuel No.   fuel No.   fuel No.
                                             1          2          3
------------------------------------------------------------------------
Sulfur, ppm............................      150        150        150
Benzene, vol %.........................        1.0        1.0        1.0
RVP, psi...............................        7.5        7.5        7.5
E200, %................................       50         50         50
E300, %................................       85         85         85
Aromatics, vol %.......................       25         25         25
Olefins, vol %.........................        9.0        9.0        9.0
Oxygen, wt %...........................        2.0        2.0        2.0
Octane, R+M/2..........................       87         87         87
------------------------------------------------------------------------

    (3) If the Complex Model for any pollutant includes one or more 
interactive terms involving the parameter being extended, then two 
additional extension fuels shall be required to be tested for each such 
interactive term. These additional extension fuels shall have the 
following properties:
    (i) The parameter being tested shall be present at its extension 
level.
    (ii) The interacting parameter shall be present at the levels 
specified in paragraph (b)(2)(i) of this section for extension Fuels 2 
and 3.
    (iii) All other parameters shall be present at the levels specified 
in paragraph (b)(2)(ii) of this section.
    (4) All extension fuels shall contain detergent control additives in 
accordance with Section 211(l) of the Clean Air Act Amendments of 1990 
and the associated EPA requirements for such additives.
    (c) The addition fuels defined in paragraph (a) of this section and 
the extension fuels defined in paragraph (b) of this section shall meet 
the following requirements for blending and measurement precision:
    (1) The properties of the test and extension fuels shall be within 
the blending tolerances defined in this paragraph (c) relative to the 
values specified in paragraphs (a) and (b) of this section. Fuels that 
do not meet the following tolerances shall require the approval of the 
Administrator to be used in vehicle testing to augment the complex 
emission model:

------------------------------------------------------------------------
              Fuel parameter                     Blending tolerance
------------------------------------------------------------------------
Sulfur content............................  25
                                             ppm.
Benzene content...........................  0.2
                                             vol %.
RVP.......................................  0.2
                                             psi.
E200 level................................  2 %.
E300 level................................  4 %.
Oxygenate content.........................  1.5
                                             vol %.
Aromatics content.........................  2.7
                                             vol %.
Olefins content...........................  2.5
                                             vol %.
Saturates content.........................  2.0
                                             vol %.
Octane....................................  0.5.
Candidate parameter.......................  To be determined as part of
                                             the augmentation process.
------------------------------------------------------------------------

    (2) The extension and addition fuels shall be specified with at 
least the same level of detail and precision as defined in paragraph 
(c)(2)(ii) of this section, and this information must be included in the 
petition submitted to the Administrator requesting augmentation of the 
complex emission model.
    (i) The composition and properties of the addition and extension 
fuels shall be determined by averaging a series of independent tests of 
the properties and compositional factors defined in paragraph (c)(2)(ii) 
of this section as well as any additional properties or compositional 
factors for which emission benefits are claimed.
    (ii) The number of independent tests to be conducted shall be 
sufficiently

[[Page 686]]

large to reduce the measurement uncertainty for each parameter to a 
sufficiently small value. At a minimum the 95% confidence limits (as 
calculated using a standard t-test) for each parameter must be within 
the following range of the mean measured value of each parameter:

------------------------------------------------------------------------
              Fuel parameter                   Measurement uncertainty
------------------------------------------------------------------------
API gravity...............................  0.2
                                             [deg]API.
Sulfur content............................  5 ppm.
Benzene content...........................  0.05
                                             vol %.
RVP.......................................  0.08
                                             psi.
Octane....................................  0.1
                                             (R+M/2).
E200 level................................  2 %.
E300 level................................  2 %.
Oxygenate content.........................  0.2
                                             vol %.
Aromatics content.........................  0.5
                                             vol %.
Olefins content...........................  0.3
                                             vol %.
Saturates content.........................  1.0
                                             vol.%
Octane....................................  0.2.
Candidate parameter.......................  To be determined as part of
                                             the augmentation process.
------------------------------------------------------------------------

    (iii) Petitioners shall obtain approval from EPA for the 95% 
confidence limits for measurements of fuel parameters for which emission 
reduction benefits are claimed and for which tolerances are not defined 
in paragraph (c)(2)(i) of this section.
    (iv) Each test must be conducted in the same laboratory in 
accordance with the procedures outlined at Sec. 80.46.
    (v) The complex emission model described at Sec. 80.45 shall be 
used to adjust the emission performance of the addition and extension 
fuels to compensate for differences in fuel compositions that are 
incorporated in the complex model, as described at Sec. 80.48. 
Compensating adjustments for naturally-resulting variations in fuel 
parameters shall also be made using the complex model. The adjustment 
process is described in paragraph (d) of this section.
    (d) The complex emission model described at Sec. 80.45 shall be 
used to adjust the emission performance of addition and extension fuels 
to compensate for differences in fuel parameters other than the 
parameter being tested. Compensating adjustments for naturally-resulting 
variations in fuel parameters shall also be made using the complex 
model. These adjustments shall be calculated as follows:
    (1) Determine the exhaust emissions performance of the actual 
addition or extension fuels relative to the exhaust emissions 
performance of Clean Air Act baseline fuel using the complex model. For 
addition fuels, set the level of the parameter being tested at baseline 
levels for purposes of emissions performance evaluation using the 
complex model. For extension fuel 1, set the level of the 
parameter being extended at the level specified in extension fuel 
2. Also determine the exhaust emissions performance of the 
addition fuels specified in paragraph (a)(1) of this section with the 
level of the parameter being tested set at baseline levels.
    (2) Calculate adjustment factors for each addition fuel as follows:
    (i) Adjustment factors shall be calculated using the formula:
    [GRAPHIC] [TIFF OMITTED] TR16FE94.006
    
where

A = the adjustment factor
P(actual) = the performance of the actual fuel used in testing according 
to the complex model
P(nominal) = the performance that would have been achieved by the test 
fuel defined in paragraph (a)(1) of this section according to the 
complex model (as described in paragraph (d)(1) of this section).

    (ii) Adjustment factors shall be calculated for each pollutant and 
for each emitter class.
    (3) Multiply the measured emissions from each vehicle by the 
corresponding adjustment factor for the appropriate addition or 
extension fuel, pollutant, and emitter class. Use the resulting adjusted 
emissions to conduct all modeling and emission effect estimation 
activities described in Sec. 80.48.
    (e) All fuels included in vehicle testing programs shall have an 
octane number of 87.5, as measured by the (R+M)/2 method following the 
ASTM D4814 procedures, to within the measurement and blending tolerances 
specified in paragraph (c) of this section.
    (f) A single batch of each addition or extension fuel shall be used 
throughout the duration of the testing program.

[59 FR 7813, Feb. 16, 1994, as amended at 59 FR 36962, July 20, 1994; 71 
FR 74567, Dec. 15, 2005]

[[Page 687]]



Sec. 80.50  General test procedure requirements for augmentation
of the emission models.

    (a) The following test procedure must be followed when testing to 
augment the complex emission model described at Sec. 80.45.
    (1) VOC, NOX, CO, and CO2 emissions must be 
measured for all fuel-vehicle combinations tested.
    (2) Toxics emissions must be measured when testing the extension 
fuels per the requirements of Sec. 80.49(b) or when testing addition 
fuels 1, 2, or 3 per the requirements of Sec. 80.49(a).
    (3) When testing addition fuels 4, 5, 6, and 7 per the requirements 
of Sec. 80.49(a), toxics emissions need not be measured. However, EPA 
reserves the right to require the inclusion of such measurements in the 
test program prior to approval of the test program if evidence exists 
which suggests that adverse interactive effects of the parameter in 
question may exist for toxics emissions.
    (b) The general requirements per 40 CFR 86.130-96 shall be met.
    (c) The engine starting and restarting procedures per 40 CFR 86.136-
90 shall be followed.
    (d) Except as provided for at Sec. 80.59, general preparation of 
vehicles being tested shall follow procedures detailed in 40 CFR 86.130-
96 and 86.131-96.

[59 FR 7813, Feb. 16, 1994, as amended at 71 FR 74567, Dec. 15, 2005]



Sec. 80.51  Vehicle test procedures.

    The test sequence applicable when augmenting the emission models 
through vehicle testing is as follows:
    (a) Prepare vehicles per Sec. 80.50.
    (b) Initial preconditioning per Sec. 80.52(a)(1). Vehicles shall be 
refueled randomly with the fuels required in Sec. 80.49 when testing to 
augment the complex emission model.
    (c) Exhaust emissions tests, dynamometer procedure per 40 CFR 
86.137-90 with:
    (1) Exhaust Benzene and 1,3-Butadiene emissions measured per Sec. 
80.55; and
    (2) Formaldehyde and Acetelaldehyde emissions measured per Sec. 
80.56.



Sec. 80.52  Vehicle preconditioning.

    (a) Initial vehicle preconditioning and preconditioning between 
tests with different fuels shall be performed in accordance with the 
``General vehicle handling requirements'' per 40 CFR 86.132-96, up to 
and including the completion of the hot start exhaust test.
    (b) The preconditioning procedure prescribed at 40 CFR 86.132-96 
shall be observed for preconditioning vehicles between tests using the 
same fuel.



Sec. Sec. 80.53-80.54  [Reserved]



Sec. 80.55  Measurement methods for benzene and 1,3-butadiene.

    (a) Sampling for benzene and 1,3-butadiene must be accomplished by 
bag sampling as used for total hydrocarbons determination. This 
procedure is detailed in 40 CFR 86.109.
    (b) Benzene and 1,3-butadiene must be analyzed by gas 
chromatography. Expected values for benzene and 1,3-butadiene in bag 
samples for the baseline fuel are 4.0 ppm and 0.30 ppm respectively. At 
least three standards ranging from at minimum 50% to 150% of these 
expected values must be used to calibrate the detector. An additional 
standard of at most 0.01 ppm must also be measured to determine the 
required limit of quantification as described in paragraph (d) of this 
section.
    (c) The sample injection size used in the chromatograph must be 
sufficient to be above the laboratory determined limit of quantification 
(LOQ) as defined in paragraph (d) of this section for at least one of 
the bag samples. A control chart of the measurements of the standards 
used to determine the response, repeatability, and limit of quantitation 
of the instrumental method for 1,3-butadiene and benzene must be 
reported.
    (d) As in all types of sampling and analysis procedures, good 
laboratory practices must be used. See, Lawrence, Principals of 
Environmental Analysis, 55 Analytical Chemistry 14, at 2210-2218 (1983) 
(copies may be obtained from the publisher, American Chemical Society, 
1155 16th Street NW., Washington, DC 20036). Reporting reproducibility 
control charts and limits of detection measurements are integral 
procedures

[[Page 688]]

to assess the validity of the chosen analytical method. The 
repeatability of the test method must be determined by measuring a 
standard periodically during testing and recording the measured values 
on a control chart. The control chart shows the error between the 
measured standard and the prepared standard concentration for the 
periodic testing. The error between the measured standard and the actual 
standard indicates the uncertainty in the analysis. The limit of 
detection (LOD) is determined by repeatedly measuring a blank and a 
standard prepared at a concentration near an assumed value of the limit 
of detection. If the average concentration minus the average of the 
blanks is greater than three standard deviations of these measurements, 
then the limit of detection is at least as low as the prepared standard. 
The limit of quantitation (LOQ) is defined as ten times the standard 
deviation of these measurements. This quantity defines the amount of 
sample required to be measured for a valid analysis.
    (e) Other sampling and analytical techniques will be allowed if they 
can be proven to have equal specificity and equal or better limits of 
quantitation. Data from alternative methods that can be demonstrated to 
have equivalent or superior limits of detection, precision, and accuracy 
may be accepted by the Administrator with individual prior approval.



Sec. 80.56  Measurement methods for formaldehyde and acetaldehyde.

    (a) Formaldehyde and acetaldehyde will be measured by drawing 
exhaust samples from heated lines through either 2,4-
Dinitrophenylhydrazine (DNPH) impregnated cartridges or impingers filled 
with solutions of DNPH in acetonitrile (ACN) as described in Sec. Sec. 
86.109 and 86.140 of this chapter for formaldehyde analysis. Diluted 
exhaust sample volumes must be at least 15 L for impingers containing 20 
ml of absorbing solution (using more absorbing solution in the impinger 
requires proportionally more gas sample to be taken) and at least 4 L 
for cartridges. As required in Sec. 86.109 of this chapter, two 
impingers or cartridges must be connected in series to detect 
breakthrough of the first impinger or cartridge.
    (b) In addition, sufficient sample must be drawn through the 
collecting cartridges or impingers so that the measured quantity of 
aldehyde is sufficiently greater than the minimum limit of quantitation 
of the test method for at least a portion of the exhaust test procedure. 
The limit of quantitation is determined using the technique defined in 
Sec. 80.55(d).
    (c) Each of the impinger samples are quantitatively transferred to a 
25 mL volumetric flask (5 mL more than the sample impinger volume) and 
brought to volume with ACN. The cartridge samples are eluted in reversed 
direction by gravity feed with 6mL of ACN. The eluate is collected in a 
graduated test tube and made up to the 5mL mark with ACN. Both the 
impinger and cartridge samples must be analyzed by HPLC without 
additional sample preparation.
    (d) The analysis of the aldehyde derivatives collected is 
accomplished with a high performance liquid chromatograph (HPLC). 
Standards consisting of the hydrazone derivative of formaldehyde and 
acetaldehyde are used to determine the response, repeatability, and 
limit of quantitation of the HPLC method chosen for acetaldehyde and 
formaldehyde.
    (e) Other sampling and analytical techniques will be allowed if they 
can be proven to have equal specificity and equal or better limits of 
quantitation. Data from alternative methods that can be demonstrated to 
have equivalent or superior limits of detection, precision, and accuracy 
may be accepted by the Administrator with individual prior approval.



Sec. Sec. 80.57-80.58  [Reserved]



Sec. 80.59  General test fleet requirements for vehicle testing.

    (a) The test fleet must consist of only 1989-91 MY vehicles which 
are technologically equivalent to 1990 MY vehicles, or of 1986-88 MY 
vehicles for which no changes to the engine or exhaust system that would 
significantly affect emissions have been made through the 1990 model 
year. To be technologically equivalent vehicles at

[[Page 689]]

minimum must have closed-loop systems and possess adaptive learning.
    (b) No maintenance or replacement of any vehicle component is 
permitted except when necessary to ensure operator safety or as 
specifically permitted in Sec. 80.60 and Sec. 80.61. All vehicle 
maintenance procedures must be reported to the Administrator.
    (c) Each vehicle in the test fleet shall have no fewer than 4,000 
miles of accumulated mileage prior to being included in the test 
program.

[59 FR 7813, Feb. 16, 1994, as amended at 59 FR 36962, July 20, 1994]



Sec. 80.60  Test fleet requirements for exhaust emission testing.

    (a) Candidate vehicles which conform to the emission performance 
requirements defined in paragraphs (b) through (d) of this section shall 
be obtained directly from the in-use fleet and tested in their as-
received condition.
    (b) Candidate vehicles for the test fleet must be screened for their 
exhaust VOC emissions in accordance with the provisions in Sec. 80.62.
    (c) On the basis of pretesting pursuant to paragraph (b) of this 
section, the test fleet shall be subdivided into two emitter group sub-
fleets: the normal emitter group and the higher emitter group.
    (1) Each vehicle with an exhaust total hydrocarbon (THC) emissions 
rate which is less than or equal to twice the applicable emissions 
standard shall be placed in the normal emitter group.
    (2) Each vehicle with an exhaust THC emissions rate which is greater 
than two times the applicable emissions standard shall be placed in the 
higher emitter group.
    (d) The test vehicles in each emitter group must conform to the 
requirements of paragraphs (d)(1) through (4) of this section.
    (1) Test vehicles for the normal emitter sub-fleet must be selected 
from the list shown in this paragraph (d)(1). This list is arranged in 
order of descending vehicle priority, such that the order in which 
vehicles are added to the normal emitter sub-fleet must conform to the 
order shown (e.g., a ten-vehicle normal emitter group sub-fleet must 
consist of the first ten vehicles listed in this paragraph (d)(1)). If 
more vehicles are tested than the minimum number of vehicles required 
for the normal emitter sub-fleet, additional vehicles are to be added to 
the fleet in the order specified in this paragraph (d)(1), beginning 
with the next vehicle not already included in the group. The vehicles in 
the normal emitter sub-fleet must possess the characteristics indicated 
in the list. If the end of the list is reached in adding vehicles to the 
normal emitter sub-fleet and additional vehicles are desired then they 
shall be added beginning with vehicle number one, and must be added to 
the normal emitter sub-fleet in accordance with the order in table A:

                                                             Table A--Test Fleet Definitions
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                                                                                            Tech.
             Veh. No.                   Fuel system            Catalyst            Air injection             EGR            group        Manufacturer
--------------------------------------------------------------------------------------------------------------------------------------------------------
1................................  Multi...............  3W..................  No Air..............  EGR................          1  GM.
2................................  Multi...............  3W..................  No Air..............  No EGR.............          2  Ford.
3................................  TBI.................  3W..................  No Air..............  EGR................          3  GM.
4................................  Multi...............  3W+OX...............  Air.................  EGR................          4  Ford.
5................................  Multi...............  3W..................  No Air..............  EGR................          1  Honda.
6................................  Multi...............  3W..................  No Air..............  No EGR.............          2  GM.
7................................  TBI.................  3W..................  No Air..............  EGR................          3  Chrysler.
8................................  Multi...............  3W+OX...............  Air.................  EGR................          4  GM.
9................................  TBI.................  3W+OX...............  Air.................  EGR................          7  Chrysler.
10...............................  Multi...............  3W..................  Air.................  EGR................          5  Toyota.
11...............................  Multi...............  3W..................  No Air..............  EGR................          1  Ford.
12...............................  Multi...............  3W..................  No Air..............  No EGR.............          2  Chrysler.
13...............................  Carb................  3W+OX...............  Air.................  EGR................          9  Toyota.
14...............................  TBI.................  3W..................  No Air..............  EGR................          3  Ford.
15...............................  Multi...............  3W+OX...............  Air.................  EGR................          4  GM.
16...............................  Multi...............  3W..................  No Air..............  EGR................          1  Toyota.
17...............................  Multi...............  3W..................  No Air..............  No EGR.............          2  Mazda.
18...............................  TBI.................  3W..................  No Air..............  EGR................          3  GM.
19...............................  Multi...............  3W+OX...............  Air.................  EGR................          4  Ford.

[[Page 690]]

 
20...............................  Multi...............  3W..................  No Air..............  EGR................          1  Nissan.
--------------------------------------------------------------------------------------------------------------------------------------------------------


                                   Table B--Tech Group Definitions in Table A
----------------------------------------------------------------------------------------------------------------
           Tech group                 Fuel system          Catalyst          Air injection            EGR
----------------------------------------------------------------------------------------------------------------
1...............................  Multi.............  3W................  No Air............  EGR.
2...............................  Multi.............  3W................  No Air............  No EGR.
3...............................  TBI...............  3W................  No Air............  EGR.
4...............................  Multi.............  3W+OX.............  Air...............  EGR.
5...............................  Multi.............  3W................  Air...............  EGR.
6...............................  TBI...............  3W................  Air...............  EGR.
7...............................  TBI...............  3W+OX.............  Air...............  EGR.
8...............................  TBI...............  3W................  No Air............  No EGR.
9...............................  Carb..............  3W+OX.............  Air...............  EGR.
----------------------------------------------------------------------------------------------------------------


Legend:

Fuel system:
    Multi = Multi-point fuel injection
    TBI = Throttle body fuel injection
    Carb = Carburetted
Catalyst:
    3W = 3-Way catalyst
    3W+OX = 3-Way catalyst plus an oxidation catalyst
Air Injection:
    Air = Air injection
EGR = Exhaust gas recirculation

    (2) Test vehicles for the higher emitter sub-fleet shall be selected 
from the in-use fleet in accordance with paragraphs (a) and (b) of this 
section and with Sec. 80.59. Test vehicles for the higher emitter sub-
fleet are not required to follow the pattern established in paragraph 
(d)(1) of this section.
    (3) The minimum test fleet size is 20 vehicles. Half of the vehicles 
tested must be included in the normal emitter sub-fleet and half of the 
vehicles tested must be in the higher emitter sub-fleet. If additional 
vehicles are tested beyond the minimum of twenty vehicles, the 
additional vehicles shall be distributed equally between the normal and 
higher emitter sub-fleets.
    (4) For each emitter group sub-fleet, 70 9.5% 
of the sub-fleet must be LDVs, & 30 9.5% must be 
LDTs. LDTs include light-duty trucks class 1 (LDT1), and light-duty 
trucks class 2 (LDT2) up to 8500 lbs GVWR.



Sec. 80.61  [Reserved]



Sec. 80.62  Vehicle test procedures to place vehicles in emitter
group sub-fleets.

    One of the two following test procedures must be used to screen 
candidate vehicles for their exhaust THC emissions to place them within 
the emitter group sub-fleets in accordance with the requirements of 
Sec. 80.60.
    (a) Candidate vehicles may be tested for their exhaust THC emissions 
using the Federal test procedure as detailed in 40 CFR part 86, with 
gasoline conforming to requirements detailed in 40 CFR 86.113-90. The 
results shall be used in accordance with the requirements in Sec. 80.60 
to place the vehicles within their respective emitter groups.
    (b) Alternatively, candidate vehicles may be screened for their 
exhaust THC emissions with the IM240 short test procedure.\1\ The 
results from the IM240 shall be converted into results comparable with 
the standard exhaust FTP as detailed in this paragraph (b) to place the 
vehicles within their respective emitter groups in accordance with the 
requirements of Sec. 80.60.
---------------------------------------------------------------------------

    \1\ EPA Technical Report EPA-AA-TSS-91-1. Copies may be obtained by 
ordering publication number PB92104405 from the National Technical 
Information Service, 5285 Port Royal Road, Springfield, Virginia 22161.
---------------------------------------------------------------------------

    (1) A candidate vehicle with IM240 test results <0.367 grams THC per 
vehicle mile shall be classified as a normal emitter.

[[Page 691]]

    (2) A candidate vehicle with IM240 test results =0.367 
grams THC per vehicle mile shall be classified as a higher emitter.



Sec. Sec. 80.63-80.64  [Reserved]



Sec. 80.65  General requirements for refiners and importers.

    (a) Date requirements begin. The requirements of this subpart D 
apply to all gasoline produced, imported, transported, stored, sold, or 
dispensed:
    (1) At any location other than retail outlets and wholesale 
purchaser-consumer facilities on or after December 1, 1994; and
    (2) At any location on or after January 1, 1995.
    (b) Certification of gasoline and RBOB. Gasoline or RBOB sold or 
dispensed in a covered area must be certified under Sec. 80.40.
    (c) Standards must be met on either a per-gallon or on an average 
basis. (1) Any refiner or importer, for each batch of reformulated 
gasoline or RBOB it produces or imports, shall meet:
    (i) Those standards and requirements it designated under paragraph 
(d) of this section for per-gallon compliance on a per-gallon basis; and
    (ii) Those standards and requirements it designated under paragraph 
(d) of this section for average compliance on an average basis over the 
applicable averaging period.
    (2) [Reserved]
    (3)(i) For each averaging period, and separately for each parameter 
that may be met either per-gallon or on average, any refiner shall 
designate for each refinery, or any importer shall designate its 
gasoline or RBOB as being subject to the standard applicable to that 
parameter on either a per-gallon or average basis. For any specific 
averaging period and parameter all batches of gasoline or RBOB shall be 
designated as being subject to the per-gallon standard, or all batches 
of gasoline and RBOB shall be designated as being subject to the average 
standard. For any specific averaging period and parameter a refiner for 
a refinery, or any importer may not designate certain batches as being 
subject to the per-gallon standard and others as being subject to the 
average standard.
    (ii) In the event any refiner for a refinery, or any importer fails 
to meet the requirements of paragraph (c)(3)(i) of this section and for 
a specific averaging period and parameter designates certain batches as 
being subject to the per-gallon standard and others as being subject to 
the average, all batches produced or imported during the averaging 
period that were designated as being subject to the average standard 
shall, ab initio, be redesignated as being subject to the per-gallon 
standard. This redesignation shall apply regardless of whether the 
batches in question met or failed to meet the per-gallon standard for 
the parameter in question.
    (d) Designation of gasoline. Any refiner or importer of gasoline 
shall designate the gasoline it produces or imports as follows:
    (1) All gasoline produced or imported shall be properly designated 
as either reformulated or conventional gasoline, or as RBOB.
    (2) All gasoline designated as reformulated or as RBOB shall be 
further properly designated as:
    (i) Either VOC-controlled or not VOC-controlled;
    (ii) In the case of gasoline or RBOB designated as VOC-controlled:
    (A) Either intended for use in VOC-Control Region 1 or VOC-Control 
Region 2 (as defined in Sec. 80.71); or
    (B) Designated as ``adjusted VOC gasoline'' (as defined in Sec. 
80.40(c)(1));
    (iii) [Reserved]
    (iv) For gasoline or RBOB produced, imported, sold, dispensed or 
used during the period January 1, 1995 through December 31, 1997, either 
as being subject to the simple model standards, or to the complex model 
standards;
    (v) For each of the following parameters, either gasoline or RBOB 
which meets the standard applicable to that parameter on a per-gallon 
basis or on average:
    (A) Toxics emissions performance;
    (B) NOX emissions performance in the case of gasoline 
certified using the complex model.
    (C) Benzene content;
    (D) [Reserved]
    (E) In the case of VOC-controlled gasoline or RBOB certified using 
the simple model, RVP; and

[[Page 692]]

    (F) In the case of VOC-controlled gasoline or RBOB certified using 
the complex model, VOC emissions performance; and
    (vi) In the case of RBOB, the gasoline must be designated as RBOB 
and the designation must include the type(s) and amount(s) of oxygenate 
required to be blended with the RBOB.
    (3) Every batch of reformulated or conventional gasoline or RBOB 
produced or imported at each refinery or import facility shall be 
assigned a number (the ``batch number''), consisting of the EPA-assigned 
refiner or importer registration number, the EPA facility registration 
number, the last two digits of the year in which the batch was produced, 
and a unique number for the batch, beginning with the number one for the 
first batch produced or imported each calendar year and each subsequent 
batch during the calendar year being assigned the next sequential number 
(e.g., 4321-54321-95-000001, 4321-543321-95-000002, etc.)
    (e) Determination of volume and properties. (1) Each refiner or 
importer shall for each batch of reformulated gasoline or RBOB produced 
or imported determine the volume and the value of each of the properties 
specified in paragraph (e)(2)(i) of this section, except that the value 
for RVP must be determined only in the case of reformulated gasoline or 
RBOB that is VOC-controlled. These determinations shall:
    (i) Be based on a representative sample of the reformulated gasoline 
or RBOB that is analyzed using the methodologies specified in Sec. 
80.46;
    (ii) In the case of RBOB, follow the oxygenate blending instructions 
specified in Sec. 80.69(a);
    (iii) Be carried out either by the refiner or importer, or by an 
independent laboratory; and
    (iv) Be completed prior to the gasoline or RBOB leaving the refinery 
or import facility for each parameter that the gasoline or RBOB is 
subject to, or that is used to calculate an emissions performance that 
the gasoline or RBOB is subject to, under Sec. 80.41(a) through (f).
    (2) In the event that the values of any of these properties is 
determined by the refiner or importer and by an independent laboratory 
in conformance with the requirements of paragraph (f) of this section:
    (i) The results of the analyses conducted by the refiner or importer 
for such properties shall be used as the basis for compliance 
determinations unless the absolute value of the differences of the test 
results from the two laboratories is larger than the following values:

------------------------------------------------------------------------
              Fuel property                            Range
------------------------------------------------------------------------
Sulfur content...........................  25 ppm
Aromatics content........................  2.7 vol %
Olefins content..........................  2.5 vol %
Benzene content..........................  0.21 vol %
Ethanol content..........................  0.4 vol %
Methanol content.........................  0.2 vol %
MTBE (and other methyl ethers) content...  0.6 vol %
ETBE (and other ethyl ethers) content....  0.6 vol %
TAME.....................................  0.6 vol %
t-Butanol content........................  0.6 vol %
RVP......................................  0.3 psi
50% distillation (T50)...................  5 [deg]F
90% distillation (T90)...................  5 [deg]F
E200.....................................  2.5 vol %
E300.....................................  3.5 vol %
API Gravity..............................  0.3 [deg]API
------------------------------------------------------------------------

    (ii) In the event the values from the two laboratories for any 
property fall outside these ranges, the refiner or importer shall use as 
the basis for compliance determinations:
    (A) The larger of the two values for the property, except the 
smaller of the two results shall be used for oxygenates; or
    (B) The refiner or importer shall have the gasoline analyzed for the 
property at one additional independent laboratory. If this second 
independent laboratory obtains a result for the property that is within 
the range, as listed in paragraph (e)(2)(i) of this section, of the 
refiner's or importer's result for this property, then the refiner's or 
importer's result shall be used as the basis for compliance 
determinations.
    (f) Independent analysis requirement. (1) Any refiner or importer of 
reformulated gasoline or RBOB shall carry out a program of independent 
sample collection and analyses for the reformulated gasoline it produces 
or imports, which meets the requirements of one of the following two 
options:
    (i) Option 1. The refiner or importer shall, for each batch of 
reformulated gasoline or RBOB that is produced or imported, have the 
value for each property specified in paragraph (e)(2)(i) of

[[Page 693]]

this section determined by an independent laboratory that collects and 
analyzes a representative sample from the batch using the methodologies 
specified in Sec. 80.46.
    (ii) Option 2. The refiner or importer shall have a periodic 
independent testing program carried out for all reformulated gasoline 
produced or imported, which shall consist of the following:
    (A) An independent laboratory shall collect a representative sample 
from each batch of reformulated gasoline that the refiner or importer 
produces or imports;
    (B) EPA will identify up to ten percent of the total number of 
samples collected under paragraph (f)(1)(ii)(A) of this section; and
    (C) The designated independent laboratory shall, for each sample 
identified by EPA under paragraph (f)(1)(ii)(B) of this section, 
determine the value for each property using the methodologies specified 
in Sec. 80.46.
    (2)(i) Any refiner or importer shall designate one independent 
laboratory for each refinery or import facility at which reformulated 
gasoline or RBOB is produced or imported. This independent laboratory 
will collect samples and perform analyses in compliance with the 
requirements of this paragraph (f) of this section.
    (ii) Any refiner or importer shall identify this designated 
independent laboratory to EPA under the registration requirements of 
Sec. 80.76.
    (iii) In order to be considered independent:
    (A) The laboratory shall not be operated by any refiner or importer, 
and shall not be operated by any subsidiary or employee of any refiner 
or importer;
    (B) The laboratory shall be free from any interest in any refiner or 
importer; and
    (C) The refiner or importer shall be free from any interest in the 
laboratory; however
    (D) Notwithstanding the restrictions in paragraphs (f)(2)(iii) (A) 
through (C) of this section, a laboratory shall be considered 
independent if it is owned or operated by a gasoline pipeline company, 
regardless of ownership or operation of the gasoline pipeline company by 
refiners or importers, provided that such pipeline company is owned and 
operated by four or more refiners or importers.
    (iv) Use of a laboratory that is debarred, suspended, or proposed 
for debarment pursuant to the Governmentwide Debarment and Suspension 
regulations, 2 CFR part 1532, or the Debarment, Suspension and 
Ineligibility provisions of the Federal Acquisition Regulations, 48 CFR 
part 9, subpart 9.4, shall be deemed noncompliance with the requirements 
of this paragraph (f).
    (v) Any laboratory that fails to comply with the requirements of 
this paragraph (f) shall be subject to debarment or suspension under 
Governmentwide Debarment and Suspension regulations, 2 CFR part 1532, or 
the Debarment, Suspension and Ineligibility regulations, Federal 
Acquisition Regulations, 48 CFR part 9, subpart 9.4.
    (3) Any refiner or importer shall, for all samples collected or 
analyzed pursuant to the requirements of this paragraph (f), cause its 
designated independent laboratory:
    (i) At the time the designated independent laboratory collects a 
representative sample from a batch of reformulated gasoline, to:
    (A) Obtain the refiner's or importer's assigned batch number for the 
batch being sampled;
    (B) Determine the volume of the batch;
    (C) Determine the identification number of the gasoline storage tank 
or tanks in which the batch was stored at the time the sample was 
collected;
    (D) Determine the date and time the batch became finished 
reformulated gasoline, and the date and time the sample was collected;
    (E) Determine the grade of the batch (e.g., premium, mid-grade, or 
regular); and
    (F) In the case of reformulated gasoline produced through computer-
controlled in-line blending, determine the date and time the blending 
process began and the date and time the blending process ended, unless 
exempt under paragraph (f)(4) of this section;
    (ii) To retain each sample collected pursuant to the requirements of 
this paragraph (f) for a period of 30 days, except that this period 
shall be extended

[[Page 694]]

to a period of up to 180 days upon request by EPA;
    (iii) To submit to EPA periodic reports, as follows:
    (A) A report for the period January through March shall be submitted 
by May 31; a report for the period April through June shall be submitted 
by August 31; a report for the period July through September shall be 
submitted by November 30; and a report for the period October through 
December shall be submitted by February 28;
    (B) Each report shall include, for each sample of reformulated 
gasoline that was analyzed pursuant to the requirements of this 
paragraph (f):
    (1) The results of the independent laboratory's analyses for each 
property; and
    (2) The information specified in paragraph (f)(3)(i) of this section 
for such sample; and
    (iv) To supply to EPA, upon EPA's request, any sample collected or a 
portion of any such sample.
    (4) Any refiner that produces reformulated gasoline using computer-
controlled in-line blending equipment is exempt from the independent 
sampling and testing requirements specified in paragraphs (f)(1) through 
(3) of this section and from the requirement of paragraph (e)(1) of this 
section to obtain test results for each batch prior to the gasoline 
leaving the refinery, provided that such refiner:
    (i) Obtains from EPA an exemption from these requirements. In order 
to seek such an exemption, the refiner shall submit a petition to EPA, 
such petition to include:
    (A) A description of the refiner's computer-controlled in-line 
blending operation, including a description of:
    (1) The location of the operation;
    (2) The length of time the refiner has used the operation;
    (3) The volumes of gasoline produced using the operation since the 
refiner began the operation or during the previous three years, 
whichever is shorter, by grade;
    (4) The movement of the gasoline produced using the operation to the 
point of fungible mixing, including any points where all or portions of 
the gasoline produced is accumulated in gasoline storage tanks;
    (5) The physical lay-out of the operation;
    (6) The automated control system, including the method of monitoring 
and controlling blend properties and proportions;
    (7) Any sampling and analysis of gasoline that is conducted as a 
part of the operation, including on-line, off-line, and composite, and a 
description of the methods of sampling, the methods of analysis, the 
parameters analyzed and the frequency of such analyses, and any written, 
printed, or computer-stored results of such analyses, including 
information on the retention of such results;
    (8) Any sampling and analysis of gasoline produced by the operation 
that occurs downstream from the blending operation prior to fungible 
mixing of the gasoline, including any such sampling and analysis by the 
refiner and by any purchaser, pipeline or other carrier, or by 
independent laboratories;
    (9) Any quality assurance procedures that are carried out over the 
operation; and
    (10) Any occasion(s) during the previous three years when the 
refiner adjusted any physical or chemical property of any gasoline 
produced using the operation downstream from the operation, including 
the nature of the adjustment and the reason the gasoline had properties 
that required adjustment; and
    (B) A description of the independent audit program of the refiner's 
computer-controlled in-line blending operation that the refiner proposes 
will satisfy the requirements of this paragraph (f)(4); and
    (ii) Carries out an independent audit program of the refiner's 
computer-controlled in-line blending operation, such program to include:
    (A) For each batch of reformulated gasoline produced using the 
operation, a review of the documents generated that is sufficient to 
determine the properties and volume of the gasoline produced;
    (B) Audits that occur no less frequently than annually;
    (C) Reports of the results of such audits submitted to the refiner, 
and to EPA by the auditor no later than February 28 of each year;

[[Page 695]]

    (D) Audits that are conducted by an auditor that meets the non-
debarred criteria specified in Sec. 80.125 (a) and/or (d); and
    (iii) Complies with any other requirements that EPA includes as part 
of the exemption.
    (g) [Reserved]
    (h) Compliance audits. Any refiner and importer of any reformulated 
gasoline or RBOB shall have the reformulated gasoline and RBOB it 
produced or imported during each calendar year audited for compliance 
with the requirements of this subpart D, in accordance with the 
requirements of subpart F, at the conclusion of each calendar year.
    (i) Exclusion of previously certified gasoline. Any refiner who uses 
previously certified reformulated or conventional gasoline or RBOB to 
produce reformulated gasoline or RBOB must exclude the previously 
certified gasoline for purposes of demonstrating compliance with the 
standards under Sec. 80.41. This exclusion must be accomplished by the 
refiner as follows:
    (1)(i) Determine the volume and properties of each batch of 
previously certified gasoline used to produce reformulated gasoline or 
RBOB using the procedures in paragraph (e)(1) of this section and Sec. 
80.66, and the independent analysis requirements in paragraph (f) of 
this section in the case of previously certified reformulated gasoline.
    (ii) In the case of previously certified reformulated gasoline or 
RBOB determine the emissions performances for toxics and NOX, 
and VOC for VOC-controlled gasoline, and the designations for VOC 
control.
    (iii) In the case of previously certified conventional gasoline 
determine the exhaust toxics and NOX emissions performances.
    (2) Determine the volume and properties, and the emissions 
performance for toxics and NOX, and VOC for VOC-controlled 
gasoline, of any batch of reformulated gasoline or RBOB produced at the 
refinery using previously certified gasoline and include each batch in 
the refinery's compliance calculations without regard to the presence of 
previously certified gasoline in the batch.
    (3) In the case of any parameter or emissions performance standard 
that the refiner has designated for the refinery to meet on a per-gallon 
basis under paragraph (d)(2)(v) of this section, the per-gallon standard 
that applies to any batch of reformulated gasoline or RBOB produced by 
the refinery is as follows:
    (i) When using any previously certified reformulated gasoline or 
RBOB, the more stringent of:
    (A) The per-gallon standard that applies to the refinery under Sec. 
80.41; or
    (B) The most stringent value for that parameter or emissions 
performance for any previously certified reformulated gasoline or RBOB 
used to produce the batch.
    (ii) When using any previously certified conventional gasoline, the 
per-gallon standard that applies to the refinery under Sec. 80.41.
    (4) In the case of any parameter or emissions performance standard 
that the refiner has designated for the refinery to meet on average 
under paragraph (d)(2)(v) of this section, any previously certified 
gasoline must be excluded from the refinery's compliance calculations as 
follows:
    (i) Where a refiner uses previously certified reformulated gasoline 
or RBOB to produce reformulated gasoline or RBOB:
    (A) The refiner must include the volume and properties of any batch 
of previously certified reformulated gasoline or RBOB in the refinery's 
compliance calculations for the standard under Sec. 80.67(g) as a 
negative batch, by multiplying the term Vi in Sec. 
80.67(g)(1)(ii) (i.e., the batch volume) times negative 1; and
    (B) The negative batch under paragraph (i)(4)(i)(A) of this section 
must be included in the averaging categories that correspond to the 
designation regarding VOC control of the previously certified gasoline 
batch when received; and
    (C) The net volume of gasoline in the refinery's reformulated 
gasoline compliance calculations must be positive in each of the 
following categories where the standard is being met on average:

------------------------------------------------------------------------
                                             Gasoline category that must
                 Standard                     have net positive volume
------------------------------------------------------------------------
(1) Oxygen................................  All RFG \1\.
(2) Benzene...............................  All RFG and RBOB.

[[Page 696]]

 
(3) VOC emissions performance.............  (i)RFG and RBOB that is VOC-
                                             controlled for Region 1.
                                            (ii) RFG and RBOB that is
                                             VOC-controlled for Region
                                             2.
(4) Toxics emissions performance..........  All RFG and RBOB.
(5) NOX emissions performance.............  (i) All RFG and RBOB.
                                            (ii) RFG and RBOB that is
                                             VOC-controlled.
------------------------------------------------------------------------
\1\ ``RFG'' is an abbreviation for reformulated gasoline.

    (ii) Where a refiner uses previously certified conventional gasoline 
to produce reformulated gasoline or RBOB:
    (A) The refiner must include the volume and properties of any batch 
of previously certified conventional gasoline as a negative batch in the 
refiner's anti-dumping compliance calculations under Sec. 80.101(g) for 
the refinery, or where applicable, the refiner's aggregation under Sec. 
80.101(h); and
    (B) The net volume of gasoline in the refiner's anti-dumping 
compliance calculations for the refinery, or, where applicable, the 
refiner's aggregation under Sec. 80.101(h), must be positive.
    (5) The refiner must use any previously certified gasoline that the 
refiner includes as a negative batch under paragraph (i)(4) of this 
section in its compliance calculations for the refinery, or where 
appropriate, the refiner's aggregation, as a component in gasoline 
production during the annual averaging period in which the previously 
certified gasoline was included as a negative batch in the refiner's 
compliance calculations.
    (6) (i) Any refiner may use the procedures specified in this 
paragraph (i) to combine previously certified conventional gasoline with 
reformulated gasoline or RBOB, to reclassify conventional gasoline into 
reformulated gasoline or RBOB, or to change the designations of 
reformulated gasoline or RBOB with regard to VOC control.
    (ii) The procedures under this section are refinery procedures. Any 
person who uses the procedures under this section is a refiner who must 
meet all requirements applicable to refiners under this subpart.
    (7) Nothing in this paragraph (i) prevents any party from combining 
previously certified reformulated gasolines from different sources in a 
manner that does not violate the prohibitions in Sec. 80.78(a).

[59 FR 7813, Feb. 16, 1994, as amended at 59 FR 36962, July 20, 1994; 59 
FR 39289, Aug. 2, 1994; 59 FR 60715, Nov. 28, 1994; 62 FR 60135, Nov. 6, 
1997; 66 FR 37165, July 17, 2001; 66 FR 67105, Dec. 28, 2001; 67 FR 
8737, Feb. 26, 2002; 71 FR 74567, Dec. 15, 2005; 71 FR 26698, May 8, 
2006; 72 FR 2427, Jan. 19, 2007]



Sec. 80.66  Calculation of reformulated gasoline properties.

    (a) All volume measurements required by these regulations shall be 
temperature adjusted to 60 degrees Fahrenheit.
    (b) The percentage of oxygen by weight contained in a gasoline 
blend, based upon its percentage oxygenate by volume and density, shall 
exclude denaturants and water.
    (c) The properties of reformulated gasoline consist of per-gallon 
values separately and individually determined on a batch-by-batch basis 
using the methodologies specified in Sec. 80.46 for each of those 
physical and chemical parameters necessary to determine compliance with 
the standards to which the gasoline is subject, and per-gallon values 
for the VOC, NOX, and toxics emissions performance standards 
to which the gasoline is subject.
    (d) Per-gallon oxygen content shall be determined based upon the 
weight percent oxygen of a representative sample of gasoline, using the 
method set forth in Sec. 80.46(g). The total oxygen content associated 
with a batch of gasoline (in percent-gallons) is calculated by 
multiplying the weight percent oxygen content times the volume.
    (e) Per-gallon benzene content shall be determined based upon the 
volume percent benzene of a representative sample of a batch of gasoline 
by the method set forth in Sec. 80.46(e). The total benzene content 
associated with a batch of gasoline (in percent-gallons) is calculated 
by multiplying the volume percent benzene content times the volume.
    (f) Per-gallon RVP shall be determined based upon the measurement of 
RVP of a representative sample of a batch of gasoline by the sampling 
methodologies specified in appendix D

[[Page 697]]

of this part and the testing methodology specified in appendix E of this 
part. The total RVP value associated with a batch of gasoline (in RVP-
gallons) is calculated by multiplying the RVP times the volume.
    (g)(1) Per gallon values for VOC and NOX emissions 
reduction shall be calculated using the methodology specified in Sec. 
80.45 that is appropriate for the gasoline.
    (2) Per-gallon values for toxic emissions performance reduction 
shall be established using:
    (i) For gasoline subject to the simple model, the methodology under 
Sec. 80.42 that is appropriate for the gasoline; and
    (ii) For gasoline subject to the complex model, the methodology 
specified in Sec. 80.45 that is appropriate for the gasoline.
    (3) The total VOC, NOX, and toxic emissions performance 
reduction values associated with a batch of gasoline (in percent 
reduction-gallons) is calculated by multiplying the per-gallon percent 
emissions performance reduction times the volume of the batch.

[59 FR 7813, Feb. 16, 1994, as amended at 59 FR 36963, July 20, 1994]



Sec. 80.67  Compliance on average.

    The requirements of this section apply to all reformulated gasoline 
and RBOB produced or imported for which compliance with one or more of 
the requirements of Sec. 80.41 is determined on average (``averaged 
gasoline'').
    (a) Compliance survey required in order to meet standards on 
average. (1) Any refiner or importer that complies with the compliance 
survey requirements of Sec. 80.68 has the option of meeting the 
standards specified in Sec. 80.41 for average compliance in addition to 
the option of meeting the standards specified in Sec. 80.41 for per-
gallon compliance; any refiner or importer that does not comply with the 
survey requirements must meet the standards specified in Sec. 80.41 for 
per-gallon compliance, and does not have the option of meeting standards 
on average.
    (2)(i)(A) A refiner or importer that produces or imports 
reformulated gasoline that exceeds the average standard for benzene (but 
not for other parameters that have average standards) may use such 
gasoline to offset reformulated gasoline which does not achieve this 
average standard, but only if the reformulated gasoline that does not 
achieve this average standard is sold to ultimate consumers in the same 
covered area as was the reformulated gasoline which exceeds the average 
standard; provided that:
    (B) Prior to the beginning of the averaging period when the 
averaging approach described in paragraph (a)(2)(i)(A) of this section 
is used, the refiner or importer obtains approval from EPA. In order to 
seek such approval, the refiner or importer shall submit a petition to 
EPA, such petition to include:
    (1) The identification of the refiner and refinery, or importer, the 
covered area, and the averaging period; and
    (2) A detailed description of the procedures the refiner or importer 
will use to ensure the gasoline is produced by the refiner or is 
imported by the importer and is used only in the covered area in 
question and is not used in any other covered area, and the record 
keeping, reporting, auditing, and other quality assurance measures that 
will be followed to establish the gasoline is used as intended; and
    (C) The refiner or importer properly completes any requirements that 
are specified by EPA as conditions for approval of the petition.
    (ii) Any refiner or importer that meets the requirements of 
paragraph (a)(2)(i) of this section will be deemed to have satisfied the 
compliance survey requirements of Sec. 80.68 for the covered area in 
question.
    (b) Scope of averaging. (1) Any refiner shall meet all applicable 
averaged standards separately for each of the refiner's refineries;
    (2)(i) Any importer shall meet all applicable averaged standards on 
the basis of all averaged reformulated gasoline and RBOB imported by the 
importer; except that
    (ii) Any importer to whom different standards apply for gasoline 
imported at different facilities by operation of Sec. 80.41(i), shall 
meet the averaged standards separately for the averaged reformulated 
gasoline and RBOB imported into each group of facilities that is subject 
to the same standards; and

[[Page 698]]

    (3) [Reserved]
    (c) RVP and VOC emissions performance reduction compliance on 
average. (1) The VOC-controlled reformulated gasoline and RBOB produced 
at any refinery or imported by any importer during the period January 1 
through September 15 of each calendar year which is designated for 
average compliance for RVP or VOC emissions performance on average must 
meet the standards for RVP (in the case of a refinery or importer 
subject to the simple model standards) or the standards for VOC 
emissions performance reduction (in the case of a refinery or importer 
subject to the complex model standards) which are applicable to that 
refinery or importer as follows:
    (i) Gasoline and RBOB designated for VOC Control Region 1 must meet 
the standards for that Region which are applicable to that refinery or 
importer; and
    (ii) Gasoline and RBOB designated for VOC Control Region 2 must meet 
the standards for that Region which are applicable to that refinery or 
importer.
    (2) In the case of a refinery or importer subject to the simple 
model standards, each gallon of reformulated gasoline and RBOB 
designated as being VOC-controlled may not exceed the maximum standards 
for RVP specified in Sec. 80.41(b) which are applicable to that refiner 
or importer.
    (3) In the case of a refinery or importer subject to the complex 
model standards, each gallon of reformulated gasoline designated as 
being VOC-controlled must equal or exceed the minimum standards for VOC 
emissions performance specified in Sec. 80.41 which are applicable to 
that refinery or importer.
    (d) Toxics emissions reduction and benzene compliance on average. 
(1) The averaging period for the requirements for benzene content and 
toxics emission performance is January 1 through December 31 of each 
year.
    (2) The reformulated gasoline and RBOB produced at any refinery or 
imported by any importer during the toxics emissions performance and 
benzene averaging periods that is designated for average compliance for 
these parameters shall on average meet the standards specified for 
toxics emissions performance and benzene in Sec. 80.41 which are 
applicable to that refinery or importer.
    (3) Each gallon of reformulated gasoline may not exceed the maximum 
standard for benzene content specified in Sec. 80.41 which is 
applicable to that refinery or importer.
    (e) NOX compliance on average. (1) The averaging period 
for NOX emissions performance is January 1 through December 
31 of each year.
    (2) The requirements of this paragraph (e) apply separately to 
reformulated gasoline and RBOB in the following categories:
    (i) All reformulated gasoline and RBOB that is designated as VOC-
controlled; and
    (ii) All reformulated gasoline and RBOB that is not designated as 
VOC-controlled.
    (3) The reformulated gasoline and RBOB produced at any refinery or 
imported by any importer during the NOX averaging period that 
is designated for average compliance for NOX shall on average 
meet the standards for NOX specified in Sec. 80.41 that are 
applicable to that refinery or importer.
    (f) [Reserved]
    (g) Compliance calculation. To determine compliance with the 
averaged standards in Sec. 80.41, any refiner for each of its 
refineries at which averaged reformulated gasoline or RBOB is produced, 
and any importer that imports averaged reformulated gasoline or RBOB 
shall, for each averaging period and for each portion of gasoline for 
which standards must be separately achieved, and for each relevant 
standard, calculate:
    (1)(i)(A) The compliance total using the following formula:
    [GRAPHIC] [TIFF OMITTED] TR17JY01.000
    
Where:

Vi=the volume in gallons of gasoline batch i.
std=the standard for the parameter being evaluated.
n=the number of batches of gasoline produced or imported during the 
averaging period.

    (B) For computation of the VOC performance standard compliance 
total,

[[Page 699]]

Std for each VOC control region is determined by the following formula:
[GRAPHIC] [TIFF OMITTED] TR17JY01.001

Where, for gasoline and RBOB designated for that VOC control region:

Std=the value to be used in the compliance total formula.
Stdu=the averaged VOC emissions performance reduction 
standard applicable to reformulated gasoline and RBOB not designated for 
compliance with the adjusted VOC gasoline standard.
Stda=the averaged VOC emissions performance reduction 
standard applicable to reformulated gasoline and RBOB designated for 
compliance with the adjusted VOC gasoline standard.
VUi=the volume of batch i not designated for compliance with 
the adjusted VOC gasoline standard.
VAi=the volume of batch i designated for compliance with the 
adjusted VOC gasoline standard.
nu=the number of batches produced or imported and not 
designated for compliance with the adjusted VOC gasoline standard.
na=the number of batches produced or imported and designated 
for compliance with the adjusted VOC gasoline standard.

    (C) The actual total using the following formula:
    [GRAPHIC] [TIFF OMITTED] TR17JY01.002
    
Where:

Vi=the volume in gallons of gasoline batch i.
parmi=the parameter value of gasoline batch i.
n=the number of batches of gasoline produced or imported during the 
averaging period.

    (ii) [Reserved]
    (2) For each standard, compare the actual total with the compliance 
total.
    (3) For the VOC, NOX, and toxics emissions performance 
standards, the actual totals must be equal to or greater than the 
compliance totals to achieve compliance.
    (4) For RVP and benzene standards, the actual total must be equal to 
or less than the compliance totals to achieve compliance.
    (5) If the actual total for the benzene standard is greater than the 
compliance total, credits for this parameter must be obtained from 
another refiner or importer in order to achieve compliance:
    (i) [Reserved]
    (ii) The total number of benzene credits required to achieve 
compliance is calculated by subtracting the compliance total from the 
actual total benzene.
    (6) If the actual total for the benzene standard is less than the 
compliance totals, credits for this parameter are generated.
    (i) [Reserved]
    (ii) The total number of benzene credits which may be traded to 
another refinery or importer is calculated by subtracting the actual 
total from the compliance total for benzene.
    (7) In 2006 only, compliance with the oxygen standards in Sec. 
80.41 may be based on the volume and oxygen content of all reformulated 
gasoline produced or imported during the period January 1, 2006, through 
May 5, 2006 or the volume and oxygen content of all oxygenated 
reformulated gasoline produced or imported during the 2006 annual 
averaging period (January 1 through December 31).
    (h) Credit transfers. (1) Compliance with the averaged standards 
specified in Sec. 80.41 for benzene (but for no other standards or 
requirements) may be achieved through the transfer of benzene credits 
provided that:
    (i) The credits were generated in the same averaging period as they 
are used;
    (ii) The credit transfer takes place no later than fifteen working 
days following the end of the averaging period in which the reformulated 
gasoline credits were generated;
    (iii) The credits are properly created;
    (iv) The credits are transferred, either through inter-company or 
intra-company transfers, directly from the refiner or importer that 
creates the credits to the refiner or importer that uses the credits to 
achieve compliance; and
    (v) Benzene credits are not used to achieve compliance with the 
maximum benzene content standards in Sec. 80.41.

[[Page 700]]

    (2) No party may transfer any credits to the extent such a transfer 
would result in the transferor having a negative credit balance at the 
conclusion of the averaging period for which the credits were 
transferred. Any credits transferred in violation of this paragraph are 
improperly created credits.
    (3) In the case of credits that were improperly created, the 
following provisions apply:
    (i) Improperly created credits may not be used to achieve 
compliance, regardless of a credit transferee's good faith belief that 
it was receiving valid credits;
    (ii) No refiner or importer may create, report, or transfer 
improperly created credits; and
    (iii) Where any credit transferor has in its balance at the 
conclusion of any averaging period both credits which were properly 
created and credits which were improperly created, the properly created 
credits will be applied first to any credit transfers before the 
transferor may apply any credits to achieve its own compliance.
    (i) Average compliance for reformulated gasoline produced or 
imported before January 1, 1995. In the case of any reformulated 
gasoline that is intended to be used beginning January 1, 1995, but that 
is produced or imported prior to that date:
    (1) Any refiner or importer may meet standards specified in Sec. 
80.41 for average compliance for such gasoline, provided the refiner or 
importer has the option of meeting standards on average for 1995 under 
paragraph (a) of this section, and provided the refiner or importer 
elects to be subject to average standards under Sec. 80.65(c)(3); and
    (2) Any average compliance gasoline under paragraph (i)(1) of this 
section shall be combined with average compliance gasoline produced 
during 1995 for purposes of compliance calculations under paragraph (g) 
of this section.

[38 FR 1255, Jan. 10, 1973, as amended at 62 FR 60135, Nov. 6, 1997; 62 
FR 68207, Dec. 31, 1997; 66 FR 37165, July 17, 2001; 71 FR 74568, Dec. 
15, 2005; 71 FR 26699, May 8, 2006]



Sec. 80.68  Compliance surveys.

    (a)(1) Beginning January 1, 2007, the compliance surveys for 
NOX emissions performance under this section shall cease to 
be required.
    (2) Beginning January 1, 2011, the compliance surveys for toxics 
emissions performance under this section shall cease to be required.
    (b) Compliance survey option 1. In order to satisfy the compliance 
survey requirements, any refiner or importer shall properly conduct a 
program of compliance surveys in accordance with a survey program plan 
which has been approved by the Administrator of EPA in each covered area 
which is supplied with any gasoline for which compliance is achieved on 
average that is produced by that refinery or imported by that importer. 
Such approval shall be based upon the survey program plan meeting the 
following criteria:
    (1) The survey program shall consist of at least four surveys which 
shall occur during the following time periods: one survey during the 
period January 1 through May 31; two surveys during the period June 1 
through September 15; and one survey during the period September 16 
through December 31.
    (2) The survey program shall meet the criteria stated in paragraph 
(d) of this section.
    (3) In the event that any refiner or importer fails to properly 
carry out an approved survey program, the refiner or importer shall 
achieve compliance with all applicable standards on a per-gallon basis 
for the calendar year in which the failure occurs, and may not achieve 
compliance with any standard on an average basis during this calendar 
year. This requirement to achieve compliance per-gallon shall apply ab 
initio to the beginning of any calendar year in which the failure 
occurs, regardless of when during the year the failure occurs.
    (c) Compliance survey option 2. A refiner or importer shall be 
deemed to have satisfied the compliance survey requirements described in 
paragraph (b) of this section if a comprehensive program of surveys is 
properly conducted in accordance with a survey program plan which has 
been approved by the Administrator of EPA. Such approval shall be based 
upon the survey program plan meeting the following criteria:

[[Page 701]]

    (1) The initial schedule for the conduct of surveys shall be as 
follows:
    (i) 120 surveys shall be conducted in 1995;
    (ii) 80 surveys shall be conducted in 1996;
    (iii) 60 surveys shall be conducted in 1997;
    (iv) 70 surveys shall be conducted in 1998 and thereafter.
    (2) This initial survey schedule shall be adjusted as follows:
    (i) In the event one or more ozone nonattainment areas in addition 
to the nine specified in Sec. 80.70, opt into the reformulated gasoline 
program, the number of surveys to be conducted in the year the area or 
areas opt into the program and in each subsequent year shall be 
increased according to the following formula:
[GRAPHIC] [TIFF OMITTED] TR16FE94.009

where:

ANSi = the adjusted number of surveys for year i; i = the 
opt-in year and each subsequent year
NSi = the number of surveys according to the schedule in 
paragraph (c)(1) of this section in year i; i = the opt-in year and each 
subsequent year
Vopt-in = the total volume of gasoline supplied to the opt-in 
covered areas in the year preceding the year of the opt-in
Vorig = the total volume of gasoline supplied to the original 
nine covered areas in the year preceding the year of the opt-in

    (ii) In the event that any covered area(s) fails a survey or survey 
series according to the criteria set forth in paragraph (d) of this 
section, the annual decreases in the numbers of surveys prescribed by 
paragraph (c)(1) of this section, as adjusted by paragraph (c)(2)(i) of 
this section, shall be adjusted as follows in the year following the 
year of the failure. Any such adjustment to the number of surveys shall 
remain in effect so long as any standard for the affected covered area 
has been adjusted to be more stringent as a result of a failed survey or 
survey series. The adjustments shall be calculated according to the 
following formula:
[GRAPHIC] [TIFF OMITTED] TR16FE94.010

where:

ANSi = the adjusted number of surveys in year i; i = the year 
after the failure and each subsequent year
Vfailed = the total volume of gasoline supplied to the 
covered area which failed the survey or survey series in the year of the 
failure
Vtotal = the total volume of gasoline supplied to all covered 
areas in the year of the failure
NSi = the number of surveys in year i according to the 
schedule in paragraph (c)(1) of this section and as adjusted by 
paragraph (c)(2)(i) of this section; i = the year after the failure and 
each subsequent year

    (3) The survey program shall meet the criteria stated in paragraph 
(d) of this section.
    (4) On each occasion the comprehensive survey program does not occur 
as specified in the approved plan with regard to any covered area:
    (i) Each refiner or importer who supplied any reformulated gasoline 
or RBOB to the covered area and who has not satisfied the survey 
requirements described in paragraph (b) of this section shall be deemed 
to have failed to carry out an approved survey program; and
    (ii) The covered area will be deemed to have failed surveys for VOC 
and NOX emissions performance, and survey series for benzene 
and toxic and NOX emissions performance.
    (d) General survey requirements. (1) During the period January 1, 
1995 through December 31, 1997:
    (i) Any sample taken from a retail gasoline storage tank for which 
the

[[Page 702]]

three most recent deliveries were of gasoline designated as meeting:
    (A) Simple model standards shall be considered a ``simple model 
sample''; or
    (B) Complex model standards shall be considered a ``complex model 
sample.''
    (ii) A survey shall consist of the combination of a simple model 
portion and a complex model portion, as follows:
    (A) The simple model portion of a survey shall consist of all simple 
model samples that are collected pursuant to the applicable survey 
design in a single covered area during any consecutive seven-day period 
and that are not excluded under paragraph (d)(6) of this section.
    (B) The complex model portion of a survey shall consist of all 
complex model samples that are collected pursuant to the applicable 
survey design in a single covered area during any consecutive seven-day 
period and that are not excluded under paragraph (d)(6) of this section.
    (iii)(A) The simple model portion of each survey shall be 
representative of all gasoline certified using the simple model which is 
being dispensed in the covered area.
    (B) The complex model portion of each survey shall be representative 
of all gasoline certified using the complex model which is being 
dispensed in the covered area.
    (2) Beginning on January 1, 1998:
    (i) A survey shall consist of all samples that are collected 
pursuant to the applicable survey design in a single covered area during 
any consecutive seven-day period and that are not excluded under 
paragraph (d)(6) of this section.
    (ii) A survey shall be representative of all gasoline which is being 
dispensed in the covered area.
    (3)(i) A VOC survey and a NOX survey shall consist of any 
survey conducted during the period June 1 through September 15;
    (ii) A sample of gasoline taken at a retail outlet or wholesale 
purchaser-consumer facility that has within the past 30 days commingled 
ethanol blended reformulated gasoline with non-ethanol blended 
reformulated gasoline in accordance with the provisions in Sec. 
80.78(a)(8) shall not be used in a VOC survey required under this 
section.
    (4)(i) A toxics and benzene survey series shall consist of all 
surveys conducted in a single covered area during a single calendar 
year.
    (ii) A NOX survey series shall consist of all surveys 
conducted in a single covered area during the periods January 1 through 
May 31, and September 16 through December 31 during a single calendar 
year.
    (5)(i) Each simple model sample included in a survey shall be 
analyzed for oxygenate type and content, benzene content, aromatic 
hydrocarbon content, and RVP in accordance with the methodologies 
specified in Sec. 80.46; and
    (ii) Each complex model sample included in a survey shall be 
analyzed for oxygenate type and content, olefins, benzene, sulfur, and 
aromatic hydrocarbons, E-200, E-300, and RVP in accordance with the 
methodologies specified in Sec. 80.46.
    (6)(i) The results of each survey shall be based upon the results of 
the analysis of each sample collected during the course of the survey, 
unless the sample violates the applicable per-gallon maximum or minimum 
standards for the parameter being evaluated plus any enforcement 
tolerance that applies to the parameter (e.g., a sample that violates 
the benzene per-gallon maximum plus any benzene enforcement tolerance 
but meets other per-gallon maximum and minimum standards would be 
excluded from the benzene survey, but would be included in the surveys 
for parameters other than benzene).
    (ii) Any sample from a survey that violates any standard under Sec. 
80.41, or that constitutes evidence of the violation of any prohibition 
or requirement under this subpart D, may be used by the Administrator in 
an enforcement action for such violation.
    (7) Each laboratory at which samples in a survey are analyzed shall 
participate in a correlation program with EPA to ensure the validity of 
analysis results.
    (8)(i) The results of each simple model VOC survey shall be 
determined as follows:

[[Page 703]]

    (A) For each simple model sample from the survey, the VOC emissions 
reduction percentage shall be determined based upon the tested values 
for RVP and oxygen for that sample as applied to the VOC emissions 
reduction equation at Sec. 80.42(a)(1) for VOC-Control Region 1 and 
Sec. 80.42(a)(2) for VOC-Control Region 2;
    (B) The VOC emissions reduction survey standard applicable to each 
covered area shall be calculated by using the VOC emissions equation at 
Sec. 80.42(a)(1) with RVP = 7.2 and OXCON = 2.0 for covered areas 
located in VOC-Control Region 1 and using the VOC emissions equation at 
Sec. 80.42(a)(2) with RVP = 8.1 and OXCON = 2.0 for covered areas 
located in VOC-Control Region 2; and
    (C) The covered area shall have failed the simple model VOC survey 
if the VOC emissions reduction average of all survey samples is less 
than VOC emissions reduction survey standard calculated under paragraph 
(d)(8)(i)(B) of this section.
    (ii) The results of each complex model VOC emissions reduction 
survey shall be determined as follows:
    (A) For each complex model sample from the survey series, the VOC 
emissions reduction percentage shall be determined based upon the tested 
parameter values for that sample and the appropriate methodology for 
calculating VOC emissions reduction at Sec. 80.45;
    (B) The covered area shall have failed the complex model VOC survey 
if the VOC emissions reduction percentage average of all survey samples 
is less than the applicable per-gallon standard for VOC emissions 
reduction;
    (C) For adjusted VOC gasoline sold in the covered areas described at 
Sec. 80.70(f) and (i), the covered area shall have failed the complex 
model VOC survey if the VOC emissions reduction percentage average of 
all survey samples is less than the weighted average of the applicable 
per-gallon standards for VOC emissions reduction calculated according to 
the following formula:
[GRAPHIC] [TIFF OMITTED] TR17JY01.003

Where:

WSTD=Weighted average of the applicable per-gallon VOC standards.
VOCU=Per gallon VOC standard applicable in the covered area to RFG 
containing less than 10 percent ethanol by volume.
VOCA=Per gallon VOC standard applicable in the covered area to RFG 
containing 10 percent ethanol by volume.
nu=Number of samples in the VOC survey with oxygen content 
less than 3.5 percent by weight.
na=Number of samples in the VOC survey with oxygen content 
equal to or greater than 3.5 percent by weight.
n=Total number of samples in the VOC survey.

    (9)(i) The results of each simple model toxics emissions reduction 
survey series conducted in any covered area shall be determined as 
follows:
    (A) For each simple model sample from the survey series, the toxics 
emissions reduction percentage shall be determined based upon the tested 
parameter values for that sample and the appropriate methodology for 
calculating toxics emissions performance reduction at Sec. 80.42.
    (B) The annual average of the toxics emissions reduction percentages 
for all samples from a survey series shall be calculated according to 
the following formula \2\:
---------------------------------------------------------------------------

    \2\ The formula requires, first, that the toxic reductions of 
samples taken in each one-week survey be averaged to obtain an average 
for each such survey. Then these survey averages are, themselves, 
averaged separately for high-ozone and non-high-ozone season surveys, to 
obtain two overall averages. These overall averages are each to be 
multiplied by a seasonal weight (0.468 for high-ozone season and 0.532 
for non-high ozone season) and the resulting products added together to 
obtain the average annual toxic emission reduction.

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

[[Page 704]]

[GRAPHIC] [TIFF OMITTED] TR15DE05.010

Where:

AATER = the annual average toxics emissions reduction
TER1,j = the toxics emissions reduction for sample j of 
gasoline collected during the high ozone season
TER2,j = the toxics emissions reduction for sample j of 
gasoline collected outside the high ozone season
n1 = the number of gasoline samples collected during a one-
week survey conducted within the high ozone season
s1 = the number of one-week surveys conducted within the high 
ozone season
n2 = the number of gasoline samples collected during a one-
week survey conducted outside the high ozone season
s2 = the number of one-week surveys conducted outside of the 
high ozone season

    (C) The covered area shall have failed the simple model toxics 
survey series if the annual average toxics emissions reduction is less 
than the simple model per-gallon standard for toxics emissions 
reduction.
    (ii) The results of each complex model toxics emissions reduction 
survey series conducted in any covered area shall be determined as 
follows:
    (A) For each complex model sample from the survey series, the toxics 
emissions reduction percentage shall be determined based upon the tested 
parameter values for that sample and the appropriate methodology for 
calculating toxics emissions reduction at Sec. 80.45;
    (B) The annual average of the toxics emissions reduction percentages 
for a survey series shall be calculated according to the formula 
specified in paragraph (d)(9)(i)(B) of this section; and
    (C) The covered area shall have failed the complex model toxics 
survey series if the annual average toxics emissions reduction is less 
than the applicable per-gallon complex model standard for toxics 
emissions reduction.
    (10) The results of each NOX emissions reduction survey 
and survey series shall be determined as follows:
    (i) For each sample from the survey and survey series, the 
NOX emissions reduction percentage shall be determined based 
upon the tested parameter values for that sample and the appropriate 
methodology for calculating NOX emissions reduction at Sec. 
80.45; and
    (ii) The average NOX emission reduction percentage for 
each single week-long NOX survey shall be calculated as the 
average of all NOX emission reduction percentages from the 
survey.
    (iii) The covered area shall have failed a NOX survey if 
the average NOX emissions reduction percentage for all survey 
samples is less than the applicable Phase I or Phase II complex model 
per-gallon standard for NOX emissions reduction.
    (iv) The average NOX emission reduction percentage for a 
NOX survey series shall be calculated according to the 
following formula:
[GRAPHIC] [TIFF OMITTED] TR15DE05.011

Where:

ANER = the average NOX emission reduction percentage for a 
NOX survey series,

[[Page 705]]

n = the number of gasoline samples taken in the course of a week-long 
NOX survey,
NERj = the NOX emissions reduction percentage for 
gasoline sample j determined according to the appropriate methodology at 
Sec. 80.45, and
S = the number of week-long NOX surveys conducted during the 
NOX survey series period

    (v) The covered area shall have failed a NOX survey 
series if the average NOX emissions reduction percentage for 
the series, as computed in paragraph (d)(10)(iv) of this section, is 
less than the applicable Phase I or Phase II complex model per gallon 
standard for NOX emissions reduction.
    (11)(i) The results of each benzene content survey series conducted 
in any covered area shall be determined according to the following 
formula:
[GRAPHIC] [TIFF OMITTED] TR15DE05.012

Where:

AABC = the annual average benzene content for a benzene content survey 
series,
n = the number of gasoline samples taken in the course of a week-long 
benzene content survey,
BCj = the benzene content for gasoline sample j taken in the 
course of a week-long benzene content survey, and
S = the number of week-long benzene content surveys conducted during the 
year.

    (ii) If the annual average benzene content computed in paragraph 
(d)(11)(i) of this section is greater than 1.000 percent by volume, the 
covered area shall have failed a benzene content survey series.
    (12) [Reserved]
    (13) Each survey program shall:
    (i) Be planned and conducted by a person who is independent of the 
refiner or importer (the surveyor). In order to be considered 
independent:
    (A) The surveyor shall not be an employee of any refiner or 
importer;
    (B) The surveyor shall be free from any obligation to or interest in 
any refiner or importer; and
    (C) The refiner or importer shall be free from any obligation to or 
interest in the surveyor; and
    (ii) Include procedures for selecting sample collection locations, 
numbers of samples, and gasoline compositions which will result in:
    (A) Simple model surveys representing all gasoline certified using 
the simple model being dispensed at retail outlets within the covered 
area during the period of the survey; and
    (B) Complex model surveys representing all gasoline certified using 
the complex model being dispensed at retail outlets within the covered 
area during the period of the survey; and
    (iii) Include procedures such that the number of samples included in 
each survey or survey series (whichever is applicable) assures that:
    (A) In the case of simple model surveys or survey series, the 
average levels of oxygen, benzene, RVP, and aromatic hydrocarbons are 
determined with a 95% confidence level, with error of less than 0.1 psi 
for RVP, 0.05% for benzene (by volume), and 0.1% for oxygen (by weight); 
and
    (B) In the case of complex model surveys or survey series, the 
average levels of oxygen, benzene, RVP, aromatic hydrocarbons, olefins, 
T-50, T-90 and sulfur are determined with a 95% confidence level, with 
error of less than 0.1 psi for RVP, 0.05% for benzene (by volume), 0.1% 
for oxygen (by weight), 0.5% for olefins (by volume), 5 [deg]F. for T-50 
and T-90, and 10 ppm for sulfur; or an equivalent level of precision for 
the complex model-determined emissions parameters; and
    (iv) Require that the surveyor shall:
    (A) Not inform anyone, in advance, of the date or location for the 
conduct of any survey;
    (B) Upon request by EPA made within thirty days following the 
submission of the report of a survey, provide a duplicate of any 
gasoline sample taken during that survey to EPA at a location to be 
specified by EPA each sample to be identified by the name and address of 
the facility where collected, the date of collection, and the 
classification of the sample as simple model or complex model; and

[[Page 706]]

    (C) At any time permit any representative of EPA to monitor the 
conduct of the survey, including sample collection, transportation, 
storage, and analysis; and
    (v) Require the surveyor to submit to EPA a report of each survey, 
within thirty days following completion of the survey, such report to 
include the following information:
    (A) The identification of the person who conducted the survey;
    (B) An attestation by an officer of the surveyor company that the 
survey was conducted in accordance with the survey plan and that the 
survey results are accurate;
    (C) If the survey was conducted for one refiner or importer, the 
identification of that party;
    (D) The identification of the covered area surveyed;
    (E) The dates on which the survey was conducted;
    (F) The address of each facility at which a gasoline sample was 
collected, the date of collection, and the classification of the sample 
as simple model or complex model;
    (G) The results of the analyses of simple model samples for 
oxygenate type and oxygen weight percent, benzene content, aromatic 
hydrocarbon content, and RVP, the calculated toxics emission reduction 
percentage, and for each survey conducted during the period June 1 
through September 15 the VOC emissions reduction percentage calculated 
using the methodology specified in paragraph (d)(8)(i) of this section;
    (H) The results of the analyses of complex model samples for 
oxygenate type and oxygen weight percent, benzene, aromatic hydrocarbon, 
and olefin content, E-200, E-300, and RVP, the calculated NOX 
and toxics emissions reduction percentage, and for each survey conducted 
during the period June 1 through September 15, the calculated VOC 
emissions reduction percentage;
    (I) The name and address of each laboratory where gasoline samples 
were analyzed;
    (J) A description of the methodology utilized to select the 
locations for sample collection and the numbers of samples collected;
    (K) For any samples which were excluded from the survey, a 
justification for such exclusion; and
    (L) The average toxics emissions reduction percentage for simple 
model samples and the percentage for complex model samples, the average 
benzene percentage, and for each survey conducted during the period June 
1 through September 15, the average VOC emissions reduction percentage 
for simple model samples and the percentage for complex model samples, 
and the average NOX emissions reduction percentage for all 
complex model samples;
    (14) Each survey shall be conducted at a time and in a covered area 
selected by EPA no earlier than two weeks before the date of the survey.
    (15) The procedure for seeking EPA approval for a survey program 
plan shall be as follows:
    (i) The survey program plan shall be submitted to the Administrator 
of EPA for EPA's approval no later than September 1 of the year 
preceding the year in which the surveys will be conducted; and
    (ii) Such submittal shall be signed by a responsible corporate 
officer of the refiner, importer, or oxygenate blender, or in the case 
of a comprehensive survey program plan, by an officer of the 
organization coordinating the survey program.
    (16)(i) No later than December 1 of the year preceding the year in 
which the surveys will be conducted, the contract with the surveyor to 
carry out the entire survey plan shall be in effect, and an amount of 
money necessary to carry out the entire survey plan shall be paid to the 
surveyor or placed into an escrow account with instructions to the 
escrow agent to pay the money over to the surveyor during the course of 
the conduct of the survey plan.
    (ii) No later than December 15 of the year preceding the year in 
which the surveys will be conducted, the Administrator of EPA shall be 
given a copy of the contract with the surveyor, proof that the money 
necessary to carry out the plan has either been paid to the

[[Page 707]]

surveyor or placed into an escrow account, and if placed into an escrow 
account, a copy of the escrow agreement.

[59 FR 7813, Feb. 16, 1994, as amended at 59 FR 36963, July 20, 1994; 62 
FR 12576, Mar. 17, 1997; 62 FR 68207, Dec. 31, 1997; 66 FR 37165, July 
17, 2001; 71 FR 74568, Dec. 15, 2005; 71 FR 26699, May 8, 2006; 72 FR 
8543, Feb. 26, 2007]



Sec. 80.69  Requirements for downstream oxygenate blending.

    The requirements of this section apply to all reformulated gasoline 
blendstock for oxygenate blending, or RBOB, to which oxygenate is added 
at any oxygenate blending facility, except that paragraph (a)(7) of this 
section does not apply to adjusted VOC gasoline as defined in Sec. 
80.40(c).
    (a) Requirements for refiners and importers. For any RBOB produced 
or imported, the refiner or importer of the RBOB shall:
    (1) Produce or import the RBOB such that, when blended with a 
specified type and percentage of oxygenate, it meets the applicable 
standards for reformulated gasoline;
    (2) In order to determine the properties of RBOB for purposes of 
calculating compliance with per-gallon or averaged standards, conduct 
tests on each batch of the RBOB by:
    (i) Adding the specified type and amount of oxygenate to a 
representative sample of the RBOB; and
    (ii) Determining the properties and characteristics of the resulting 
gasoline using the methodology specified in Sec. 80.65(e);
    (3) Carry out the independent analysis requirements specified in 
Sec. 80.65(f);
    (4) [Reserved]
    (5) Transfer ownership of the RBOB only to an oxygenate blender who 
is registered with EPA as such, or to an intermediate owner with the 
restriction that it only be transferred to a registered oxygenate 
blender;
    (6) Have a contract with each oxygenate blender who receives any 
RBOB produced or imported by the refiner or importer that requires the 
oxygenate blender, or, in the case of a contract with an intermediate 
owner, that requires the intermediate owner to require the oxygenate 
blender to:
    (i) Comply with blender procedures that are specified by the 
contract and are calculated to assure blending with the proper type and 
amount of oxygenate;
    (ii) Allow the refiner or importer to conduct the quality assurance 
sampling and testing required under this paragraph (a); and
    (iii) Stop selling any gasoline found not to comply with the 
standards under which the RBOB was produced or imported.
    (7) Conduct a quality assurance sampling and testing program to be 
carried out at the facilities of each oxygenate blender who blends any 
RBOB produced or imported by the refiner or importer with any oxygenate, 
to determine whether the reformulated gasoline which has been produced 
through blending complies with the applicable standards, using the 
methodology specified in Sec. 80.46 for this determination.
    (i) The sampling and testing program shall be conducted as follows:
    (A) All samples shall be collected subsequent to the addition of 
oxygenate, and either:
    (1) Prior combining the resulting gasoline with any other gasoline; 
or
    (2) In the case of truck splash blending, subsequent to the delivery 
of the gasoline to a retail outlet or wholesale purchaser-consumer 
facility provided that the three most recent deliveries to the retail 
outlet or wholesale purchaser facility were of gasoline produced using 
that refiner's or importer's RBOB, and provided that any discrepancy 
found through the retail outlet or wholesale purchaser facility sampling 
is followed-up with measures reasonably designed to discover the cause 
of the discrepancy; and
    (B) Sampling and testing shall be at one of the following rates:
    (1) In the case of RBOB which is blended with oxygenate in a 
gasoline storage tank, a rate of not less than one sample for every 
400,000 barrels of RBOB produced or imported by that refiner or importer 
that is blended by that blender, or one sample every month, whichever is 
more frequent; or
    (2) In the case of RBOB which is blended with oxygenate in gasoline 
delivery trucks through the use of computer-controlled in-line blending 
equipment, a rate of not less than one sample for every 200,000 barrels 
of RBOB

[[Page 708]]

produced or imported by that refiner or importer that is blended by that 
blender, or one sample every three months, whichever is more frequent; 
or
    (3) In the case of RBOB which is blended with oxygenate in gasoline 
delivery trucks without the use of computer-controlled in-line blending 
equipment, a rate of not less than one sample for each 50,000 barrels of 
RBOB produced or imported by that refiner or importer which is blended, 
or one sample per month, whichever is more frequent;
    (ii) In the event the test results for any sample indicate the 
gasoline does not comply with applicable standards (within the 
correlation ranges specified in Sec. 80.65(e)(2)(i)), the refiner or 
importer shall:
    (A) Immediately take steps to stop the sale of the gasoline that was 
sampled;
    (B) Take steps which are reasonably calculated to determine the 
cause of the noncompliance and to prevent future instances of 
noncompliance;
    (C) Increase the rate of sampling and testing to one of the 
following rates:
    (1) In the case of RBOB which is blended with oxygenate in a 
gasoline storage tank, a rate of not less than one sample for every 
200,000 barrels of RBOB produced or imported by that refiner or importer 
that is blended by that blender, or one sample every two weeks, 
whichever is more frequent; or
    (2) In the case of RBOB which is blended with oxygenate in gasoline 
delivery trucks through the use of computer-controlled in-line blending 
equipment, a rate of not less than one sample for every 100,000 barrels 
of RBOB produced or imported by that refiner or importer that is blended 
by that blender, or one sample every two months, whichever is more 
frequent; or
    (3) In the case of RBOB which is blended with oxygenate in gasoline 
delivery trucks without the use of computer-controlled in-line blending 
equipment, a rate of not less than one sample for each 25,000 barrels of 
RBOB produced or imported by that refiner or importer which is blended, 
or one sample every two weeks, whichever is more frequent;
    (D) Continue the increased frequency of sampling and testing until 
the results of ten consecutive samples and tests indicate the gasoline 
complies with applicable standards, at which time the sampling and 
testing may be conducted at the original frequency;
    (iii) This quality assurance program is in addition to any quality 
assurance requirements carried out by other parties;
    (8)-(9) [Reserved]
    (10) Specify in the product transfer documentation for the RBOB each 
oxygenate type or types and amount or range of amounts which, if blended 
with the RBOB will result in reformulated gasoline which:
    (i) Has VOC, toxics, or NOX emissions reduction 
percentages which are no lower than the percentages that formed the 
basis for the refiner's or importer's compliance determination for these 
parameters;
    (ii) Has a benzene content and RVP level which are no higher than 
the values for these characteristics that formed the basis for the 
refiner's or importer's compliance determinations for these parameters; 
and
    (iii) Will not cause the reformulated gasoline to violate any 
standard specified in Sec. 80.41.
    (11) Any refiner or importer who produces or imports RBOB may comply 
with the following alternative quality assurance requirement instead of 
the contract and quality assurance sampling and testing requirements in 
paragraphs (a)(6) and (a)(7) of this section:
    (i) To comply with the alternative quality assurance requirement 
under this paragraph (a)(11), a refiner or importer must either arrange 
to have an independent surveyor conduct a comprehensive program of 
annual compliance surveys, or participate in the funding of an 
organization which arranges to have an independent surveyor conduct a 
comprehensive program of annual compliance surveys, to be carried out in 
accordance with a survey plan which has been approved by EPA.
    (ii) The annual compliance surveys under this paragraph (a)(11) 
shall be:
    (A) Planned and conducted by an independent surveyor that meets the 
requirements in Sec. 80.68(c)(13)(i);

[[Page 709]]

    (B) Conducted at retail gasoline outlets in a specified reformulated 
gasoline covered area;
    (C) Representative of all reformulated gasoline being dispensed in 
the specified reformulated gasoline covered area; and
    (D) Designed to achieve at least the same level of quality assurance 
required under paragraph (a)(7) of this section.
    (iii) The compliance survey program shall require the independent 
surveyor conducting the surveys to:
    (A) Obtain gasoline samples in accordance with the survey plan 
approved under this paragraph (a)(11), or immediately notify EPA of any 
refusal of retail outlets to allow samples to be taken;
    (B) Test or arrange for the samples to be tested for type and amount 
of oxygenate;
    (C)(1) Obtain the product transfer documents associated with the 
gasoline sample from the retail outlet; or immediately notify EPA of any 
refusal of any party to provide product transfer documents that should 
be within their possession; and
    (2) Immediately notify EPA of any case where the product transfer 
documents obtained from the retail outlet do not contain the information 
required in paragraph (a)(11)(vii)(A) of this section, or any case where 
the gasoline does not contain the type and/or minimum amount of 
oxygenate stated on the product transfer documents;
    (D) Where the test results indicate that the gasoline does not 
contain the type and/or minimum amount of oxygenate stated on the 
product transfer documents:
    (1) Determine the oxygenate blending facility that supplied the 
gasoline; and
    (2) Obtain from the oxygenate blender documentation of the refiner's 
or importer's oxygenate blending instructions for the gasoline;
    (E) Immediately notify EPA of any case where the test results 
obtained by the independent surveyor indicate that the gasoline does not 
contain the type and/or minimum amount of oxygenate designated for the 
RBOB in the refiner's or importer's blending instructions;
    (F) Immediately notify EPA of any instances where a refiner, 
importer, terminal, distributor, carrier or retail outlet fails to 
cooperate in the manner described in paragraph (a)(11)(vi) of this 
section.
    (G) Submit to EPA a report of each survey, within thirty days 
following completion of the survey, such report to include the following 
information:
    (1) The identification of the person who conducted the survey;
    (2) An attestation by an officer of the surveyor company that the 
survey was conducted in accordance with the survey plan and that the 
survey results are accurate;
    (3) Identification of the party(ies) for whom the survey was 
conducted;
    (4) The identification of the covered area surveyed;
    (5) The dates on which the survey was conducted;
    (6) The address of each facility at which a gasoline sample was 
collected and the date of collection;
    (7) The results of the analyses of the samples for type and amount 
of oxygenate;
    (8) The name and address of each laboratory where the gasoline 
samples were analyzed;
    (9) A description of the methodology utilized to select the 
locations for sample collection and the number of samples collected; and
    (10) For any samples excluded from the survey, a justification for 
such exclusion.
    (H) Maintain all records relating to the surveys conducted under 
this paragraph (a)(11) for a period of at least 5 years; and
    (I) At any time permit any representative of EPA to monitor the 
conduct of the surveys, including sample collection, transportation, 
storage, and analysis.
    (iv) A survey plan under this paragraph (a)(11) must include:
    (A) Identification of the party(ies) for whom the survey is to be 
conducted;
    (B) Identification of the independent surveyor;
    (C) A methodology for determining:
    (1) When the samples will be collected;

[[Page 710]]

    (2) The sample collection locations; and
    (3) The number of samples to be collected during the annual 
compliance period;
    (D) A process for notifying oxygenate blenders and other downstream 
parties in the affected RFG area of the product transfer documentation 
requirements in paragraph (a)(11)(vii)(A) of this section; and
    (E) Any other elements determined by EPA to be necessary to achieve 
the level of quality assurance required under paragraph (a)(11)(ii)(D) 
of this section.
    (v) Any sampling and testing pursuant to a survey plan under this 
paragraph (a)(11) must be conducted in a manner consistent with the 
applicable provisions of Sec. Sec. 80.8 and 80.46.
    (vi)(A) Each refiner and importer who participates in the 
alternative quality assurance program under this paragraph (a)(11) must 
take all reasonable steps to ensure that each oxygenate blender, 
distributor, carrier and retail outlet cooperates in this program by 
allowing the independent surveyor to collect samples and by providing to 
the independent surveyor and/or EPA, upon request, copies of product 
transfer documents and other records or information regarding the source 
of any gasoline received, the destination of any gasoline distributed, 
the oxygenate blending instructions for the RBOB, and the rate (volume 
%) that oxygenate was blended into the gasoline.
    (B) Reasonable steps under paragraph (a)(11)(vii) of this section 
must include, but typically should not be limited to, contractual 
agreements with any branded facilities of the refiner or importer, 
including any terminals, distributors, carriers and retail outlets, 
which require the branded facility to cooperate with the independent 
surveyor and/or EPA in the manner described in paragraph (a)(11)(vii)(A) 
of this section.
    (vii)(A) Any terminal that blends oxygenate with RBOB which is 
produced or imported by any refiner or importer that complies with the 
alternative quality assurance requirement under this paragraph (a)(11), 
and any parties downstream from such oxygenate blending terminal, must 
include on product transfer documents information regarding the type and 
amount of oxygenate contained in the gasoline and identification of the 
oxygenate blending facility that blended the gasoline.
    (B) If a party downstream from a refiner or importer that complies 
with the alternative quality assurance requirement under this paragraph 
(a)(11) fails to receive notice of the requirements in paragraph 
(a)(11)(vii)(A) of this section, upon notification from EPA, the party 
must thereafter comply with the requirements in paragraph 
(a)(11)(vii)(A) of this section.
    (viii) The procedure for obtaining EPA approval of a survey plan 
under this paragraph (a)(11), and for revocation of any such approval, 
are as follows:
    (A) A detailed survey plan which complies with the requirements of 
this paragraph (a)(11) must be submitted to EPA, no later than September 
1 of the year preceding the calendar year in which the surveys will be 
conducted;
    (B) The survey plan must be signed by a responsible corporate 
officer of the refiner or importer, or responsible officer of the 
organization which arranges to have an independent surveyor conduct a 
program of compliance surveys, as applicable; and
    (C) The survey plan must be sent to the following address: Director, 
Transportation and Regional Programs Division, U.S. Environmental 
Protection Agency, 1200 Pennsylvania Ave., NW., (6406J), Washington, DC 
20460;
    (D) EPA will send a letter to the party submitting a survey plan 
under this section, either approving or disapproving the survey plan;
    (E) EPA may revoke any approval of a survey plan under this section 
for cause, including an EPA determination that the approved survey plan 
has proved to be inadequate in practice or that it was not diligently 
implemented;
    (F) The approving official for an alternative quality assurance 
program under this section is the Director of the Transportation and 
Regional Programs Division, Office of Transportation and Air Quality.
    (G) Any notifications required under this paragraph (a)(11) must be 
directed

[[Page 711]]

to the official designated in paragraph (a)(11)(viii)(F) of this 
section.
    (ix)(A) No later than December 1 of the year preceding the year in 
which the surveys will be conducted, the contract with the independent 
surveyor shall be in effect, and an amount of money necessary to carry 
out the entire survey plan shall be paid to the independent surveyor or 
placed into an escrow account with instructions to the escrow agent to 
pay the money to the independent surveyor during the course of the 
conduct of the survey plan;
    (B) No later than December 15 of the year preceding the year in 
which the surveys will be conducted, EPA must receive a copy of the 
contract with the independent surveyor, proof that the money necessary 
to carry out the survey plan has either been paid to the independent 
surveyor or placed into an escrow account, and, if placed into an escrow 
account, a copy of the escrow agreement, to be sent to the official 
designated in paragraph (a)(11)(viii)(F) of this section.
    (x) A failure of any refiner or importer to fulfill or cause to be 
fulfilled any of the requirements of this paragraph (a)(11) will cause 
the option to use the alternative quality assurance requirements under 
this paragraph (a)(11) to be void ab initio.
    (b) Requirements for oxygenate blenders. For all RBOB received by 
any oxygenate blender, the oxygenate blender shall:
    (1) Add oxygenate of the type(s) and amount (or within the range of 
amounts) specified in the product transfer documents for the RBOB; and
    (2) Meet the recordkeeping requirements specified in Sec. 80.74.
    (c) [Reserved]
    (d) Requirements for distributors dispensing RBOB into trucks for 
blending. Any distributor who dispenses any RBOB into any truck which 
delivers gasoline to retail outlets or wholesale purchase-consumer 
facilities, shall for such RBOB so dispensed:
    (1) Transfer the RBOB only to an oxygenate blender who has 
registered with the Administrator or EPA as such; and
    (2) Obtain from the oxygenate blender the oxygenate blender's EPA 
registration number.
    (e) Additional requirements for oxygenate blenders who blend 
oxygenate in trucks. Any oxygenate blender who obtains any RBOB in any 
gasoline delivery truck shall on each occasion it obtains RBOB from a 
distributor, supply the distributor with the oxygenate blender's EPA 
registration number.

[59 FR 7813, Feb. 16, 1994, as amended at 59 FR 36964, July 20, 1994; 62 
FR 60135, Nov. 6, 1997; 66 FR 37165, July 17, 2001; 71 FR 74569, Dec. 
15, 2005; 71 FR 26700, May 8, 2006; 71 FR 31959, June 2, 2006]



Sec. 80.70  Covered areas.

    For purposes of subparts D, E, and F of this part, the covered areas 
are as follows:
    (a) The Los Angeles-Anaheim-Riverside, California, area, comprised 
of:
    (1) Los Angeles County;
    (2) Orange County;
    (3) Ventura County;
    (4) That portion of San Bernadino County that lies south of latitude 
35 degrees, 10 minutes north and west of longitude 115 degrees, 45 
minutes west; and
    (5) That portion of Riverside County, which lies to the west of a 
line described as follows:
    (i) Beginning at the northeast corner of Section 4, Township 2 
South, Range 5 East, a point on the boundary line common to Riverside 
and San Bernadino Counties;
    (ii) Then southerly along section lines to the centerline of the 
Colorado River Aqueduct;
    (iii) Then southeasterly along the centerline of said Colorado River 
Aqueduct to the southerly line of Section 36, Township 3 South, Range 7 
East;
    (iv) Then easterly along the township line to the northeast corner 
of Section 6, Township 4 South, Range 9 East;
    (v) Then southerly along the easterly line of Section 6 to the 
southeast corner thereof;
    (vi) Then easterly along section lines to the northeast corner of 
Section 10, Township 4 South, Range 9 East;
    (vii) Then southerly along section lines to the southeast corner of 
Section 15, Township 4 South, Range 9 East;

[[Page 712]]

    (viii) Then easterly along the section lines to the northeast corner 
of Section 21, Township 4 South, Range 10 East;
    (ix) Then southerly along the easterly line of Section 21 to the 
southeast corner thereof;
    (x) Then easterly along the northerly line of Section 27 to the 
northeast corner thereof;
    (xi) Then southerly along section lines to the southeast corner of 
Section 34, Township 4 South, Range 10 East;
    (xii) Then easterly along the township line to the northeast corner 
of Section 2, Township 5 South, Range 10 East;
    (xiii) Then southerly along the easterly line of Section 2, to the 
southeast corner thereof;
    (xiv) Then easterly along the northerly line of Section 12 to the 
northeast corner thereof;
    (xv) Then southerly along the range line to the southwest corner of 
Section 18, Township 5 South, Range 11 East;
    (xvi) Then easterly along section lines to the northeast corner of 
Section 24, Township 5 South, Range 11 East; and
    (xvii) Then southerly along the range line to the southeast corner 
of Section 36, Township 8 South, Range 11 East, a point on the boundary 
line common to Riverside and San Diego Counties.
    (b) San Diego County, California.
    (c) The Greater Connecticut area, comprised of:
    (1) The following Connecticut counties:
    (i) Hartford;
    (ii) Middlesex;
    (iii) New Haven;
    (iv) New London;
    (v) Tolland;
    (vi) Windham; and
    (2) Portions of certain Connecticut counties, described as follows:
    (i) In Fairfield County, the City of Shelton; and
    (ii) In Litchfield County, all cities and townships except the towns 
of Bridgewater and New Milford.
    (d) The New York-Northern New Jersey-Long Island-Connecticut area, 
comprised of:
    (1) Portions of certain Connecticut counties, described as follows:
    (i) In Fairfield County, all cities and townships except Shelton 
City;
    (ii) In Litchfield County, the towns of Bridgewater and New Milford;
    (2) The following New Jersey counties:
    (i) Bergen;
    (ii) Essex;
    (iii) Hudson;
    (iv) Hunterdon;
    (v) Middlesex;
    (vi) Monmouth;
    (vii) Morris;
    (viii) Ocean;
    (ix) Passaic;
    (x) Somerset;
    (xi) Sussex;
    (xii) Union; and
    (3) The following New York counties:
    (i) Bronx;
    (ii) Kings;
    (iii) Nassau;
    (iv) New York (Manhattan);
    (v) Queens;
    (vi) Richmond;
    (vii) Rockland;
    (viii) Suffolk;
    (ix) Westchester;
    (x) Orange; and
    (xi) Putnam.
    (e) The Philadelphia-Wilmington-Trenton area, comprised of:
    (1) The following Delaware counties:
    (i) New Castle; and
    (ii) Kent;
    (2) Cecil County, Maryland;
    (3) The following New Jersey counties:
    (i) Burlington;
    (ii) Camden;
    (iii) Cumberland;
    (iv) Gloucester;
    (v) Mercer;
    (vi) Salem; and
    (4) The following Pennsylvania counties:
    (i) Bucks;
    (ii) Chester;
    (iii) Delaware;
    (iv) Montgomery; and
    (v) Philadelphia.
    (f) The Chicago-Gary-Lake County, Illinois-Indiana-Wisconsin area, 
comprised of:
    (1) The following Illinois counties:
    (i) Cook;
    (ii) Du Page;
    (iii) Kane;
    (iv) Lake;
    (v) McHenry;
    (vi) Will;

[[Page 713]]

    (2) Portions of certain Illinois counties, described as follows:
    (i) In Grundy County, the townships of Aux Sable and Goose Lake; and
    (ii) In Kendall County, Oswego township; and
    (3) The following Indiana counties:
    (i) Lake; and
    (ii) Porter.
    (g) The Baltimore, Maryland area, comprised of:
    (1) The following Maryland counties:
    (i) Anne Arundel;
    (ii) Baltimore;
    (iii) Carroll;
    (iv) Harford;
    (v) Howard; and
    (2) The City of Baltimore.
    (h) The Houston-Galveston-Brazoria, Texas area, comprised of the 
following Texas counties:
    (1) Brazoria;
    (2) Fort Bend;
    (3) Galveston;
    (4) Harris;
    (5) Liberty;
    (6) Montgomery;
    (7) Waller; and
    (8) Chambers.
    (i) The Milwaukee-Racine, Wisconsin area, comprised of the following 
Wisconsin counties:
    (1) Kenosha;
    (2) Milwaukee;
    (3) Ozaukee;
    (4) Racine;
    (5) Washington; and
    (6) Waukesha.
    (j) Any other area classified under 40 CFR part 81, subpart C as a 
marginal, moderate, serious, or severe ozone nonattainment area may be 
included as a covered area on petition of the Governor of the State in 
which the area is located. The ozone nonattainment areas listed in this 
paragraph (j) opted into the reformulated gasoline program prior to the 
start of the reformulated gasoline program. These areas are covered 
areas for purposes of subparts D, E, and F of this part. The geographic 
extent of each covered area listed in this paragraph (j) shall be the 
nonattainment area boundaries as specified in 40 CFR part 81, subpart C.
    (1) Sussex County, Delaware;
    (2) District of Columbia portion of the Washington ozone 
nonattainment area;
    (3) The following Kentucky counties:
    (i) Boone;
    (ii) Campbell;
    (iii) Jefferson; and
    (iv) Kenton;
    (4) Portions of the following Kentucky counties:
    (i) Portion of Bullitt County described as follows:
    (A) Beginning at the intersection of Ky 1020 and the Jefferson-
Bullitt County Line proceeding to the east along the county line to the 
intersection of county road 567 and the Jefferson-Bullitt County Line;
    (B) Proceeding south on county road 567 to the junction with Ky 1116 
(also known as Zoneton Road);
    (C) Proceeding to the south on KY 1116 to the junction with Hebron 
Lane;
    (D) Proceeding to the south on Hebron Lane to Cedar Creek;
    (E) Proceeding south on Cedar Creek to the confluence of Floyds Fork 
turning southeast along a creek that meets Ky 44 at Stallings Cemetery;
    (F) Proceeding west along Ky 44 to the eastern most point in the 
Shepherdsville city limits;
    (G) Proceeding south along the Shepherdsville city limits to the 
Salt River and west to a point across the river from Mooney Lane;
    (H) Proceeding south along Mooney Lane to the junction of Ky 480;
    (I) Proceeding west on Ky 480 to the junction with Ky 2237;
    (J) Proceeding south on Ky 2237 to the junction with Ky 61 and 
proceeding north on Ky 61 to the junction with Ky 1494;
    (K) Proceeding south on Ky 1494 to the junction with the perimeter 
of the Fort Knox Military Reservation;
    (L) Proceeding north along the military reservation perimeter to 
Castleman Branch Road;
    (M) Proceeding north on Castleman Branch Road to Ky 44;
    (N) Proceeding a very short distance west on Ky 44 to a junction 
with Ky 1020; and
    (O) Proceeding north on Ky 1020 to the beginning.
    (ii) Portion of Oldham County described as follows:
    (A) Beginning at the intersection of the Oldham-Jefferson County 
Line

[[Page 714]]

with the southbound lane of Interstate 71;
    (B) Proceeding to the northeast along the southbound lane of 
Interstate 71 to the intersection of Ky 329 and the southbound lane of 
Interstate 71;
    (C) Proceeding to the northwest on Ky 329 to the intersection of 
Zaring Road on Ky 329;
    (D) Proceeding to the east-northeast on Zaring Road to the junction 
of Cedar Point Road and Zaring Road;
    (E) Proceeding to the north-northeast on Cedar Point Road to the 
junction of Ky 393 and Cedar Point Road;
    (F) Proceeding to the south-southeast on Ky 393 to the junction of 
county road 746 (the road on the north side of Reformatory Lake and the 
Reformatory);
    (G) Proceeding to the east-northeast on county road 746 to the 
junction with Dawkins Lane (also known as Saddlers Mill Road) and county 
road 746;
    (H) Proceeding to follow an electric power line east-northeast 
across from the junction of county road 746 and Dawkins Lane to the 
east-northeast across Ky 53 on to the La Grange Water Filtration Plant;
    (I) Proceeding on to the east-southeast along the power line then 
south across Fort Pickens Road to a power substation on Ky 146;
    (J) Proceeding along the power line south across Ky 146 and the 
Seaboard System Railroad track to adjoin the incorporated city limits of 
La Grange;
    (K) Then proceeding east then south along the La Grange city limits 
to a point abutting the north side of Ky 712;
    (L) Proceeding east-southeast on Ky 712 to the junction of Massie 
School Road and Ky 712;
    (M) Proceeding to the south-southwest and then north-northwest on 
Massie School Road to the junction of Ky 53 and Massie School Road;
    (N) Proceeding on Ky 53 to the north-northwest to the junction of 
Moody Lane and Ky 53;
    (O) Proceeding on Moody Lane to the south-southwest until meeting 
the city limits of La Grange;
    (P) Then briefly proceeding north following the La Grange city 
limits to the intersection of the northbound lane of Interstate 71 and 
the La Grange city limits;
    (Q) Proceeding southwest on the northbound lane of Interstate 71 
until intersecting with the North Fork of Currys Fork;
    (R) Proceeding south-southwest beyond the confluence of Currys Fork 
to the south-southwest beyond the confluence of Floyds Fork continuing 
on to the Oldham-Jefferson County Line; and
    (S) Proceeding northwest along the Oldham-Jefferson County Line to 
the beginning.
    (5) [Reserved]
    (6) The following Maryland counties:
    (i) Calvert;
    (ii) Charles;
    (iii) Frederick;
    (iv) Montgomery;
    (v) Prince Georges;
    (vi) Queen Anne's; and
    (vii) Kent;
    (7) The entire State of Massachusetts;
    (8) The following New Hampshire counties:
    (i) Strafford;
    (ii) Merrimack;
    (iii) Hillsborough; and
    (iv) Rockingham;
    (9) The following New Jersey counties:
    (i) Atlantic;
    (ii) Cape May; and
    (iii) Warren;
    (10) The following New York counties:
    (i) Dutchess;
    (ii) The portion of Essex County that consists of the portion of 
Whiteface Mountain above 4,500 feet in elevation.
    (11) The entire State of Rhode Island;
    (12) The following Texas counties: and
    (i) Collin;
    (ii) Dallas;
    (iii) Denton; and
    (iv) Tarrant;
    (13) The following Virginia areas:
    (i) Alexandria;
    (ii) Arlington County;
    (iii) Fairfax;
    (iv) Fairfax County;
    (v) Falls Church;
    (vi) Loudoun County;
    (vii) Manassas;
    (viii) Manassas Park;
    (ix) Prince William County;
    (x) Stafford County;

[[Page 715]]

    (xi) Charles City County;
    (xii) Chesterfield County;
    (xiii) Colonial Heights;
    (xiv) Hanover County;
    (xv) Henrico County;
    (xvi) Hopewell;
    (xvii) Richmond;
    (xviii) Chesapeake;
    (xix) Hampton;
    (xx) James City County;
    (xxi) Newport News;
    (xxii) Norfolk;
    (xxiii) Poquoson;
    (xxiv) Portsmouth;
    (xxv) Suffolk;
    (xxvi) Virginia Beach;
    (xxvii) Williamsburg; and
    (xxviii) York County.
    (k) The ozone nonattainment areas included in this paragraph (k) 
have opted into the reformulated gasoline program since the beginning of 
the program, and are covered areas for purposes of subparts D, E, and F 
of this part. The geographic extent of each covered area listed in this 
paragraph (k) shall be the nonattainment area boundaries as specified in 
40 CFR part 81, subpart C.
    (1) The St. Louis, Missouri, ozone nonattainment area is a covered 
area beginning June 1, 1999. The prohibitions of section 211(k)(5) of 
the Clean Air Act apply to all persons in the St. Louis, Missouri, 
covered area, other than retailers and wholesale purchaser-consumers, 
beginning May 1, 1999. The prohibitions of section 211(k)(5) of the 
Clean Air Act apply to retailers and wholesale purchase-consumers in the 
St. Louis, Missouri, area beginning June 1, 1999.
    (2) The Illinois portion of the St. Louis, Illinois-Missouri ozone 
nonattainment area is a covered area beginning on July 1, 2007. The 
prohibitions of section 211(k)(5) of the Clean Air Act apply to all 
persons other than retailers and wholesale purchaser-consumers in the 
Illinois portion of the St. Louis, Illinois-Missouri ozone nonattainment 
area beginning on June 1, 2007. The prohibitions of section 211(k)(5) of 
the Clean Air Act apply to retailers and wholesale purchaser-consumers 
in the Illinois portion of the St. Louis, Illinois-Missouri ozone 
nonattainment area beginning July 1, 2007.
    (l) Upon the effective date for removal of any opt-in area or 
portion of an opt-in area included in an approved petition under Sec. 
80.72(a), the geographic area covered by such approval shall no longer 
be considered a covered area for purposes of subparts D, E, and F of 
this part.
    (m) Effective one year after an area has been reclassified as a 
Severe ozone nonattainment area under section 181(b) of the Clean Air 
Act, such Severe area shall also be a covered area under the 
reformulated gasoline program. The ozone nonattainment areas identified 
pursuant to this paragraph (m) were reclassified as Severe ozone 
nonattainment areas, and are covered areas for purposes of subparts D, 
E, and F of this part. The geographic extent of each covered area 
identified pursuant to this paragraph (m) shall be the nonattainment 
area boundaries as specified in 40 CFR part 81, subpart C.
    (1) An area identified as a covered area pursuant to this paragraph 
(m), whose classification as a severe nonattainment area under the 1-
hour ozone NAAQS is removed as a result of removal of the 1-hour ozone 
NAAQS, remains a covered area as follows:
    (i) Prior to redesignation as attainment for the 8-hour ozone NAAQS 
the area remains a covered area;
    (ii) After redesignation as attainment for the 8-hour ozone NAAQS. 
[Reserved]
    (2) An area identified as a covered area pursuant to this paragraph 
(m), whose classification as a severe nonattainment area under the 1-
hour ozone NAAQS is removed as a result of redesignation to attainment 
for the 1-hour ozone NAAQS, remains a covered area as follows: 
[Reserved]

[59 FR 7813, Feb. 16, 1994, as amended at 59 FR 36964, July 20, 1994; 60 
FR 2699, Jan 11, 1995; 60 FR 35491, July 10, 1995; 61 FR 35680, July 8, 
1996; 62 FR 30270, June 3, 1997; 63 FR 43049, Aug. 11, 1998; 63 FR 
52104, Sept. 29, 1998; 64 FR 10371, Mar. 3, 1999; 67 FR 38403, June 4, 
2002; 70 FR 71705, Nov. 29, 2005; 72 FR 20242, Apr. 24, 2007]



Sec. 80.71  Descriptions of VOC-control regions.

    (a) Reformulated gasoline covered areas which are located in the 
following States are included in VOC-Control Region 1:


[[Page 716]]


Alabama
Arizona
Arkansas
California
Colorado
District of Columbia
Florida
Georgia
Kansas
Louisiana
Maryland
Mississippi
Missouri
Nevada
New Mexico
North Carolina
Oklahoma
Oregon
South Carolina
Tennessee
Texas
Utah
Virginia

    (b) Reformulated gasoline covered areas which are located in the 
following States are included in VOC-Control Region 2:

Connecticut
Delaware
Idaho
Illinois
Indiana
Iowa
Kentucky
Maine
Massachusetts
Michigan
Minnesota
Montana
Nebraska
New Hampshire
New Jersey
New York
North Dakota
Ohio
Pennsylvania
Rhode Island
South Dakota
Vermont
Washington
West Virginia
Wisconsin
Wyoming

    (c) Reformulated gasoline covered areas which are partially in VOC 
Control Region 1 and partially in VOC Control Region 2 shall be included 
in VOC Control Region 1, except in the case of the Philadelphia-
Wilmington-Trenton CMSA which shall be included in VOC Control Region 2.



Sec. 80.72  Procedures for opting out of the covered areas.

    (a) In accordance with paragraph (b) of this section, the 
Administrator may approve a petition from a state asking for removal of 
any opt-in area, or portion of an opt-in area, from inclusion as a 
covered area under Sec. 80.70. If the Administrator approves a 
petition, he or she shall set an effective date as provided in paragraph 
(c) of this section. The Administrator shall notify the state in writing 
of the Agency's action on the petition and the effective date of the 
removal when the petition is approved.
    (b) To be approved under paragraph (a) of this section, a petition 
must be signed by the Governor of a State, or his or her authorized 
representative, and must include the following:
    (1) A geographic description of each opt-in area, or portion of each 
opt-in area, which is covered by the petition;
    (2) A description of all ways in which reformulated gasoline is 
relied upon as a control measure in any approved State or local 
implementation plan or plan revision, or in any submission to the Agency 
containing any proposed plan or plan revision (and any associated 
request for redesignation) that is pending before the Agency when the 
petition is submitted; and
    (3) For any opt-in areas covered by the petition for which 
reformulated gasoline is relied upon as a control measure as described 
under paragraph (b)(2) of this section, the petition shall include the 
following information:
    (i) Identify whether the State is withdrawing any such pending plan 
submission;
    (ii)(A) Identify whether the State intends to submit a revision to 
any such approved plan provision or pending plan submission that does 
not rely on reformulated gasoline as a control measure, and describe the 
alternative air quality measures, if any, that the State plans to use to 
replace reformulated gasoline as a control measure;
    (B) A description of the current status of any proposed revision to 
any such approved plan provision or pending plan submission, as well as 
a projected schedule for submission of such proposed revision;
    (iii) If the State is not withdrawing any such pending plan 
submission and does not intend to submit a revision to any such approved 
plan provision or pending plan submission, describe why no revision is 
necessary;
    (iv) If reformulated gasoline is relied upon in any pending plan 
submission, other than as a contingency measure consisting of a future 
opt-in, and the Agency has found such pending plan submission complete 
or made a protectiveness finding under 40 CFR 51.448 and 93.128, 
demonstrate whether the removal of the reformulated gasoline program 
will affect the completeness and/or protectiveness determinations;
    (4) The Governor of a State, or his or her authorized 
representative, shall submit additional information upon request of the 
Administrator,

[[Page 717]]

    (c)(1) For opt-out petitions received on or before December 31, 
1997, except as provided in paragraphs (c)(2) and (c)(3) of this 
section, the Administrator shall set an effective date for removal of an 
area under paragraph (a) of this section as requested by the Governor, 
but no less than 90 days from the Agency's written notification to the 
state approving the opt-out petition, and no later than December 31, 
1999.
    (2) For opt-out petitions received on or before December 31, 1997, 
except as provided in paragraph (c)(3) of this section, where RFG is 
contained as an element of any plan or plan revision that has been 
approved by the Agency, other than as a contingency measure consisting 
of a future opt-in, then the effective date under paragraph (a) of this 
section shall be the date requested by the Governor, but no less than 90 
days from the effective date of Agency approval of a revision to the 
plan that removes RFG as a control measure.
    (3)(i) The Administrator may extend the deadline for submitting opt-
out petitions in paragraphs (c)(1) and (2) of this section for a state 
if:
    (A) The Governor or his authorized representative requests an 
extension prior to December 31, 1997;
    (B) The request indicates that there is active or pending 
legislation before the state legislature that was introduced prior to 
March 28, 1997;
    (C) The legislation is concerning opting out of or remaining in the 
reformulated gasoline program; and
    (D) The request demonstrates that the legislation cannot reasonably 
be acted upon prior to December 31, 1997.
    (ii) The Administrator may extend the deadline until no later than 
May 31, 1998. If the deadline is extended, then opt-out requests from 
that state received during the extension shall be considered under the 
provisions of paragraphs (c)(1) and (2) of this section.
    (4) For opt-out petitions received January 1, 1998 through December 
31, 2003, except as provided in paragraph (c)(5) of this section, the 
Administrator shall set an effective date for removal of an area under 
paragraph (a) of this section as requested by the Governor but no 
earlier than January 1, 2004 or 90 days from the Agency's written 
notification to the state approving the opt-out petition, whichever date 
is later.
    (5) For opt-out petitions received January 1, 1998 through December 
31, 2003, where RFG is contained as an element of any plan or plan 
revision that has been approved by the Agency, other than as a 
contingency measure consisting of a future opt-in, then the effective 
date for removal of an area under paragraph (a) of this section shall be 
the date requested by the Governor, but no earlier than January 1, 2004, 
or 90 days from the effective date of Agency approval of a revision to 
the plan that removes RFG as a control measure, whichever date is later.
    (6) For opt-out petitions received on or after January 1, 2004, 
except as provided in paragraph (c)(7) of this section, the 
Administrator shall set an effective date for removal of an area as 
requested by the Governor, but no less than 90 days from the Agency's 
written notification to the state approving the opt-out petition.
    (7) For opt-out petitions received on or after January 1, 2004, 
where RFG is contained as an element of any plan or plan revision that 
has been approved by the Agency, other than as a contingency measure 
consisting of a future opt-in, then the effective date for removal of an 
area under paragraph (a) of this section shall be the date requested by 
the Governor, but no less than 90 days from the effective date of Agency 
approval of a revision to the plan that removes RFG as a control 
measure.
    (d) The Administrator shall publish a notice in the Federal Register 
announcing the approval of any petition under paragraph (a) of this 
section, and the effective date for removal.

[61 FR 35680, July 8, 1996, as amended at 62 FR 54558, Oct. 20, 1997]



Sec. 80.73  Inability to produce conforming gasoline in extraordinary circumstances.

    In appropriate extreme and unusual circumstances (e.g., natural 
disaster or Act of God) which are clearly outside the control of the 
refiner, importer, or oxygenate blender and which could not have been 
avoided by the exercise of prudence, diligence, and due care, EPA may 
permit a refiner, importer, or oxygenate blender, for a brief period, to

[[Page 718]]

distribute gasoline which does not meet the requirements for 
reformulated gasoline, or does not contain the type(s) and amount(s) of 
oxygenate required under Sec. 80.69(b)(1), if:
    (a) It is in the public interest to do so (e.g., distribution of the 
nonconforming gasoline is necessary to meet projected shortfalls which 
cannot otherwise be compensated for);
    (b) The refiner, importer, or oxygenate blender exercised prudent 
planning and was not able to avoid the violation and has taken all 
reasonable steps to minimize the extent of the nonconformity;
    (c) The refiner, importer, or oxygenate blender can show how the 
requirements for reformulated gasoline will be expeditiously achieved;
    (d) The refiner, importer, or oxygenate blender agrees to make up 
air quality detriment associated with the nonconforming gasoline, where 
practicable; and
    (e) The refiner, importer, or oxygenate blender pays to the U.S. 
Treasury an amount equal to the economic benefit of the nonconformity 
minus the amount expended, pursuant to paragraph (d) of this section, in 
making up the air quality detriment.

[38 FR 1255, Jan. 10, 1973, as amended at 71 FR 26700, May 8, 2006]



Sec. 80.74  Recordkeeping requirements.

    All parties in the gasoline distribution network, as described in 
this section, shall maintain records containing the information as 
required in this section. These records shall be retained for a period 
of five years from the date of creation, and shall be delivered to the 
Administrator of EPA or to the Administrator's authorized representative 
upon request.
    (a) All regulated parties. Any refiner, importer, oxygenate blender, 
carrier, distributor, reseller, retailer, or wholesale-purchaser who 
sells, offers for sale, dispenses, supplies, offers for supply, stores, 
transports, or causes the transportation of any reformulated gasoline or 
RBOB, shall maintain records containing the following information:
    (1) The product transfer documentation for all reformulated gasoline 
or RBOB for which the party is the transferor or transferee; and
    (2) For any sampling and testing on RBOB or reformulated gasoline:
    (i) The location, date, time, and storage tank or truck 
identification for each sample collected;
    (ii) The identification of the person who collected the sample and 
the person who performed the testing;
    (iii) The results of the tests; and
    (iv) The actions taken to stop the sale of any gasoline found not to 
be in compliance, and the actions taken to identify the cause of any 
noncompliance and prevent future instances of noncompliance.
    (b) Refiners and importers. In addition to other requirements of 
this section, any refiner and importer shall, for all reformulated 
gasoline and RBOB produced or imported, maintain records containing the 
following information:
    (1) Results of the tests to determine reformulated gasoline 
properties and characteristics specified in Sec. 80.65;
    (2) [Reserved]
    (3) The volume of gasoline associated with each of the above test 
results using the method normally employed at the refinery or import 
facility for this purpose;
    (4) In the case of RBOB:
    (i) The results of tests to ensure that, following blending, RBOB 
meets applicable standards; and
    (ii) Each contract with each oxygenate blender to whom the refiner 
or importer transfers RBOB; or
    (iii) Compliance calculations described in Sec. 80.69(a)(8) based 
on an assumed addition of oxygenate;
    (5) In the case of any refinery or importer subject to the simple 
model standards, the calculations used to determine the 1990 baseline 
levels of sulfur, T-90, and olefins, and the calculations used to 
determine compliance with the standards for these parameters;
    (6) In the case of any refinery or importer subject to the complex 
model standards before January 1, 1998, the calculations used to 
determine the baseline levels of VOC, toxics, and NOX 
emissions performance; and
    (7) In the case of any gasoline classified as previously certified 
gasoline under the terms of Sec. 80.65(i):

[[Page 719]]

    (i) Results of the tests to determine the properties and volume of 
the previously certified gasoline when received at the refinery; and
    (ii) Records that reflect the storage and movement of the previously 
certified gasoline within the refinery to the point the previously 
certified gasoline is used to produce reformulated gasoline or RBOB;
    (8) In the case of butane blended into reformulated gasoline or RBOB 
under Sec. 80.82, documentation of:
    (i) The volume of butane added;
    (ii) The volume of reformulated gasoline or RBOB both prior to and 
subsequent to the butane blending;
    (iii) The purity and properties of the butane specified in Sec. 
80.82(c) and (d), as appropriate;
    (iv) Compliance with the requirements of Sec. 80.82; and
    (9) In the case of any imported GTAB, documents that reflect the 
storage and physical movement of the GTAB from the point of importation 
to the point of blending to produce reformulated gasoline.
    (10) In the case of any interface or transmix used to produce 
reformulated gasoline or RBOB under Sec. 80.84, records that reflect 
the results of any sampling and testing of RFG or RBOB required under 
Sec. 80.84.
    (i) Pipelines must keep records showing that interface was 
designated in the proper manner, according to the designations listed in 
Sec. 80.84(b)(1);
    (ii) Transmix processors and transmix blenders must keep records 
showing that their transmix meets the definition in Sec. 80.84(a)(2), 
or contains gasoline and distillate fuel only from the sources listed in 
Sec. 80.84(e);
    (iii) Transmix processors must keep records showing the volumes of 
reformulated gasoline or RBOB recovered from transmix and the type and 
amount of any blendstock added, if applicable; and
    (iv) Transmix blenders must keep records showing compliance with the 
quality assurance program and/or sampling and testing requirements in 
Sec. 80.84(d)(2) or (d)(3), and for each batch of reformulated gasoline 
or RBOB with which transmix is blended, the volume of the batch, and the 
volume of transmix blended into the batch;
    (c) Refiners and importers of averaged gasoline. In addition to 
other requirements of this section, any refiner or importer who produces 
or imports any reformulated gasoline for which compliance with one or 
more applicable standard is determined on an average shall maintain 
records containing the following information:
    (1) The calculations used to determine compliance with the relevant 
standards on average, for each averaging period and for each quantity of 
gasoline for which standards must be separately achieved; and
    (2) For any credits bought, sold, traded or transferred pursuant to 
Sec. 80.67(h), the dates of the transactions, the names and EPA 
registration numbers of the parties involved, and the number of credits 
transferred.
    (d) Oxygenate blenders. Any oxygenate blender who blends any 
oxygenate with any RBOB shall, for each occasion such blending occurs, 
maintain records containing the following:
    (i) The date, time, location, and identification of the blending 
tank or truck in which the blending occurred;
    (ii) The volume and oxygenate requirements of the RBOB to which 
oxygenate was added; and
    (iii) The volume, type, and purity of the oxygenate which was added, 
and documents which show the source(s) of the oxygenate used.
    (e) Distributors who dispense RBOB into trucks. In addition to other 
requirements of this section, any distributor who dispenses any RBOB 
into a truck used for delivering gasoline to retail outlets shall, for 
each occasion RBOB is dispensed into such a truck, obtain records 
identifying:
    (1) The name and EPA registration number of the oxygenate blender 
that received the RBOB; and
    (2) The volume and oxygenate requirements of the RBOB dispensed.
    (f) [Reserved]
    (g) Retailers before January 1, 1998. Prior to January 1, 1998 any 
retailer that sells or offers for sale any reformulated gasoline shall 
maintain at each retail outlet the product transfer documentation for 
the most recent three deliveries to the retail outlet of each grade of 
reformulated gasoline sold or offered for sale at the retail

[[Page 720]]

outlet, and shall make such documentation available to any person 
conducting any gasoline compliance survey pursuant to Sec. 80.68.

[59 FR 7813, Feb. 16, 1994, as amended at 66 FR 67106, Dec. 28, 2001; 71 
FR 74569, Dec. 15, 2005; 71 FR 26700, May 8, 2006; 71 FR 31961, June 2, 
2006]



Sec. 80.75  Reporting requirements.

    Any refiner or importer shall report as specified in this section, 
and shall report such other information as the Administrator may 
require.
    (a) Quarterly reports for reformulated gasoline. Any refiner or 
importer that produces or imports any reformulated gasoline or RBOB 
shall submit quarterly reports to the Administrator for each refinery at 
which such reformulated gasoline or RBOB was produced and for all such 
reformulated gasoline or RBOB imported by each importer.
    (1) The quarterly reports shall be for all such reformulated 
gasoline or RBOB produced or imported during the following time periods:
    (i) The first quarterly report shall include information for 
reformulated gasoline or RBOB produced or imported from January 1 
through March 31, and shall be submitted by May 31 of each year 
beginning in 1995;
    (ii) The second quarterly report shall include information for 
reformulated gasoline or RBOB produced or imported from April 1 through 
June 30, and shall be submitted by August 31 of each year beginning in 
1995;
    (iii) The third quarterly report shall include information for 
reformulated gasoline or RBOB produced or imported from July 1 through 
September 30, and shall be submitted by November 30 of each year 
beginning in 1995; and
    (iv) The fourth quarterly report shall include information for 
reformulated gasoline or RBOB produced or imported from October 1 
through December 31, and shall be submitted by the last day of February 
of each year beginning in 1996.
    (2) The following information shall be included in each quarterly 
report for each batch of reformulated gasoline or RBOB which is included 
under paragraph (a)(1) of this section:
    (i) The batch number;
    (ii) The date of production;
    (iii) The volume of the batch;
    (iv) The grade of gasoline produced (i.e., premium, mid-grade, or 
regular);
    (v) For any refiner or importer:
    (A) Each designation of the gasoline, pursuant to Sec. 80.65; and
    (B) The properties, pursuant to Sec. Sec. 80.65 and 80.66;
    (vi) For any importer, the PADD in which the import facility is 
located;
    (vii) [Reserved]
    (viii) In the case of any previously certified gasoline used in a 
refinery operation under the terms of Sec. 80.65(i), the following 
information relative to the previously certified gasoline when received 
at the refinery:
    (A) Identification of the previously certified gasoline as such;
    (B) The batch number assigned by the receiving refinery;
    (C) The date of receipt; and
    (D) The volume, properties and designation of the batch.
    (ix) In the case of butane blended with reformulated gasoline or 
RBOB under Sec. 80.82:
    (A) Identification of the butane batch as complying with the 
provisions of Sec. 80.82;
    (B) Identification of the butane batch as commercial or non-
commercial grade butane;
    (C) The batch number of the butane;
    (D) The date of production of the gasoline produced using the butane 
batch;
    (E) The volume of the butane batch;
    (F) The properties of the butane batch specified by the butane 
supplier, or the properties specified in Sec. 80.82(c) or (d), as 
appropriate;
    (G) The volume of the gasoline batch subsequent to the butane 
blending; and
    (x) In the case of any imported GTAB, identification of the gasoline 
as GTAB.
    (3) Information pertaining to gasoline produced or imported during 
1994 shall be included in the first quarterly report in 1995.
    (b) Reports for gasoline or RBOB produced or imported under the 
simple model--(1) RVP averaging reports. (i) Any refiner or importer 
that produced or imported any reformulated gasoline or RBOB under the 
simple model that was to meet RVP standards on average (``averaged 
reformulated gasoline'') shall submit to the Administrator,

[[Page 721]]

with the third quarterly report, a report for each refinery or importer 
for such averaged reformulated gasoline or RBOB produced or imported 
during the previous RVP averaging period. This information shall be 
reported separately for the following categories:
    (A) Gasoline or RBOB which is designated as VOC-controlled intended 
for areas in VOC-Control Region 1; and
    (B) Gasoline or RBOB which is designated as VOC-controlled intended 
for VOC-Control Region 2.
    (ii) The following information shall be reported:
    (A) The total volume of averaged reformulated gasoline or RBOB in 
gallons;
    (B) The compliance total value for RVP; and
    (C) The actual total value for RVP.
    (2) Sulfur, olefins and T90 averaging reports. (i) Any refiner or 
importer that produced or imported any reformulated gasoline or RBOB 
under the simple model shall submit to the Administrator, with the 
fourth quarterly report, a report for such reformulated gasoline or RBOB 
produced or imported during the previous year:
    (A) For each refinery or importer; or
    (B) In the case of refiners who operate more than one refinery, for 
each grouping of refineries as designated by the refiner pursuant to 
Sec. 80.41(h)(2)(iii).
    (ii) The following information shall be reported:
    (A) The total volume of reformulated gasoline or RBOB in gallons;
    (B) The applicable sulfur content standard under Sec. 
80.41(h)(2)(i) in parts per million;
    (C) The average sulfur content in parts per million;
    (D) The difference between the applicable sulfur content standard 
under Sec. 80.41(h)(2)(i) in parts per million and the average sulfur 
content under paragraph (b)(2)(ii)(C) of this section in parts per 
million, indicating whether the average is greater or lesser than the 
applicable standard;
    (E) The applicable olefin content standard under Sec. 
80.41(h)(2)(i) in volume percent;
    (F) The average olefin content in volume percent;
    (G) The difference between the applicable olefin content standard 
under Sec. 80.41(h)(2)(i) in volume percent and the average olefin 
content under paragraph (b)(2)(ii)(F) of this section in volume percent, 
indicating whether the average is greater or lesser than the applicable 
standard;
    (H) The applicable T90 distillation point standard under Sec. 
80.41(h)(2)(i) in degrees Fahrenheit;
    (I) The average T90 distillation point in degrees Fahrenheit; and
    (J) The difference between the applicable T90 distillation point 
standard under Sec. 80.41(h)(2)(i) in degrees Fahrenheit and the 
average T90 distillation point under paragraph (b)(2)(ii)(I) of this 
section in degrees Fahrenheit, indicating whether the average is greater 
or lesser than the applicable standard.
    (c) VOC emissions performance averaging reports. (1) Any refiner or 
importer that produced or imported any reformulated gasoline or RBOB 
under the complex model that was to meet the VOC emissions performance 
standards on average (``averaged reformulated gasoline'') shall submit 
to the Administrator, with the third quarterly report, a report for each 
refinery or importer for such averaged reformulated gasoline produced or 
imported during the previous VOC averaging period. This information 
shall be reported separately for the following categories:
    (i) Gasoline or RBOB which is designated as VOC-controlled intended 
for areas in VOC-Control Region 1; and
    (ii) Gasoline or RBOB which is designated as VOC-controlled intended 
for VOC-Control Region 2.
    (2) The following information shall be reported:
    (i) The total volume of averaged reformulated gasoline or RBOB in 
gallons;
    (ii) The compliance total value for VOC emissions performance; and
    (iii) The actual total value for VOC emissions performance.
    (d) Benzene content averaging reports. (1) Any refiner or importer 
that produced or imported any reformulated gasoline or RBOB that was to 
meet the benzene content standards on average (``averaged reformulated 
gasoline'') shall submit to the Administrator, with the fourth quarterly 
report, a report for each refinery or importer for

[[Page 722]]

such averaged reformulated gasoline that was produced or imported during 
the previous toxics averaging period.
    (2) The following information shall be reported:
    (i) The volume of averaged reformulated gasoline or RBOB in gallons;
    (ii) The compliance total content of benzene;
    (iii) The actual total content of benzene;
    (iv) The number of benzene credits generated as a result of actual 
total benzene being less than compliance total benzene;
    (v) The number of benzene credits required as a result of actual 
total benzene being greater than compliance total benzene;
    (vi) The number of benzene credits transferred to another refinery 
or importer; and
    (vii) The number of benzene credits obtained from another refinery 
or importer.
    (e) Toxics emissions performance averaging reports. (1) Any refiner 
or importer that produced or imported any reformulated gasoline or RBOB 
that was to meet the toxics emissions performance standards on average 
(``averaged reformulated gasoline'') shall submit to the Administrator, 
with the fourth quarterly report, a report for each refinery or importer 
for such averaged reformulated gasoline that was produced or imported 
during the previous toxics averaging period.
    (2) The following information shall be reported:
    (i) The volume of averaged reformulated gasoline or RBOB in gallons;
    (ii) The compliance value for toxics emissions performance; and
    (iii) The actual value for toxics emissions performance.
    (f) [Reserved]
    (g) NOX emissions performance averaging reports. (1) Any 
refiner or importer that produced or imported any reformulated gasoline 
or RBOB that was to meet the NOX emissions performance 
standard on average (``averaged reformulated gasoline'') shall submit to 
the Administrator, with the fourth quarterly report, a report for each 
refinery or importer for such averaged reformulated gasoline that was 
produced or imported during the previous NOX averaging 
period.
    (2) The following information shall be reported:
    (i) The volume of averaged reformulated gasoline or RBOB in gallons;
    (ii) The compliance value for NOX emissions performance; 
and
    (iii) The actual value for NOX emissions performance.
    (3) The information required by paragraph (g)(2) of this section 
shall be reported separately for the following categories:
    (i) Gasoline and RBOB which is designated as VOC-controlled; and
    (ii) Gasoline and RBOB which is not designated as VOC-controlled.
    (h) Credit transfer reports. As an additional part of the fourth 
quarterly report required by this section, any refiner or importer 
shall, for each refinery or importer, supply the following information 
for any benzene credits that are transferred from or to another refinery 
or importer:
    (1) The names, EPA-assigned registration numbers and facility 
identification numbers of the transferor and transferee of the credits;
    (2) The number(s) of credits that were transferred; and
    (3) The date(s) of the transaction(s).
    (i) Covered areas of gasoline use report. Any refiner that produced 
any reformulated gasoline that was to meet any reformulated gasoline 
standard on average (``averaged reformulated gasoline'') shall, for each 
refinery at which such averaged reformulated gasoline was produced 
submit to the Administrator, with the fourth quarterly report, a report 
that contains the identity of each covered area that was supplied with 
any averaged reformulated gasoline produced at each refinery during the 
previous year.
    (j) Additional reporting requirements for certain importers. In the 
case of any importer to whom different standards apply for gasoline 
imported at different facilities by operation of Sec. 80.41(q)(2), such 
importer shall submit separate reports for gasoline imported into 
facilities subject to different standards.
    (k) Reporting requirements for early use of the complex model. Any 
refiner for any refinery, or any importer, that elects to be subject to 
complex model

[[Page 723]]

standards under Sec. 80.41(i)(1) shall report such election in writing 
to the Administrator no later than sixty days prior to the beginning of 
the calendar year during which such standards would apply. This report 
shall include the refinery's or importer's baseline values for VOC, 
NOX, and toxics emissions performance, in milligrams per 
mile.
    (l) Reports for per-gallon compliance gasoline. In the case of 
reformulated gasoline or RBOB for which compliance with each of the 
standards set forth in Sec. 80.41 is achieved on a per-gallon basis, 
the refiner or importer shall submit to the Administrator, by the last 
day of February of each year beginning in 1996, a report of the volume 
of each designated reformulated gasoline or RBOB produced or imported 
during the previous calendar year for which compliance is achieved on a 
per-gallon basis, and a statement that each gallon of this reformulated 
gasoline or RBOB met the applicable standards.
    (m) Reports of compliance audits. Any refiner or importer shall 
cause to be submitted to the Administrator, by May 31 of each year, the 
report of the compliance audit required by Sec. 80.65(h).
    (n) Report submission. The reports required by this section shall 
be:
    (1) Submitted on forms and following procedures specified by the 
Administrator; and
    (2) Signed and certified as correct by the owner or a responsible 
corporate officer of the refiner or importer.
    (o) Additional reporting requirements for refiners that blend butane 
with reformulated gasoline or RBOB. For refiners that blend any butane 
with reformulated gasoline or RBOB under Sec. 80.82, the refiner shall 
submit to the Administrator, by the last day of February of each year, a 
report for the refinery which includes the following information for the 
previous calendar year:
    (1) The total volume of butane blended with reformulated gasoline or 
RBOB at the refinery, separately for reformulated gasoline and RBOB;
    (2) The total volume of reformulated gasoline or RBOB produced using 
butane, separately for reformulated gasoline and RBOB;
    (3) A statement that each gallon of reformulated gasoline or RBOB 
produced using butane met the applicable per-gallon standards under 
Sec. 80.41;
    (4) A statement that all butane blended with reformulated gasoline 
or RBOB at the refinery is included in the volume reported in paragraph 
(o)(2) of this section;

[59 FR 7813, Feb. 16, 1994, as amended at 59 FR 36964, July 20, 1994; 60 
FR 65574, Dec. 20, 1995; 62 FR 60135, Nov. 6, 1997; 66 FR 67106, Dec. 
28, 2001; 71 FR 74569, Dec. 15, 2005; 71 FR 26700, May 8, 2006]



Sec. 80.76  Registration of refiners, importers or oxygenate blenders.

    (a) Registration with the Administrator of EPA is required for any 
refiner and importer that produces or imports any reformulated gasoline 
or RBOB, and any oxygenate blender that blends oxygenate into RBOB.
    (b) Any person required to register shall do so by November 1, 1994, 
or not later than three months in advance of the first date that such 
person will produce or import reformulated gasoline or RBOB or 
conventional gasoline, whichever is later.
    (c) Registration shall be on forms prescribed by the Administrator, 
and shall include the following information:
    (1) The name, business address, contact name, and telephone number 
of the refiner, importer, or oxygenate blender;
    (2) For each separate refinery and oxygenate blending facility, the 
facility name, physical location, contact name, telephone number, and 
type of facility; and
    (3) For each separate refinery and oxygenate blending facility, and 
for each importer's operations in a single PADD:
    (i) Whether records are kept on-site or off-site of the refinery or 
oxygenate blending facility, or in the case of importers, the registered 
address;
    (ii) If records are kept off-site, the primary off-site storage 
facility name, physical location, contact name, and telephone number; 
and
    (iii) The name, address, contact name and telephone number of the 
independent laboratory used to meet the independent analysis 
requirements of Sec. 80.65(f).

[[Page 724]]

    (d) EPA will supply a registration number to each refiner, importer, 
and oxygenate blender, and a facility registration number for each 
refinery and oxygenate blending facility that is identified, which shall 
be used in all reports to the Administrator.
    (e)(1) Any refiner, importer, or oxygenate blender shall submit 
updated registration information to the Administrator within thirty days 
of any occasion when the registration information previously supplied 
becomes incomplete or inaccurate; except that
    (2) EPA must be notified in writing of any change in designated 
independent laboratory at least thirty days in advance of such change.

[59 FR 7813, Feb. 16, 1994, as amended at 59 FR 36965, July 20, 1994; 71 
FR 74570, Dec. 15, 2005; 71 FR 26701, May 8, 2006]



Sec. 80.77  Product transfer documentation.

    On each occasion when any person transfers custody or title to any 
reformulated gasoline or RBOB, other than when gasoline is sold or 
dispensed for use in motor vehicles at a retail outlet or wholesale 
purchaser-consumer facility, the transferor shall provide to the 
transferee documents which include the following information:
    (a) The name and address of the transferor;
    (b) The name and address of the transferee;
    (c) The volume of gasoline or RBOB which is being transferred;
    (d) The location of the gasoline at the time of the transfer;
    (e) The date of the transfer;
    (f) The proper identification of the product as reformulated 
gasoline or RBOB;
    (g) In the case of reformulated gasoline or RBOB:
    (1) The proper identification as:
    (i)(A) VOC-controlled for VOC-Control Region 1; or VOC-controlled 
for VOC-Control Region 2; or Not VOC-controlled; or
    (B) In the case of gasoline or RBOB that is VOC-controlled for VOC-
Control Region 1, the gasoline may be identified as suitable for use 
either in VOC-Control Region 1 or VOC-Control Region 2;
    (ii) [Reserved]
    (iii) Prior to January 1, 1998, certified under the simple model 
standards or certified under the complex model standards; and
    (2) The minimum and/or maximum standards with which the gasoline or 
RBOB conforms for:
    (i) Benzene content;
    (ii) [Reserved]
    (iii) In the case of VOC-controlled gasoline subject to the simple 
model standards, RVP;
    (iv) In the case of gasoline subject to the complex model standards:
    (A) Prior to January 1, 1998, the NOx emissions performance minimum, 
and for VOC-controlled gasoline the VOC emissions performance minimum, 
in milligrams per mile; and
    (B) Beginning on January 1, 1998, for VOC-controlled gasoline, the 
VOC emissions performance minimum.
    (3) Identification of VOC-controlled reformulated gasoline or RBOB 
as gasoline or RBOB which contains ethanol, or which does not contain 
any ethanol; and
    (4) For transfers of custody of gasoline subject to the provisions 
of Sec. 80.69(a)(11), the information required to be included on 
product transfer documents under Sec. 80.69(a)(11)(vii)(A).
    (h) Prior to January 1, 1998, in the case of reformulated gasoline 
or RBOB subject to the complex model standards:
    (1) The name and EPA registration number of the refinery at which 
the gasoline was produced, or importer that imported the gasoline; and
    (2) Instructions that the gasoline or RBOB may not be combined with 
any other gasoline or RBOB that was produced at any other refinery or 
was imported by any other importer;
    (i) In the case of RBOB:
    (1) The designation of the RBOB as suitable for blending with:
    (i) Any-oxygenate;
    (ii) Ether-only; or
    (iii) Other specified oxygenate type(s) and amount(s);
    (2) The oxygenate type(s) and amount(s) that are intended for 
blending with the RBOB;
    (3) Instructions that the RBOB may not be combined with any other 
RBOB except other RBOB having the same requirements for oxygenate 
type(s) and

[[Page 725]]

amount(s), or, prior to blending, with reformulated gasoline.

[59 FR 7813, Feb. 16, 1994, as amended at 59 FR 36965, July 20, 1994; 62 
FR 60136, Nov. 6, 1997; 62 FR 68207, Dec. 31, 1997; 71 FR 74570, Dec. 
15, 2005; 71 FR 26701, May 8, 2006; 71 FR 31961, June 2, 2006]



Sec. 80.78  Controls and prohibitions on reformulated gasoline.

    (a) Prohibited activities. (1) No person may manufacture and sell or 
distribute, offer for sale or distribution, dispense, supply, offer for 
supply, store, transport, or cause the transportation of any gasoline 
represented as reformulated and intended for sale or use in any covered 
area:
    (i) Unless each gallon of such gasoline meets the applicable benzene 
maximum standard specified in Sec. 80.41;
    (ii)-(iii) [Reserved]
    (iv) Unless the product transfer documentation for such gasoline 
complies with the requirements in Sec. 80.77; and
    (v) During the period May 1 through September 15 for all persons 
except retailers and wholesale purchaser-consumers, and during the 
period June 1 through September 15 for all persons including retailers 
and wholesale purchaser-consumers:
    (A) Unless each gallon of such gasoline is VOC-controlled for the 
proper VOC Control Region, except that gasoline designated for VOC-
Control Region 1 may be used in VOC-Control Region 2;
    (B) Unless each gallon of such gasoline that is subject to simple 
model standards has an RVP which is less than or equal to the applicable 
RVP maximum specified in Sec. 80.41;
    (C) Unless each gallon of such gasoline that is subject to complex 
model standards has a VOC emissions reduction percentage which is 
greater than or equal to the applicable minimum specified in Sec. 
80.41.
    (2) No refiner or importer may produce or import any gasoline 
represented as reformulated or RBOB, and intended for sale or use in any 
covered area:
    (i) Unless such gasoline meets the definition of reformulated 
gasoline or RBOB; and
    (ii) Unless the properties of such gasoline or RBOB correspond to 
the product transfer documents.
    (3) [Reserved]
    (4) Gasoline shall be presumed to be intended for sale or use in a 
covered area unless:
    (i) Product transfer documentation as described in Sec. 80.77 
accompanying such gasoline clearly indicates the gasoline is intended 
for sale and use only outside any covered area; or
    (ii) The gasoline is contained in the storage tank of a retailer or 
wholesale purchaser-consumer outside any covered area.
    (5) No person may combine any reformulated gasoline with any 
conventional gasoline or blendstock, except that a refiner may do so at 
a refinery under the requirements specified in Sec. 80.65(i), or if the 
combined product is designated as conventional gasoline.
    (6) No person may add any oxygenate to reformulated gasoline, except 
that such oxygenate may be added to reformulated gasoline provided that 
such gasoline is used in an oxygenated fuels program control area during 
an oxygenated fuels control period.
    (7) No person may combine any reformulated gasoline blendstock for 
oxygenate blending with any other gasoline, blendstock, or oxygenate 
except:
    (i) Oxygenate of the type and amount (or within the range of 
amounts) specified by the refiner or importer at the time the RBOB was 
produced or imported;
    (ii) Other RBOB for which the same oxygenate type and amount (or 
range of amounts) was specified by the refiner or importer; or
    (iii) Under the terms of paragraph (a)(5) of this section.
    (8)(i) No person may combine any ethanol-blended VOC-controlled 
reformulated gasoline with any non-ethanol-blended VOC-controlled 
reformulated gasoline during the period January 1 through September 15, 
except that:
    (ii) Notwithstanding the prohibition in paragraph (a)(8)(i), 
retailers and wholesale purchaser-consumers may combine at a retail 
outlet or wholesale purchaser-consumer facility ethanol-blended VOC-
controlled reformulated gasoline with non-ethanol-blended VOC-controlled 
reformulated gasoline, provided that the retailer or wholesale 
purchaser-consumer:

[[Page 726]]

    (A) Combines only batches of reformulated gasoline that have been 
certified under this subpart;
    (B) Notifies EPA prior to combining the gasolines and identifies the 
exact location of the retail outlet or wholesale purchase-consumer 
facility and the specific tank in which the gasolines will be combined;
    (C) Retains and, upon request by EPA, makes available for inspection 
product transfer documentation accounting for all gasoline at the retail 
outlet or wholesale purchaser-consumer facility; and
    (D) Does not combine any VOC-controlled gasoline with any non-VOC 
controlled gasoline between June 1 and September 15 of each calendar 
year;
    (iii) A retailer or wholesale purchaser-consumer may combine 
ethanol-blended reformulated gasoline with non-ethanol-blended 
reformulated gasoline under paragraph (a)(8)(ii) of this section a 
maximum of two periods between May 1 and September 15 of each calendar 
year, each such period to extend for a period of no more than ten 
consecutive calendar days. At the end of the ten-day period, the 
gasoline must be in compliance with the VOC minimum standard under Sec. 
80.41.
    (A) The retailer or wholesale purchaser-consumer may demonstrate 
compliance with the VOC minimum standard by testing the gasoline at the 
end of the ten-day period using the test methods in Sec. 80.46, where 
the test results show that the gasoline meets the VOC minimum standard. 
Under this option, the retailer or wholesale purchaser-consumer may add 
both ethanol-blended reformulated gasoline and non-ethanol-blended 
reformulated gasoline to the same tank an unlimited number of times 
during the ten-day period; or
    (B) The retailer or wholesale purchaser-consumer will be deemed in 
compliance with the VOC minimum standard where the retailer or wholesale 
purchaser-consumer draws the tank down as low as practicable before 
receiving product of the other type into the tank and receives only 
product of the other type into the tank during the ten-day period. Under 
this option, the retailer or wholesale purchaser-consumer is not 
required to test the gasoline at the end of the ten-day period.
    (iv) Nothing in paragraphs (a)(8)(ii) or (iii) of this section shall 
preempt existing State laws or regulations regulating the combining of 
ethanol-blended reformulated gasoline with non-ethanol-blended 
reformulated gasoline or prohibit a State from adopting such laws or 
regulations in the future.
    (9) Prior to January 1, 1998:
    (i) No person may combine any reformulated gasoline or RBOB that is 
subject to the simple model standards with any reformulated gasoline or 
RBOB that is subject to the complex model standards, except that such 
gasolines may be combined at a retail outlet or wholesale purchaser-
consumer facility;
    (ii) No person may combine any reformulated gasoline subject to the 
complex model standards that is produced at any refinery or is imported 
by any importer with any other reformulated gasoline that is produced at 
a different refinery or is imported by a different importer, unless the 
other refinery or importer has an identical baseline for meeting complex 
model standards during this period; and
    (iii) No person may combine any RBOB subject to the complex model 
standards that is produced at any refinery or is imported by any 
importer with any RBOB that is produced at a different refinery or is 
imported by a different importer, unless the other refinery or importer 
has an identical baseline for meeting complex model standards during 
this period.
    (10) The prohibitions against combining certain categories of 
gasoline under paragraphs (a)(5), (a)(7) and (a)(8) of this section do 
not apply in the case of a party who is changing the type of gasoline 
stored in a gasoline storage tank or the type of gasoline transported 
through a gasoline pipe or manifold within a single facility (a gasoline 
storage tank, pipe, or manifold change of service), or in the case of a 
change of service that involves mixing gasoline with blendstock, 
provided that:
    (i) The change of service is for a legitimate operational reason and 
is not for the purpose of combining the categories of gasoline or of 
combining gasoline with blendstock;

[[Page 727]]

    (ii) Prior to adding product of the new category the volume of 
product of the old category in the tank, pipe or manifold is made as low 
as possible through normal pumping operations;
    (iii) The volume of product of the new category that is added to the 
tank, pipe or manifold is as large as possible taking into account the 
availability of product of the new category; and
    (iv) In any case where the new category of product is reformulated 
gasoline, subsequent to adding the gasoline of the new category, a 
representative sample from the tank, pipe or manifold is collected and 
analyzed, and such analysis shows compliance with each standard under 
Sec. 80.41 that is relevant to the new gasoline category. The analysis 
for each standard must be conducted using the method specified under 
Sec. 80.46, or using another method that is approved by the American 
Society of Testing and Materials (ASTM), provided that the protocols of 
the ASTM method are followed and the alternative method is correlated to 
the method specified under Sec. 80.46.
    (11) The prohibition against combining reformulated gasoline with 
RBOB under paragraph (a)(7) of this section does not apply in the case 
of a party who is changing the type of product stored in a tank from 
which trucks are loaded, from reformulated gasoline to RBOB, or vice 
versa, provided that:
    (i) The change of service requirements described in paragraph 
(a)(10) of this section cannot be met without taking the storage tank 
out of service;
    (ii) Prior to adding product of the new category the volume of 
product of the old category in the tank is drawn down to the lowest 
point which allows trucks to be loaded during the transition;
    (iii) The volume of product of the new category that is added to the 
tank is as large as possible taking into account the availability of 
product of the new category;
    (iv) When transitioning from RBOB to reformulated gasoline, the 
reformulated gasoline must meet all applicable standards that apply at 
the terminal subsequent to any oxygenate blending;
    (v) When transitioning from reformulated gasoline to RBOB:
    (A) The oxygen content of the reformulated gasoline produced using 
the RBOB must be not less than the minimum oxygen amount specified in 
the RBOB product transfer documents;
    (B) Subsequent to any oxygenate blending, the reformulated gasoline 
produced using the RBOB must meet all applicable standards that apply at 
the terminal; and
    (C) The transition from reformulated gasoline to RBOB may not begin 
until the date the VOC-control standards no longer apply to the 
terminal; and
    (vi) The party must demonstrate compliance with the requirements 
specified in paragraphs (a)(11)(iv) and (v) of this section through 
testing of samples collected from the terminal storage tank and from 
trucks loaded at the terminal subsequent to each receipt of new product 
until the transition is complete. The analyses must be conducted using 
the test method specified under Sec. 80.46, or using another test 
method that is approved by the American Society of Testing and Materials 
(ASTM), provided that the protocols of the ASTM method are followed and 
the alternative method is correlated with the method specified under 
Sec. 80.46.
    (12)(i) The prohibited activities specified in paragraph (a)(1) of 
this section do not apply in the case of gasoline that is used to fuel 
aircraft, or racing motor vehicles or racing boats that are used only in 
sanctioned racing events, provided that product transfer documents 
associated with such gasoline, and any pump stand from which such 
gasoline is dispensed, identify the gasoline either as conventional 
gasoline that is restricted for use in aircraft, or as conventional 
gasoline that is restricted for use in racing motor vehicles or racing 
boats that are used only in sanctioned racing events.
    (ii) A vehicle shall be considered to be a racing vehicle only if 
the vehicle:
    (A) Is operated in conjunction with sanctioned racing events;
    (B) Exhibits racing features and modifications such that it is 
incapable of safe and practical street or highway use;
    (C) Is not licensed, and is not licensable, by any state for 
operation on public streets or highways;

[[Page 728]]

    (D) Is not operated on public streets or highways; and
    (E) Could not be converted to public street or highway use at a cost 
that is reasonable compared to the value of the vehicle.
    (b) Liability. Liability for violations of paragraph (a) of this 
section shall be determined according to the provisions of Sec. 80.79.
    (c) Determination of compliance. Compliance with the standards 
listed in paragraph (a) of this section shall be determined by use of 
one of the testing methodologies specified in Sec. 80.46, except that 
where test results using the testing methodologies specified in Sec. 
80.46 are not available or where such test results are available but are 
in question, EPA may establish noncompliance with standards using any 
information, including the results of testing using methods that are not 
included in Sec. 80.46.
    (d) Dates controls and prohibitions begin. The controls and 
prohibitions specified in paragraph (a) of this section apply at any 
location other than retail outlets and wholesale purchaser-consumer 
facilities on or after December 1, 1994, at any location on or after 
January 1, 1995.

[59 FR 7813, Feb. 16, 1994, as amended at 59 FR 36965, July 20, 1994; 62 
FR 60136, Nov. 6, 1997; 62 FR 68207, Dec. 31, 1997; 66 FR 67106, Dec. 
28, 2001; 71 FR 74570, Dec. 15, 2005; 71 FR 8972, 8985, Feb. 22, 2006; 
71 FR 26420, May 5, 2006; 71 FR 26701, May 8, 2006]



Sec. 80.79  Liability for violations of the prohibited activities.

    (a) Persons liable. Where the gasoline contained in any storage tank 
at any facility owned, leased, operated, controlled or supervised by any 
refiner, importer, oxygenate blender, carrier, distributor, reseller, 
retailer, or wholesale purchaser-consumer is found in violation of the 
prohibitions described in Sec. 80.78(a), the following persons shall be 
deemed in violation:
    (1) Each refiner, importer, oxygenate blender, carrier, distributor, 
reseller, retailer, or wholesale purchaser-consumer who owns, leases, 
operates, controls or supervises the facility where the violation is 
found;
    (2) Each refiner or importer whose corporate, trade, or brand name, 
or whose marketing subsidiary's corporate, trade, or brand name, appears 
at the facility where the violation is found;
    (3) Each refiner, importer, oxygenate blender, distributor, and 
reseller who manufactured, imported, sold, offered for sale, dispensed, 
supplied, offered for supply, stored, transported, or caused the 
transportation of any gasoline which is in the storage tank containing 
gasoline found to be in violation; and
    (4) Each carrier who dispensed, supplied, stored, or transported any 
gasoline which is in the storage tank containing gasoline found to be in 
violation, provided that EPA demonstrates, by reasonably specific 
showings by direct or circumstantial evidence, that the carrier caused 
the violation.
    (5) Notwithstanding the provisions in paragraphs (a)(1) through 
(a)(4) of this section: (i) Only a retailer or wholesale purchaser-
consumer shall be deemed in violation for combining gasolines in a 
manner that is inconsistent with Sec. 80.78(a)(8)(ii) or (iii), or for 
gasoline which does not comply with the VOC minimum standard under Sec. 
80.41 after the retailer or wholesale purchaser-consumer combines or 
causes the combining of compliant gasolines in a manner inconsistent 
with Sec. 80.78(a)(8)(ii) or (iii);
    (ii) No person shall be deemed in violation for gasoline which does 
not comply with the VOC minimum standard under Sec. 80.41 where the 
non-compliance is solely due to the combining of compliant gasolines by 
a retailer or wholesale purchaser-consumer in a manner that is 
consistent with Sec. 80.78(a)(8)(ii) and (iii).
    (b) Defenses for prohibited activities. (1) In any case in which a 
refiner, importer, oxygenate blender, carrier, distributor, reseller, 
retailer, or wholesale purchaser-consumer would be in violation under 
paragraph (a) of this section, it shall be deemed not in violation if it 
can demonstrate:
    (i) That the violation was not caused by the regulated party or its 
employee or agent;
    (ii) That product transfer documents account for all of the gasoline 
in the storage tank found in violation and indicate that the gasoline 
met relevant requirements; and

[[Page 729]]

    (iii)(A) That it has conducted a quality assurance sampling and 
testing program, as described in paragraph (c) of this section; except 
that
    (B) A carrier may rely on the quality assurance program carried out 
by another party, including the party that owns the gasoline in 
question, provided that the quality assurance program is carried out 
properly.
    (2)(i) Where a violation is found at a facility which is operating 
under the corporate, trade or brand name of a refiner, that refiner must 
show, in addition to the defense elements required by paragraph (b)(1) 
of this section, that the violation was caused by:
    (A) An act in violation of law (other than the Act or this part), or 
an act of sabotage or vandalism;
    (B) The action of any reseller, distributor, oxygenate blender, 
carrier, or a retailer or wholesale purchaser- consumer supplied by any 
of these persons, in violation of a contractual undertaking imposed by 
the refiner designed to prevent such action, and despite periodic 
sampling and testing by the refiner to ensure compliance with such 
contractual obligation; or
    (C) The action of any carrier or other distributor not subject to a 
contract with the refiner but engaged by the refiner for transportation 
of gasoline, despite specification or inspection of procedures and 
equipment by the refiner which are reasonably calculated to prevent such 
action.
    (ii) In this paragraph (b), to show that the violation ``was 
caused'' by any of the specified actions the party must demonstrate by 
reasonably specific showings, by direct or circumstantial evidence, that 
the violation was caused or must have been caused by another.
    (c) Quality assurance program. In order to demonstrate an acceptable 
quality assurance program for reformulated gasoline at all points in the 
gasoline distribution network, other than at retail outlets and 
wholesale purchaser-consumer facilities, a party must present evidence 
of the following.
    (1) Of a periodic sampling and testing program to determine if the 
applicable maximum and/or minimum standards for oxygen, benzene, RVP, or 
VOC emission performance are met. For gasoline subject to the provisions 
in Sec. 80.81, a party is not required to conduct periodic sampling and 
testing to determine compliance with the oxygen minimum standard.
    (2) That on each occasion when gasoline is found in noncompliance 
with one of the requirements referred to in paragraph (c)(1) of this 
section:
    (i) The party immediately ceases selling, offering for sale, 
dispensing, supplying, offering for supply, storing, transporting, or 
causing the transportation of the violating product; and
    (ii) The party promptly remedies the violation (such as by removing 
the violating product or adding more complying product until the 
applicable standards are achieved).
    (3) An oversight program conducted by a carrier under paragraph 
(c)(1) of this section need not include periodic sampling and testing of 
gasoline in a tank truck operated by a common carrier, but in lieu of 
such tank truck sampling and testing the common carrier shall 
demonstrate evidence of an oversight program for monitoring compliance 
with the requirements of Sec. 80.78 relating to the transport or 
storage of gasoline by tank truck, such as appropriate guidance to 
drivers on compliance with applicable requirements and the periodic 
review of records normally received in the ordinary course of business 
concerning gasoline quality and delivery.

[38 FR 1255, Jan. 10, 1973, as amended at 62 FR 68207, Dec. 31, 1997; 71 
FR 8973, 8985, Feb. 22, 2006; 71 FR 26420, May 5, 2006; 71 FR 26701, May 
8, 2006; 71 FR 27533, May 11, 2006]



Sec. 80.80  Penalties.

    (a) Any person that violates any requirement or prohibition of 
subpart D, E, or F of 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 
each such violation and the amount of economic benefit or savings 
resulting from each such violation.
    (b) Any violation of a standard for average compliance during any 
averaging period, or for per-gallon compliance for any batch of 
gasoline, shall constitute a separate violation for each and every 
standard that is violated.

[[Page 730]]

    (c) Any violation of any standard based upon a multi-day averaging 
period shall constitute a separate day of violation for each and every 
day in the averaging period. Any violation of any credit creation or 
credit transfer requirement shall constitute a separate day of violation 
for each and every day in the averaging period.
    (d)(1)(i) Any violation of any per- gallon standard or of any per-
gallon minimum or per-gallon maximum, other than the standards specified 
in paragraph (e) of this section, shall constitute a separate day of 
violation for each and every day such gasoline giving rise to such 
violations remains any place in the gasoline distribution system, 
beginning on the day that the gasoline that violates such per-gallon 
standard is produced or imported and distributed and/or offered for 
sale, and ending on the last day that any such gasoline is offered for 
sale or is dispensed to any ultimate consumer for use in any motor 
vehicle; unless
    (ii) The violation is corrected by altering the properties and 
characteristics of the gasoline giving rise to the violations and any 
mixture of gasolines that contains any of the gasoline giving rise to 
the violations such that the said gasoline or mixture of gasolines has 
the properties and characteristics that would have existed if the 
gasoline giving rise to the violations had been produced or imported in 
compliance with all per-gallon standards.
    (2) For the purposes of this paragraph (d), the length of time the 
gasoline in question remained in the gasoline distribution system shall 
be deemed to be twenty-five days; unless the respective party or EPA 
demonstrates by reasonably specific showings, by direct or 
circumstantial evidence, that the gasoline giving rise to the violations 
remained any place in the gasoline distribution system for fewer than or 
more than twenty-five days.
    (e)(1) Any reformulated gasoline that is produced or imported and 
offered for sale and for which the requirements to determine the 
properties and characteristics under Sec. 80.65(f) is not met, or any 
conventional gasoline for which the refiner or importer does not sample 
and test to determine the relevant properties, shall be deemed:
    (i)(A) Except as provided in paragraph (e)(1)(i)(B) of this section 
to have the following properties:

Sulfur content--970 ppm
Benzene content--5 vol %
RVP (summer)--11 psi
50% distillation--250 [deg]F
90% distillation--375 [deg]F
Oxygen content--0 wt %
Aromatics content--50 vol %
Olefins content--26 vol %

    (B) To have the following properties in paragraph (e)(1)(i)(A) of 
this section unless the respective party or EPA demonstrates by 
reasonably specific showings, by direct or circumstantial evidence, 
different properties for the gasoline giving rise to the violations; and
    (ii) In the case of reformulated gasoline, to have been designated 
as meeting all applicable standards on a per-gallon basis.
    (2) For the purposes of paragraph (e)(1) of this section, any 
refiner or importer that fails to meet the independent analysis 
requirements of Sec. 80.65(f) may not use the results of sampling and 
testing that is carried out by that refiner or importer as direct or 
circumstantial evidence of the properties of the gasoline giving rise to 
the violations, unless this failure was not caused by the refiner or 
importer.
    (f) Any violation of any affirmative requirement or prohibition not 
included in paragraph (c) or (d) of this section shall constitute a 
separate day of violation for each and every day such affirmative 
requirement is not properly accomplished, and/or for each and every day 
the prohibited activity continues. For those violations that may be 
ongoing under subparts D, E, and F of this part, each and every day the 
prohibited activity continues shall constitute a separate day of 
violation.



Sec. 80.81  Enforcement exemptions for California gasoline.

    (a)(1) The requirements of subparts D, E, F, and J of this part are 
modified in accordance with the provisions contained in this section in 
the case of California gasoline.
    (2) For purposes of this section, ``California gasoline'' means any 
gasoline that is sold, intended for sale, or

[[Page 731]]

made available for sale as a motor vehicle fuel in the State of 
California and that:
    (i) Is manufactured within the State of California;
    (ii) Is imported into the State of California from outside the 
United States; or
    (iii) Is imported into the State of California from inside the 
United States and that is manufactured at a refinery that does not 
produce reformulated gasoline for sale in any covered area outside the 
State of California.
    (b)(1) Any refiner or importer of gasoline that is sold, intended 
for sale, or made available for sale as a motor fuel in the State of 
California is, with regard to such gasoline, exempt from the compliance 
survey provisions contained in Sec. 80.68.
    (2) Any refiner or importer of California gasoline is, with regard 
to such gasoline, exempt from the independent analysis requirements 
contained in Sec. 80.65(f).
    (3) Any refiner, importer, or oxygenate blender of California 
gasoline that elects to meet any benzene content, oxygen content, or 
toxics emission reduction standard specified in Sec. 80.41 on average 
for any averaging period specified in Sec. 80.67 that is in part before 
March 1, 1996, and in part subsequent to such date, shall, with regard 
to such gasoline that is produced or imported prior to such date, 
demonstrate compliance with each of the standards specified in Sec. 
80.41 for each of the following averaging periods in lieu of those 
specified in Sec. 80.67:
    (i) January 1 through December 31, 1995; and
    (ii) March 1, 1995, through February 29, 1996.
    (4) The compliance demonstration required by paragraph (b)(3)(ii) of 
this section shall be submitted no later than May 31, 1996, along with 
the report for the first quarter of 1996 required to be submitted under 
Sec. 80.75(a)(1)(i).
    (c) Any refiner, importer, or oxygenate blender of California 
gasoline that is manufactured or imported subsequent to March 1, 1996 
and that meets the requirements of the California Phase 2 or Phase 3 
reformulated gasoline regulations, as set forth in Title 13, California 
Code of Regulations, section 2250 et seq. (May 1, 2003), is with regard 
to such gasoline, exempt from the following requirements (in addition to 
the requirements specified in paragraph (b) of this section:
    (1) The parameter value reconciliation requirements contained in 
Sec. 80.65(e)(2);
    (2) The designation of gasoline requirements contained in Sec. 
80.65(d), except in the case of RBOB that is designated as ``any 
renewable oxygenate,'' ``non-VOC controlled renewable ether only'', or 
``renewable ether only'';
    (3) The reformulated gasoline and RBOB compliance requirements 
contained in Sec. 80.65(c);
    (4) [Reserved]
    (5) The annual compliance audit requirements contained in Sec. 
80.65(h), except where such audits are required with regard to the 
renewable oxygenate requirements contained in Sec. 80.83;
    (6) The downstream oxygenate blending requirements contained in 
Sec. 80.69, except where such requirements apply to the renewable 
oxygenate requirements contained in Sec. 80.83;
    (7) The record keeping requirements contained in Sec. Sec. 80.74 
and 80.104, except that records required to be maintained under Title 
13, California Code of Regulations, section 2270, shall be maintained 
for a period of five years from the date of creation and shall be 
delivered to the Administrator or to the Administrator's authorized 
representative upon request;
    (8) The reporting requirements contained in Sec. Sec. 80.75 and 
80.105;
    (9) The product transfer documentation requirements contained in 
Sec. 80.77; and
    (10) The compliance attest engagement requirements contained in 
subpart F of this part, except where such requirements apply to the 
renewable oxygenate requirements contained in Sec. 80.83.
    (d) Any refiner or importer that produces or imports gasoline that 
is sold, intended for sale, or made available for sale as a motor 
vehicle fuel in the State of California subsequent to March 1, 1996, 
shall demonstrate compliance with the standards specified in

[[Page 732]]

Sec. Sec. 80.41 and 80.90 by excluding the volume and properties of 
such gasoline from all conventional gasoline and reformulated gasoline 
that it produces or imports that is not sold, intended for sale, or made 
available for sale as a motor vehicle fuel in the State of California 
subsequent to such date. The exemption provided in this section does not 
exempt any refiner or importer from demonstrating compliance with such 
standards for all gasoline that it produces or imports.
    (e)(1) The exemption provisions contained in paragraphs (b)(2), 
(b)(3), (c), and (f) of this section shall not apply under the 
circumstances set forth in paragraphs (e)(2) and (e)(3) of this section.
    (2) [Reserved]
    (3)(i) Such exemption provisions shall not apply to any refiner or 
importer of California gasoline who has been assessed a civil, criminal 
or administrative penalty for a violation of subpart D, E or F of this 
part or for a violation of the California Phase 2 reformulated gasoline 
regulations set forth in Title 13, California Code of Regulations, 
sections 2260 et seq., effective 90 days after the date of final agency 
or district court adjudication of such penalty assessment.
    (ii) Any refiner or importer subject to the provisions of paragraph 
(e)(3)(i) of this section may submit a petition to the Administrator for 
relief, in whole or in part, from the applicability of such provisions, 
for good cause. Good cause may include a showing that the violation for 
which a penalty was assessed was not a substantial violation of the 
Federal California reformulated gasoline regulations.
    (f) In the case of any gasoline that is sold, intended for sale, or 
made available for sale as a motor vehicle fuel in the State of 
California subsequent to March 1, 1996, any person that manufactures, 
sells, offers for sale, dispenses, supplies, offers for supply, stores, 
transports, or causes the transportation of such gasoline is, with 
regard to such gasoline, exempt from the following prohibited activities 
provisions:
    (1) The oxygenated fuels provisions contained in Sec. 
80.78(a)(1)(iii);
    (2) The product transfer provisions contained in Sec. 
80.78(a)(1)(iv);
    (3) The oxygenate blending provisions contained in Sec. 
80.78(a)(7); and
    (4) The segregation of simple and complex model certified gasoline 
provision contained in Sec. 80.78(a)(9).
    (g)(1) Any refiner that operates a refinery located outside the 
State of California at which California gasoline is produced (as defined 
in paragraph (a)(2)(ii) or (iii) of this section) is produced shall, 
with regard to such gasoline, provide to any person to whom custody or 
title of such gasoline has transferred, and each transferee shall 
provide to any subsequent transferee, documents which include the 
following information:
    (i) The name and address of the transferor;
    (ii) The name and address of the transferee;
    (iii) The volume of gasoline which is being transferred;
    (iv) The location of the gasoline at the time of the transfer;
    (v) The date and time of the transfer;
    (vi) The identification of the gasoline as California gasoline.
    (2) Each refiner and transferee of such gasoline shall maintain 
copies of the product transfer documents required to be provided by 
paragraph (g)(1) of this section for a period of five years from the 
date of creation and shall deliver such documents to the Administrator 
or to the Administrator's authorized representative upon request.
    (h)(1) For the purposes of the batch sampling and analysis 
requirements contained in Sec. 80.65(e)(1) and Sec. 
80.101(i)(1)(i)(A), any refiner or importer of California gasoline may 
use a sampling and/or analysis methodology prescribed in Title 13, 
California Code of Regulations, section 2260 et seq. (as amended July 2, 
1996), in lieu of any applicable methodology specified in Sec. 80.46, 
with regards to:
    (i) Such gasoline; or
    (ii) That portion of its gasoline produced or imported for use in 
other areas of the United States, provided that:
    (A) The gasoline must be produced by a refinery that is located in 
the state of California that produces California

[[Page 733]]

gasoline, or imported into California from outside the United States as 
California gasoline;
    (B) The gasoline must be classified as conventional gasoline upon 
exportation from the California; and
    (C) The refiner or importer must correlate the results from the 
applicable sampling and/or analysis methodology prescribed in Title 13, 
California Code of Regulations, section 2250 et seq. (May 1, 2003) with 
the method specified in Sec. 80.46, and such correlation must be 
adequately demonstrated to EPA upon request.
    (2) Nothwithstanding the requirements of Sec. 80.65(e)(1) regarding 
when the properties of a batch of reformulated gasoline must be 
determined, a refiner of California gasoline may determine the 
properties of gasoline as specified under Sec. 80.65(e)(1) at off site 
tankage provided that:
    (i) The samples are properly collected under the terms of a current 
and valid protocol agreement between the refiner and the California Air 
Resources Board with regard to sampling at the off site tankage and 
consistent with the requirements prescribed in Title 13, California Code 
of Regulations, section 2250 et seq. (May 1, 2003); and
    (ii) The refiner provides a copy of the protocol agreement to EPA 
upon request.

[59 FR 7813, Feb. 16, 1994, as amended at 59 FR 36965, July 20, 1994; 59 
FR 39289, Aug. 2, 1994; 59 FR 60715, Nov. 28, 1994; 63 FR 34825, June 
26, 1998; 64 FR 49997, Sept. 15, 1999; 66 FR 17263, Mar. 29, 2001; 70 FR 
75920, Dec. 21, 2005; 70 FR 74570, Dec. 15, 2005; 71 FR 8973, Feb. 22, 
2006; 71 FR 26701, May 8, 2006]

    Effective Date Note: At 59 FR 39289, Aug. 2, 1994, Sec. 80.81 was 
amended by revising paragraphs (c)(2), (c)(5), (c)(6), and (c)(10) 
effective September 1, 1994. At 59 FR 60715, Nov. 28, 1994, the 
amendment was stayed effective September 13, 1994. At 70 FR 74570, Dec. 
15, 2005, Sec. 80.81 was amended by revising paragraphs (c)(2), (c)(5), 
(c)(6), and (c)(10); however, the amendment could not be incorporated 
because those paragraphs are stayed.



Sec. 80.82  Butane blending.

    A refiner for any refinery that produces gasoline by blending butane 
with conventional gasoline or reformulated gasoline or RBOB may meet the 
sampling and testing requirements of subparts D and E of this part as 
follows:
    (a) Any refinery that blends butane for which the refinery has 
documents from the butane supplier which demonstrate that the butane is 
commercial grade, as defined in paragraph (c) of this section, may 
demonstrate compliance with the standards in subparts D and E of this 
part based on the properties specified in paragraph (c) of this section, 
or the properties specified by the butane supplier.
    (b)(1) Any refiner that blends butane for which the refiner has 
documents from the butane supplier which demonstrate that the butane is 
non-commercial grade, as defined in paragraph (d) of this section, may 
demonstrate compliance with the standards in subparts D and E of this 
part based on the properties specified in paragraph (d) of this section, 
or the properties specified by the butane supplier, provided that the 
refinery:
    (i) Conducts a quality assurance program of sampling and testing the 
butane obtained from each separate butane supplier which demonstrates 
that the butane has the properties specified in paragraph (d) of this 
section; and
    (ii) The frequency of sampling and testing for the butane received 
from each butane supplier must be one sample for every 500,000 gallons 
of butane received, or one sample every three months, whichever is more 
frequent.
    (2) Where test results indicate the butane does not meet the 
requirements in paragraph (b)(1) of this section, the refiner may:
    (i) Blend the butane with conventional gasoline, or reformulated 
gasoline that has been downgraded to conventional gasoline, provided 
that the equivalent emissions performance of the butane batch, as 
determined using the provisions in Sec. 80.101(g)(3), meets the 
refinery's standards under Sec. 80.101;
    (ii) Blend the butane with reformulated gasoline or RBOB, provided 
that the final batch of butane blended with reformulated gasoline or 
RBOB meets the per-gallon standards in Sec. 80.41, as determined using 
the test methods in Sec. 80.46.
    (c) Commercial grade butane is defined as butane for which test 
results demonstrate that the butane is 95% pure and has the following 
properties:

olefins <=1.0 vol%

[[Page 734]]

aromatics <=2.0 vol%
benzene <=0.03 vol%
sulfur <=140 ppm until December 31, 2003; <=120 ppm in 2004; <=30 ppm 
beginning January 1, 2005 and thereafter

    (d) Non-commercial grade butane is defined as butane for which test 
results demonstrate the butane has the following properties:

olefins <=10.0 vol%
aromatics <=2.0 vol%
benzene <=0.03 vol%
sulfur <=140 ppm until December 31, 2003; <=120 ppm in 2004; <=30 ppm 
beginning January 1, 2005 and thereafter

    (e)(1) When butane is blended with conventional gasoline under this 
section during the period May 1 through September 15, the refiner shall 
demonstrate through sampling and testing, using the test method for Reid 
vapor pressure in Sec. 80.46, that each batch of conventional gasoline 
blended with butane meets the volatility standards specified in Sec. 
80.27.
    (2) Butane may not be blended with any reformulated gasoline or RBOB 
during the period April 1 through September 30, or with any reformulated 
gasoline or RBOB designated as VOC-controlled, under this section.
    (f) When butane is blended with conventional gasoline or 
reformulated gasoline or RBOB under this section, product transfer 
documents which accompany the gasoline blended with butane must comply 
with all of the requirements of Sec. 80.77 or Sec. 80.106, as 
appropriate.
    (g) Butane blended with reformulated gasoline or RBOB or 
conventional gasoline during a period of up to one month may be included 
in a single batch for purposes of reporting to EPA, however, commercial 
grade butane and non-commercial grade butane must be reported as 
separate batches.
    (h) Where a refiner chooses to include butane blended with gasoline 
in the refinery's annual average compliance calculations:
    (1) In the case of butane blended with conventional gasoline, the 
equivalent emissions performance of the butane must be calculated in 
accordance with the provisions of Sec. 80.101(g)(3). For purposes of 
this paragraph (i)(1), the property values in Sec. 80.82(c) or (d), as 
appropriate, may be used;
    (2) In the case of butane blended with reformulated gasoline or 
RBOB, compliance with the reformulated gasoline standards may not be 
demonstrated using the provisions of this section;
    (3) All butane blended into gasoline during the annual averaging 
period must be included in annual average compliance calculations for 
the refinery.

[70 FR 74570, Dec. 15, 2005]



Sec. 80.83  Renewable oxygenate requirements.

    (a) Definition of renewable oxygenate. For purposes of subparts D 
and F of this part, renewable oxygenate is defined as provided in this 
paragraph (a).
    (1) In the case of oxygenate added to reformulated gasoline or RBOB 
that is not designated as VOC-controlled or that is not subject to the 
additional requirements associated with an extended non-commingling 
season pursuant to Sec. 80.83(i), renewable oxygenate shall be:
    (i) An oxygenate that is derived from non-fossil fuel feedstocks; or
    (ii) An ether that is produced using an oxygenate that is derived 
from non-fossil fuel feedstocks.
    (2) In the case of oxygenate added to reformulated gasoline or RBOB 
that is designated as VOC-controlled or that is subject to the 
additional requirements associated with an extended non-commingling 
season pursuant to Sec. 80.83(i), renewable oxygenate shall be an ether 
that meets the requirements of paragraph (a)(1)(ii) or (a)(3) of this 
section.
    (3) An oxygenate other than those ethers specified in paragraphs 
(a)(1) or (a)(2) of this section may be considered a renewable oxygenate 
if the Administrator approves a petition to that effect. The 
Administrator may approve such a petition if it is demonstrated to the 
satisfaction of the Administrator that the oxygenate does not cause 
volatility increases in gasoline that are non-linear in nature (i.e., a 
non-linear vapor pressure blending curve). The Administrator may approve 
a petition subject to any appropriate conditions or limitations.
    (4)(i) Oxygenate shall be renewable only if the refiner, importer, 
or oxygenate blender who uses the oxygenate

[[Page 735]]

is able to establish in the form of documentation that the oxygenate was 
produced from a non-fossil fuel feedstock.
    (ii)(A) Any person who produces renewable oxygenate, as defined in 
paragraph (a)(1) of this section, or who stores, transports, transfers, 
or sells such renewable oxygenate, and where such renewable oxygenate is 
intended to be used in the production of gasoline, shall maintain 
documents that state the renewable source of the oxygenate, and shall 
supply to any transferee of the oxygenate documents which state the 
oxygenate is from a renewable source.
    (B) Any person who imports oxygenate that is represented by the 
importer to be renewable oxygenate, as defined in paragraph (a) of this 
section, shall maintain documents, obtained from the person who produced 
the oxygenate, that include a certification signed by the owner or chief 
executive officer of the company that produced the oxygenate that 
states:
    (1) The nature of the feedstock for the oxygenate; and
    (2) A description of the manner in which the oxygenate meets the 
renewable definition under paragraph (a) of this section.
    (iii) No person may represent any oxygenate as renewable unless the 
oxygenate meets the renewable definition under paragraph (a) of this 
section.
    (5) For purposes of this section, an oxygenate shall be considered 
to be derived from non-fossil fuel feedstocks only if the oxygenate is:
    (i) Derived from a source other than petroleum, coal, natural gas, 
or peat; or
    (ii) Derived from a product:
    (A) That was produced using petroleum, coal, natural gas, or peat 
through a substantial transformation of the fossil fuel;
    (B) When the product was initially produced, it was not commonly 
used to generate energy (e.g. automobile tires); and
    (C) The product was sold or transferred for a use other than energy 
generation, and was later treated as a waste product.
    (b) Renewable oxygenate standard. (1) The reformulated gasoline and 
reformulated gasoline produced using RBOB that is produced by any 
refiner at each refinery, or is imported by any importer, shall contain 
a volume of renewable oxygenate such that the reformulated gasoline and 
reformulated gasoline produced using RBOB, on average, has an oxygen 
content from such renewable oxygenate that is equal to or greater than 
0.30 wt% for the period of December 1, 1994 through December 31, 1995, 
and 0.60 wt% beginning on January 1, 1996.
    (2) The averaging period for the renewable oxygenate standard 
specified in paragraph (b)(1) of this section shall be:
    (i) Each calendar year; except that
    (ii)Any reformulated gasoline and RBOB that is produced or imported 
prior to January 1, 1995 shall be averaged with reformulated gasoline 
and RBOB produced or imported during 1995.
    (3)(i) The oxygenate used to meet the standard under paragraph 
(b)(1) of this section may also be used to meet any oxygen standard 
under Sec. 80.41; except that
    (ii) The renewable oxygenate added by a downstream oxygenate blender 
shall not be used by any refiner or importer to meet the oxygen standard 
under Sec. 80.41, except through the transfer of oxygen credits.
    (c) Downstream oxygenate blending using renewable oxygenate. (1) In 
the case of any refiner that produces RBOB, or any importer that imports 
RBOB, the oxygenate that is blended with the RBOB may be included with 
the refiner's or importer's compliance calculations under paragraph (d) 
of this section only if:
    (i) The oxygenate meets the applicable renewable oxygenate 
definition under paragraph (a) of this section; and
    (ii) The refiner or importer meets the downstream oxygenate blending 
oversight requirements specified in Sec. Sec. 80.69(a)(6) and (7); or
    (iii)(A) In the case of RBOB designated for ``any renewable 
oxygenate'' the refiner or importer assumes that ethanol will be blended 
with the RBOB;
    (B) In the case of RBOB designated for ``renewable ether only'' or 
``non-VOC controlled renewable ether only ``, the refiner or importer 
assumes that

[[Page 736]]

ETBE will be blended with the RBOB; and
    (C) In the case of ``any renewable oxygenate,'' ``non-VOC controlled 
renewable ether only'' and ``renewable ether only RBOB,'' the refiner or 
importer assumes that the volume of oxygenate added will be such that 
the resulting reformulated gasoline will have an oxygen content of 2.0 
wt%.
    (2)(i) No person may combine any oxygenate with RBOB designated as 
``any renewable oxygenate'' unless the oxygenate meets the criteria 
specified in paragraph (a) of this section.
    (ii) No person may combine any oxygenate with RBOB designated as 
``renewable ether only'' or ``non-VOC controlled renewable ether only'' 
unless the oxygenate meets the criteria specified in paragraph (a) of 
this section.
    (d) Compliance calculation. (1) Any refiner for each of its 
refineries, and any importer shall, for each averaging period, determine 
compliance with the renewable oxygenate standard by calculating:
    (i) Prior to January 1, 1996, renewable oxygen compliance total 
using the following formula:
[GRAPHIC] [TIFF OMITTED] TR02AU94.000

    (ii) Beginning on January 1, 1996, the renewable oxygen compliance 
total using the following formula:
[GRAPHIC] [TIFF OMITTED] TR02AU94.001

where

CTro = the compliance total for renewable oxygen
Vi = the volume of reformulated gasoline or RBOB batch i
n = the number of batches of reformulated gasoline and RBOB produced or 
imported during the averaging period

    (iii) The renewable oxygen actual total using the following formula:
    [GRAPHIC] [TIFF OMITTED] TR02AU94.002
    
where

ATro = the actual total for renewable oxygen
Vi = the volume of gasoline or RBOB batch i
ROi = the oxygen content, in wt%, in the form of renewable 
oxygenate of gasoline or RBOB batch i
n = the number of batches of gasoline or RBOB produced or imported 
during the averaging period

    (iv) Compare the renewable oxygen actual total with the renewable 
oxygen compliance total.
    (2)(i) The actual total must be equal to or greater than the 
compliance totals to achieve compliance, subject to the credit transfer 
provisions of paragraph (e) of this section.
    (ii) If the renewable oxygen actual total is less than the renewable 
oxygen compliance total, renewable oxygen credits must be obtained from 
another refinery or importer in order to achieve compliance.
    (iii) The total number of renewable oxygen credits required to 
achieve compliance is calculated by subtracting the renewable oxygen 
actual total from the renewable oxygen compliance total.
    (iv) If the renewable oxygen actual total is greater than the 
renewable oxygen compliance total, renewable oxygen credits are 
generated.
    (v) The total number of renewable oxygen credits which may be traded 
to a refiner for a refinery, or to another importer, is calculated by 
subtracting the renewable oxygen compliance total from the renewable 
oxygen actual total.
    (e) Credit transfers. Compliance with the renewable oxygenate 
standard specified in paragraph (b)(1) of this section may be achieved 
through the transfer of renewable oxygen credits, provided that the 
credits meet the criteria specified in Sec. Sec. 80.67(h)(1) (i) 
through (iv) and Sec. Sec. 80.67(h) (2) and (3).
    (f) Recordkeeping. Any refiner or importer, or any oxygenate blender 
who blends oxygenate with any RBOB designated as ``any renewable 
oxygenate,'' ``non VOC controlled renewable ether only'' or ``renewable 
ether only'' shall for a period of five years maintain the records 
specified in this paragraph (f) in a manner consistent with the 
requirements under Sec. 80.74, and deliver such records to the 
Administrator upon request. The records shall contain the following 
information:

[[Page 737]]

    (1)(i) Documents demonstrating the renewable nature and source of 
the oxygenate used, consistent with the requirements of paragraph (a)(3) 
of this section;
    (ii) The volume, type, and purity of any renewable oxygenate used; 
and
    (iii) Product transfer documentation for all renewable oxygenate, 
reformulated gasoline, or RBOB for which the party is the transferor or 
transferee.
    (2) The requirements of this paragraph (f) shall apply in addition 
to the recordkeeping requirements specified in Sec. 80.74(e).
    (g) Reporting requirements. (1) Any refiner for each refinery, or 
any importer, shall for each batch of reformulated gasoline and RBOB 
include in the quarterly reports for reformulated gasoline required by 
Sec. 80.75(a) the total weight percent oxygen and the weight percent 
oxygen attributable to renewable oxygenate contained in the gasoline, or 
contained in the RBOB subsequent to oxygenate blending if allowed under 
paragraph (c) of this section.
    (2) Any refiner for each refinery, or any importer, shall submit to 
the Administrator, with the fourth quarterly report required by Sec. 
80.75(a), a report for all reformulated gasoline and RBOB that was 
produced or imported during the previous calendar year averaging period, 
that includes the following information:
    (i) The total volume of reformulated gasoline and RBOB;
    (ii) The compliance total for renewable oxygen;
    (iii) The actual total for renewable oxygen;
    (iv) The number of renewable oxygen credits generated as a result of 
actual total renewable oxygen being greater than compliance total 
renewable oxygen;
    (v) The number of renewable oxygen credits required as a result of 
actual total renewable oxygen being less than compliance total renewable 
oxygen;
    (vi) The number of renewable oxygen credits transferred to another 
refinery or importer;
    (vii) The number of renewable oxygen credits obtained from another 
refinery or importer; and
    (viii) For any renewable oxygen credits that are transferred from or 
to another refinery or importer, for any such transfer:
    (A) The names, EPA-assigned registration numbers and facility 
identification numbers of the transferor and transferee of the credits;
    (B) The number of renewable oxygen credits that were transferred; 
and
    (C) The date of the transaction.
    (h) Renewable oxygenate requirements for reformulated gasoline used 
in the State of California. (1) Any refiner or importer of California 
gasoline, as defined in Sec. 80.81, shall meet the renewable oxygenate 
standard specified in paragraph (a) of this section for all reformulated 
gasoline or RBOB used in any reformulated gasoline covered area as 
specified in Sec. 80.70.
    (2) Any California gasoline shall be presumed to be used in a 
reformulated gasoline covered area:
    (i)(A) If the gasoline is produced at a refinery that is located 
within a reformulated gasoline covered area; or
    (B) If the gasoline is transported to a facility that is located 
within a reformulated gasoline covered area, or to a facility from which 
gasoline is transported by truck into a reformulated gasoline covered 
area; unless
    (ii) The refiner or importer is able to establish with documentation 
that the gasoline was used outside any reformulated gasoline covered 
area.
    (3) Any California gasoline shall be considered to be designated as 
VOC-controlled (for purposes of paragraph (a)(1) of this section) if the 
Reid vapor pressure of the gasoline, or RBOB subsequent to oxygenate 
blending, is intended to meet a standard of:
    (i) 7.8 psi or less in the case of gasoline intended for use before 
March 1, 1996; or
    (ii) 7.0 psi or less in the case of gasoline intended for use on or 
after March 1, 1996.
    (i) Special provisions for shoulder season. (1) The Governor of any 
State may petition for an extension of the non-commingling season for 
any or all reformulated gasoline covered areas within the State pursuant 
to Sec. 80.70.
    (i) Such petition must satisfy the following criteria:
    (A) Evidence showing an increase in the market share and/or use of

[[Page 738]]

oxygenates which produce commingling-related RVP increases in the 
area(s) that are covered by the petition;
    (B) Evidence demonstrating a pattern of exceedances for the period 
for which the extension is sought, including ozone monitoring data for 
the preceding three(3) years of the reformulated gasoline program;
    (C) An analysis showing that the pattern of ozone exceedances is 
likely to continue even with implementation of other ozone air quality 
control measures and/or programs currently planned by the State; and
    (D) Evidence that the responsible State agency or authority has 
given the public an opportunity for a public hearing and the submission 
of written comments with respect to the petition.
    (ii) Effective data and publication of decision.
    (A) If the Administrator determines that the petition meets the 
requirements of paragraph (i)(1)(i) of this section, to the satisfaction 
of the Administrator, then EPA shall publish a notice in the Federal 
Register announcing its intention to establish the non-commingling 
season as requested by the Governor, and specifying a tentative 
effective date.
    (1) The Administrator shall provide the public with an opportunity 
for a hearing and the submission of written comments.
    (2) The tentative effective date will correspond with the first day 
of the next complete non-commingling season beginning not less than one 
year after receipt of the petition.
    (B) If the Administrator receives adverse comments or information 
demonstrating to the satisfaction of the Administrator that the criteria 
of paragraph (i)(1)(i) of this section have not been met, that the 
tentative effective date is not reasonable, or that other good reasons 
exist to deny the petition, then the Administrator may reject the 
Governor's request for an extended non-commingling season, in whole or 
in part, or may delay the effective date by up to two (2) additional 
years. Absent receipt of such adverse comments or information, EPA shall 
publish a notice in the Federal Register announcing its approval of the 
petition and specifying an effective date for the extended non-
commingling season.
    (2) In the case of any refiner that produces RBOB, or any importer 
that imports RBOB, the oxygenate that is blended with the RBOB may be 
included with the refiner's or importer's compliance calculations under 
paragraph (d) of this section only if:
    (i) The oxygenate meets the applicable renewable oxygenate 
definition under paragraph (a) of this section; and
    (ii) In the case of RBOB designated for ``non VOC controlled ether 
only'' the refiner or importer assumes that ETBE or other oxygenate that 
does not exhibit volatility-related commingling effects when mixed with 
other gasolines and approved by the EPA Administrator under subparagraph 
(a)(3) of this section will be blended with the RBOB and so labels the 
transfer documentation.

[59 FR 39290, Aug. 2, 1994]

    Effective Date Note: At 59 FR 39290, Aug. 2, 1994, Sec. 80.83 was 
added effective September 1, 1994, except for paragraphs (g) and (h), 
which would not become effective until approval had been given by the 
Office of Management and Budget. At 59 FR 60715, Nov. 28, 1994, this 
section was stayed, effective September 13, 1994. At 70 FR 74571, Dec. 
15, 2005, Sec. 80.83 was revised; however, the amendment could not be 
incorporated because the section is stayed.



Sec. 80.84  Treatment of interface and transmix.

    (a) Definitions. For purposes of this section, the following 
definitions apply:
    (1) Interface means a volume of petroleum product generated in a 
pipeline between two adjacent volumes of non-identical petroleum product 
that consists of a mixture of the two adjacent products.
    (2) Transmix means an interface that does not meet the 
specifications for a fuel that can be used or sold, and that is composed 
solely of any combination of:
    (i) Previously certified gasoline (including previously certified 
gasoline blendstocks that become gasoline solely upon the addition of an 
oxygenate);
    (ii) Distillate fuel; or

[[Page 739]]

    (iii) Gasoline blendstocks that are suitable for use as a blendstock 
without further processing.
    (3) Transmix gasoline product, or TGP, means the gasoline or 
gasoline blendstock that is produced when transmix is separated into 
distillate fuel and either gasoline or gasoline blendstock. Gasoline 
blendstock here includes blendstock that becomes gasoline solely upon 
the addition of an oxygenate (such as RBOB).
    (4) Transmix processing facility means any refinery that produces 
TGP from transmix by distillation or other refining processes, but does 
not produce gasoline by processing crude oil.
    (5) Transmix processor means any person who owns, leases, operates, 
controls or supervises a transmix processing facility.
    (6) Transmix blending facility means any facility which produces 
gasoline by blending transmix into gasoline.
    (7) Transmix blender means any person who owns, leases, operates, 
controls or supervises a transmix blending facility.
    (b) Designation of gasoline interface by pipeline operators. (1) 
Gasoline interface mixtures containing the products below shall be 
designated by pipeline operators in the following manner:
    (i) Interface mixtures of reformulated gasoline or RBOB, and 
conventional gasoline shall be designated as conventional gasoline;
    (ii) Interface mixtures of VOC-controlled reformulated gasoline and 
non-VOC-controlled reformulated gasoline shall be designated as non-VOC-
controlled RFG;
    (iii) Interface mixtures of RBOB and reformulated gasoline shall be 
designated as RBOB; and
    (iv) Interface mixtures of reformulated gasoline or RBOB, and 
blendstock shall be designated as blendstock.
    (2) Regardless of gasoline product designation, all gasoline 
containing interface must meet all downstream standards, including but 
not limited to any standards and requirements that apply downstream of 
the refinery in this part and the Clean Air Act.
    (c) Transmix processing--(1) TGP sold without further mixing with 
blendstocks or previously certified gasoline. (i) Where the TGP meets 
all standards and requirements that apply to conventional gasoline 
downstream from the refinery, including but not limited to any standards 
and requirements in this part and the Clean Air Act, and the TGP is 
designated and sold as conventional gasoline, the transmix processor may 
exclude the TGP from compliance calculations for the transmix processing 
facility under this part Subpart E of this part. Except as required in 
paragraph (c)(4) of this section, the transmix processor must either 
include every batch or exclude every batch of this TGP from their 
compliance calculations for each compliance period;
    (ii) Where the TGP is sold as a blendstock, the transmix processor 
must exclude the TGP from compliance calculations. Pursuant to Sec. 
80.101(d)(3), however, TGP which becomes gasoline solely upon the 
addition of an oxygenate must be included in the compliance calculations 
for the transmix processing facility under subpart E of this part.
    (iii) Where the TGP is designated and sold as reformulated gasoline 
or RBOB, the transmix processor must fulfill all requirements and 
standards that apply to a refiner under subpart D of this part and must 
include the reformulated gasoline or RBOB produced from the transmix in 
compliance calculations for the transmix processing facility under 
subpart D of this part.
    (2) TGP blended with blendstocks. Where the transmix processor mixes 
the TGP with blendstock(s) to produce reformulated or conventional 
gasoline or RBOB, the TGP is treated as a blendstock and the transmix 
processor must fulfill all requirements and standards that apply to a 
refiner under subpart D or E of this part, as appropriate, and include 
the gasoline produced in compliance calculations for the transmix 
processing facility under subpart D or E of this part, as appropriate.
    (3) TGP blended with previously certified gasoline. (i) Where the 
TGP meets all the standards and requirements that apply to conventional 
gasoline downstream from the refinery, including but not limited to any 
standards and requirements of this part and the Clean Air Act, and the 
transmix processor mixes the TGP with any previously certified gasoline 
to produce conventional gasoline, the TGP may be

[[Page 740]]

excluded from compliance calculations for the transmix processing 
facility under subpart E of this part. Except as required in paragraph 
(c)(4) of this section, the transmix processor must either include every 
batch or exclude every batch of this TGP from compliance calculations 
for the transmix processing facility for each compliance period.
    (ii) Where the TGP does not meet all standards that apply to 
conventional gasoline downstream from the refinery, including but not 
limited to any standards and requirements of this part and the Clean Air 
Act, and the transmix processor mixes the TGP with any previously 
certified gasoline to produce conventional gasoline, the TGP is treated 
as a blendstock and the transmix processor must fulfill all requirements 
and standards for a refiner under subpart E of this part, for the TGP, 
and include the TGP in the compliance calculations for the transmix 
processing facility under subpart E of this part.
    (iii) The sampling and testing required under paragraph (c)(3)(ii) 
of this section may be met using one of the following methods:
    (A) Sample and test the TGP prior to blending with previously 
certified gasoline to determine the volume and properties of the TGP and 
include each volume of TGP blended with previously certified gasoline as 
a separate batch in compliance calculations for the transmix processing 
facility; or
    (B) Determine the volume and properties of the previously certified 
gasoline prior to blending with the TGP and measure the volume and 
properties of the gasoline subsequent to blending with the TGP. 
Calculate the volume and properties of the TGP by subtracting the volume 
and properties of the previously certified gasoline from the volume and 
properties of the gasoline subsequent to blending, and include each 
volume of TGP blended with previously certified gasoline as a separate 
batch in compliance calculations for the transmix processing facility; 
or
    (C) Comply with the requirements in Sec. 80.101(g)(9).
    (iv) Where the transmix processor mixes the TGP with any previously 
certified gasoline to produce reformulated gasoline or RBOB, the TGP is 
treated as a blendstock and the transmix processor must fulfill all 
requirements and standards for a refiner under subpart D of this part, 
for the TGP, and include the TGP in the compliance calculations for the 
transmix processing facility under subpart D of this part, using the 
procedures in Sec. 80.65(i).
    (4) Additional requirements for conventional gasoline produced with 
transmix containing blendstocks. Notwithstanding paragraphs (c)(1)(i) 
and (c)(3)(i) of this section, if gasoline is produced at a transmix 
processing facility from any transmix containing gasoline blendstocks, 
the transmix processor must include every batch of gasoline produced 
from transmix in compliance calculations for the transmix processing 
facility under subpart E of this part for the entire compliance period.
    (d) Transmix blending. Transmix blenders which fulfill all of the 
requirements in this paragraph (d) are exempt from the requirements and 
standards that apply to a refiner under subparts D and E of this part.
    (1) Transmix may be blended into any previously certified gasoline, 
provided that:
    (i) The endpoint of the final transmix-blended gasoline does not 
exceed 437 degrees Fahrenheit as measured by ASTM standard method D 86-
01\e1\, entitled ``Standard Test Method for Distillation of Petroleum 
Products at Atmospheric Pressure'', which is incorporated by reference. 
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. A 
copy may be obtained from the American Society for Testing and 
Materials, 100 Barr Harbor Dr., West Conshohocken, PA 19428-2959. Copies 
may be inspected at the Air Docket, EPA/DC, EPA West, Room B102, 1301 
Constitution Ave., NW., Washington, DC, 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.htm.;

[[Page 741]]

    (ii) The final transmix-blended gasoline meets all applicable 
downstream standards; and
    (iii) The transmix blender complies with the requirements in 
Sec. Sec. 80.74(b)(10), 80.104(b) and 80.213.
    (2) The transmix blender must maintain and follow a written quality 
assurance program designed to assure that the type and amount of 
transmix blended into previously certified gasoline will not cause 
violations of the applicable standards in paragraph (d)(1) of this 
section. Except as set forth in paragraph (d)(3) of this section, as a 
part of the quality assurance program, transmix blenders shall collect 
samples of gasoline subsequent to blending transmix, and test the 
samples to ensure the end-point temperature of the final transmix-
blended gasoline does not exceed 437 degrees Fahrenheit, at one of the 
following rates:
    (i) In the case of transmix that is blended in a tank, following 
each occasion transmix is blended; or
    (ii) In the case of transmix that is blended by a computer 
controlled in-line blending system, the transmix blender shall collect 
composite samples of gasoline subsequent to blending transmix at a rate 
of not less than twice each calendar month during which transmix is 
blended.
    (3) Any transmix blender may petition EPA for approval of a quality 
assurance program that does not include the minimum sampling and testing 
requirements in paragraph (d)(2) of this section. In order to seek such 
an exemption, the transmix blender shall submit a petition to EPA that 
includes:
    (i) A detailed description of the quality assurance procedures to be 
carried out at each location where transmix is blended into previously 
certified gasoline, including a description of how the transmix blender 
proposes to determine the ratio of transmix that can be blended with 
previously certified gasoline without violating any of the applicable 
standards in paragraph (d)(1) of this section, and a description of how 
the transmix blender proposes to determine that the gasoline produced by 
the transmix blending operation meets the applicable standards.
    (ii) If the transmix is blended by a computer controlled in-line 
blending system, the transmix blender shall also include all of the 
information required by refiners under Sec. 80.65(f)(4)(i)(A).
    (iii) A letter signed by the president, chief operating or chief 
executive officer of the company, or his/her designee, stating that the 
information contained in the submission is true to the best of his/her 
belief must accompany any submission under this paragraph.
    (iv) Transmix blenders who seek an exemption under paragraph (d)(3) 
of this section must comply with any request by EPA for additional 
information or any other requirements that EPA includes as part of the 
exemption. However, they may withdraw their exemption petition or 
approved exemption at any time, upon notice to EPA.
    (v) EPA reserves the right to modify the requirements of an 
exemption under paragraph (d)(3) of this section, in whole or in part, 
at any time, if EPA determines that the transmix blender's operation 
does not effectively or adequately control, monitor or document the end-
point temperature of the gasoline produced, or if EPA determines that 
any other circumstance exists which merits modification of the 
requirements of an exemption. If EPA finds that a transmix blender 
provided false or inaccurate information in any submission required for 
an exemption under this section, upon notification from EPA, the 
transmix blender's exemption will be void ab initio.
    (4) In the event the test results for any sample collected pursuant 
to a quality assurance program indicate the gasoline does not comply 
with any of the applicable standards in paragraph (d)(1) of this 
section, the transmix blender shall:
    (i) Immediately take steps to stop the sale of the gasoline that was 
sampled;
    (ii) Take steps which are reasonably calculated to determine the 
cause of the noncompliance and to prevent future instances of 
noncompliance;
    (iii) Inform EPA of the noncompliance; and
    (iv) If the transmix was blended by a computer controlled in-line 
blending system, increase the rate of sampling and testing to a rate of 
not less than

[[Page 742]]

once per week and continue the increased frequency of sampling and 
testing until the results of ten consecutive samples and tests indicate 
the gasoline complies with applicable standards, at which time the 
sampling and testing may be conducted at the original frequency;
    (5) Any transmix blender who blends transmix into previously 
certified gasoline and who does not meet the requirements under this 
paragraph (d) shall meet all requirements and standards that apply to a 
refiner under subparts D and E of this part, other than this section and 
Sec. Sec. 80.74(b)(10), and 80.104(b).
    (e) The provisions of paragraphs (c) and (d) of this section also 
apply to mixtures of gasoline and distillate fuel:
    (1) Produced by unintentionally combining gasoline and distillate 
fuel in a tank.
    (2) Produced from normal business operations at terminals or 
pipelines, such as gasoline or distillate fuel drained from a tank, or 
drained from piping or hoses used to transfer gasoline or distillate 
fuel to tanks or trucks, or gasoline or distillate fuel discharged from 
a safety relief valve.
    (f) Any transmix processor or transmix blender who adds a feedstock 
to their transmix other than gasoline, distillate fuel or gasoline 
blendstocks from pipeline interface must meet all requirements and 
standards that apply to a refiner under subparts D and E of this part, 
other than this section and Sec. Sec. 80.74(b)(10), and 80.104(b), for 
all gasoline they produce during a compliance period.

[71 FR 31961, June 2, 2006]



Sec. Sec. 80.85-80.89  [Reserved]



                         Subpart E_Anti-Dumping

    Source: 59 FR 7860, Feb. 16, 1994, unless otherwise noted.



Sec. 80.90  Conventional gasoline baseline emissions determination.

    (a) Annual average baseline values. For any facility of a refiner or 
importer of conventional gasoline, the annual average baseline values of 
the facility's exhaust benzene emissions, exhaust toxics emissions, 
NOX emissions, sulfur, olefins and T90 shall be determined 
using the following equation:
[GRAPHIC] [TIFF OMITTED] TR16FE94.012

where

BASELINE = annual average baseline value of the facility,
SUMRBASE = summer baseline value of the facility,
SUMRVOL = summer baseline gasoline volume of the facility, per Sec. 
80.91,
WNTRBASE = winter baseline value of the facility,
WNTRVOL = winter baseline gasoline volume of the facility, per Sec. 
80.91.

    (b) Baseline exhaust benzene emissions--simple model. (1) Simple 
model exhaust benzene emissions of conventional gasoline shall be 
determined using the following equation:

EXHBEN = (1.884 + 0.949 x BZ + 0.113 x (AR - BZ))

where

EXHBEN = exhaust benzene emissions,
BZ = fuel benzene value in terms of volume percent (per Sec. 80.91), 
and
AR = fuel aromatics value in terms of volume percent (per Sec. 80.91).

    (2) The simple model annual average baseline exhaust benzene 
emissions for any facility of a refiner or importer of conventional 
gasoline shall be determined as follows:
    (i) The simple model baseline exhaust benzene emissions shall be 
determined separately for summer and winter using the facility's 
oxygenated individual baseline fuel parameter values for summer and 
winter (per Sec. 80.91), respectively, in the equation specified in 
paragraph (b)(1) of this section.
    (ii) The simple model annual average baseline exhaust benzene 
emissions of the facility shall be determined using the emissions values 
determined in

[[Page 743]]

paragraph (b)(2)(i) of this section in the equation specified in 
paragraph (a) of this section.
    (c) Baseline exhaust benzene emissions--complex model. The complex 
model annual average baseline exhaust benzene emissions for any facility 
of a refiner or importer of conventional gasoline shall be determined as 
follows:
    (1) The summer and winter complex model baseline exhaust benzene 
emissions shall be determined separately using the facility's oxygenated 
individual baseline fuel parameter values for summer and winter (per 
Sec. 80.91), respectively, in the appropriate complex model for exhaust 
benzene emissions described in Sec. 80.45.
    (2) The complex model annual average baseline exhaust benzene 
emissions of the facility shall be determined using the emissions values 
determined in paragraph (c)(1) of this section in the equation specified 
in paragraph (a) of this section.
    (d) Baseline exhaust toxics emissions. The annual average baseline 
exhaust toxics emissions for any facility of a refiner or importer of 
conventional gasoline shall be determined as follows:
    (1) The summer and winter baseline exhaust emissions of benzene, 
formaldehyde, acetaldehyde, 1,3-butadiene, and polycyclic organic matter 
shall be determined using the oxygenated individual baseline fuel 
parameter values for summer and winter (per Sec. 80.91), respectively, 
in the appropriate complex model for each exhaust toxic (per Sec. 
80.45).
    (2) The summer and winter baseline total exhaust toxics emissions 
shall be determined separately by summing the summer and winter baseline 
exhaust emissions of each toxic (per paragraph (d)(1) of this section), 
respectively.
    (3) The annual average baseline exhaust toxics emissions of the 
facility shall be determined using the emissions values determined in 
paragraph (d)(2) of this section in the equation specified in paragraph 
(a) of this section.
    (e) Baseline NOX emissions. The annual average baseline 
NOX emissions for any facility of a refiner or importer of 
conventional gasoline shall be determined as follows:
    (1) The summer and winter baseline NOX emissions shall be 
determined using the baseline individual baseline fuel parameter values 
for summer and winter (per Sec. 80.91), respectively, in the 
appropriate complex model for NOX (per Sec. 80.45).
    (2) The annual average baseline NOX emissions of the 
facility shall be determined using the emissions values determined in 
paragraph (e)(1) of this section in the equation specified in paragraph 
(a) of this section.
    (3) The requirements specified in paragraphs (e) (1) and (2) of this 
section shall be determined separately using the oxygenated and 
nonoxygenated individual baseline fuel parameters, per Sec. 80.91.
    (f) Applicability of Phase I and Phase II models. The requirements 
of paragraphs (d) and (e) of this section shall be determined separately 
for the applicable Phase I and Phase II complex models specified in 
Sec. 80.45.
    (g) Calculation accuracy. Emissions values calculated per the 
requirements of this section shall be determined to four (4) significant 
figures. Sulfur, olefin and T90 values calculated per the requirements 
of this section shall be determined to the same number of decimal places 
as the corresponding value listed in Sec. 80.91(c)(5).

[59 FR 7860, Feb. 16, 1994, as amended at 59 FR 36965, July 20, 1994]



Sec. 80.91  Individual baseline determination.

    (a) Baseline definition. (1) The ``baseline'' or ``individual 
baseline'' of a refinery, refiner or importer, as applicable, shall 
consist of:
    (i) An estimate of the quality, composition and volume of its 1990 
gasoline, or allowable substitute, based on the requirements specified 
in Sec. Sec. 80.91 through 80.93; and
    (ii) Its baseline emissions values calculated per paragraph (f) of 
this section.
    (2)(i) The quality and composition of the 1990 gasoline of a 
refinery, refiner or importer, as applicable, shall be the set of values 
of the following fuel parameters: benzene content; aromatic content; 
olefin content; sulfur content; distillation temperature at 50 and 90 
percent by volume evaporated; percent

[[Page 744]]

evaporated at 200 [deg]F and 300 [deg]F; oxygen content; RVP.
    (ii) A refiner, per paragraph (b)(3)(i) of this section, shall also 
determine the API gravity of its 1990 gasoline.
    (3) The methodology outlined in this section shall be followed in 
determining a baseline value for each fuel parameter listed in paragraph 
(a)(2) of this section.
    (b) Requirements for refiners, blenders and importers--(1) 
Requirements for producers of gasoline and gasoline blendstocks. (i) A 
refinery engaged in the production of gasoline blendstocks from crude 
oil and/or crude oil derivatives, and the subsequent mixing of those 
blendstocks to form gasoline, shall have its baseline fuel parameter 
values determined from Method 1, 2 and/or 3-type data as described in 
paragraph (c) of this section, provided the refinery was in operation 
for at least 6 months in 1990.
    (ii) A refinery which was in operation for at least 6 months in 
1990, was shut down after 1990, and which restarts after June 15, 1994, 
and for which insufficient 1990 and post-1990 data was collected prior 
to January 1, 1995 from which to determine an individual baseline, shall 
have the values listed in paragraph (c)(5) of this section as its 
individual baseline parameters.
    (iii) A refinery which was in operation for less than 6 months in 
1990 shall have the values listed in paragraph (c)(5) of this section as 
its individual baseline parameters.
    (2) Requirements for producers or importers of gasoline blendstocks 
only. A refiner or importer of gasoline blendstocks which did not 
produce or import gasoline in 1990 and which produces or imports post-
1994 gasoline shall have the values listed in paragraph (c)(5) of this 
section as its individual baseline parameters.
    (3) Requirements for purchasers of gasoline and/or gasoline 
blendstocks. (i) A refiner or refinery, as applicable, solely engaged in 
the production of gasoline from gasoline blendstocks and/or gasoline 
which are simply purchased and blended to form gasoline shall have its 
individual baseline determined using Method 1-type data (per paragraph 
(c) of this section) from every batch of 1990 gasoline.
    (ii) If Method 1-type data on every batch of the refiner's or 
refinery's 1990 gasoline does not exist, that refiner or refinery shall 
have the values listed in paragraph (c)(5) of this section as its 
individual baseline parameters.
    (4) Requirements for importers of gasoline and/or gasoline 
blendstocks. (i) An importer of gasoline shall determine an individual 
baseline value for each fuel parameter listed in paragraph (a)(2) of 
this section using Method 1-type data on every batch of gasoline 
imported by that importer into the United States in 1990.
    (ii) An importer which is also a foreign refiner must determine its 
individual baseline using Method 1, 2 and/or 3-type data (per paragraph 
(c) of this section) if it imported at least 75 percent, by volume, of 
the gasoline produced at its foreign refinery in 1990 into the United 
States in 1990.
    (iii) An importer which cannot meet the criteria of paragraphs 
(b)(4)(i) or (ii) of this section for baseline determination shall have 
the parameter values listed in paragraph (c)(5) of this section as its 
individual baseline parameter values.
    (5) Requirements for exporters of gasoline and/or gasoline 
blendstocks. A refiner shall not include quality or volume data on its 
1990 exports of gasoline blendstocks or gasoline in its baseline 
determination.
    (c) Data types--(1) Method 1-type data. (i) Method 1-type data shall 
consist of quality (composition and property data) and volume records of 
gasoline produced in or shipped from the refinery in 1990, excluding 
exported gasoline. The measured fuel parameter values and volumes of 
batches, or shipments if not batch blended, shall be used except that 
data on produced gasoline which was also shipped shall be included only 
once.
    (ii) Gasoline blendstock which left a facility in 1990 and which 
could become gasoline solely upon the addition of oxygenate shall be 
included in the baseline determination.
    (A) Fuel parameter values of such blendstock shall be accounted for 
as if the gasoline blendstock were blended with ten (10.0) volume 
percent ethanol.
    (B) If the refiner or importer can provide evidence that such 
gasoline

[[Page 745]]

blendstock was not blended per paragraph (c)(1)(ii)(A) of this section, 
and that such gasoline blendstock was blended with another oxygenate or 
a different volume of ethanol, the fuel parameter values of the final 
gasoline (including oxygenate) shall be included in the baseline 
determination.
    (C) If the refiner or importer can provide evidence that such 
gasoline blendstock was not blended per paragraph (c)(1)(ii)(A) or (B) 
of this section, and that such gasoline blendstock was sold with out 
further changes downstream, the fuel parameter values of the original 
product shall be included in the baseline determination.
    (iii) Data on 1990 gasoline purchased or otherwise received, 
including intracompany transfers, shall not be included in the baseline 
determination of a refiner's or importer's facility if the gasoline 
exited the receiving refinery unchanged from its arrival state.
    (2) Method 2-type data. Method 2-type data shall consist of 1990 
gasoline blendstock quality data and 1990 blendstock production records, 
specifically the measured fuel parameter values and volumes of 
blendstock used in the production of gasoline within the refinery. 
Blendstock data shall include volumes purchased or otherwise received, 
including intracompany transfers, if the volumes were blended as part of 
the refiner's or importer's 1990 gasoline. Henceforth in Sec. Sec. 
80.91 through 80.93, ``blendstock(s)'' or ``gasoline blendstock(s)'' 
shall include those products or streams commercially blended to form 
gasoline.
    (3) Method 3-type data. (i) Method 3-type data shall consist of 
post-1990 gasoline blendstock and/or gasoline quality data and 1990 
blendstock and gasoline production records, specifically the measured 
fuel parameter values and volumes of blendstock used in the production 
of gasoline within the refinery. Blendstock data shall include volumes 
purchased or otherwise received, including intracompany transfers, if 
the volumes were blended as part of the refiner's or importer's 1990 
gasoline.
    (ii) In order to use Method 3-type data, the refiner or importer 
must do all of the following:
    (A) Include a detailed discussion comparing its 1990 and post-1990 
refinery operations and all other differences which would cause the 1990 
and post-1990 fuel parameter values to differ; and
    (B) Perform the appropriate calculations so as to adjust for the 
differences determined in paragraph (c)(3)(ii)(A) of this section; and
    (C) Include a narrative, discussing the methodology and reasoning 
for the adjustments made per paragraph (c)(3)(ii)(B) of this section.
    (iii) In order to use post-1990 gasoline data, either of the 
following must be shown for each blendstock-type included in 1990 
gasoline, excluding butane:
    (A) The post-1990 volumetric fraction of a blendstock is within 
()10.0 percent of the volumetric fraction of that 
blendstock in 1990 gasoline. For example, if a 1990 blendstock 
constituted 30 volume percent of 1990 gasoline, this criterion would be 
met if the post-1990 volumetric fraction of the blendstock in post-1990 
gasoline was 27.0-33.0 volume percent.
    (B) The post-1990 volumetric fraction of a blendstock is within 
()2.0 volume percent of the absolute value of the 
1990 volumetric fraction. For example, if a 1990 blendstock constituted 
5 volume percent of 1990 gasoline, this criterion would be met if the 
post-1990 volumetric fraction of the blendstock in post-1990 gasoline 
was 3-7 volume percent.
    (iv) If using post-1990 gasoline data, post-1990 gasoline blendstock 
which left a facility and which could become gasoline solely upon the 
addition of oxygenate shall be included in the baseline determination, 
per the requirements specified in paragraph (c)(1)(ii) of this section.
    (4) Hierarchy of data use. (i) A refiner or importer must determine 
a baseline fuel parameter value using only Method 1-type data if 
sufficient Method 1-type data is available, per paragraph (d)(1)(ii) of 
this section.
    (ii) If a refiner has insufficient Method 1-type data for a baseline 
parameter value determination, it must supplement that data with all 
available Method 2-type data, until it has sufficient data, per 
paragraph (d)(1)(iii) of this section.

[[Page 746]]

    (iii) If a refiner has insufficient Method 1- and Method 2-type data 
for a baseline parameter value determination, it must supplement that 
data with all available Method 3-type data, until it has sufficient 
data, per paragraph (d)(1)(iii) of this section.
    (iv) The protocol for the determination of baseline fuel parameter 
values in paragraphs (c)(4)(i) through (iii) of this section shall be 
applied to each fuel parameter one at a time.
    (5) Anti-dumping statutory baseline. (i) The summer anti-dumping 
statutory baseline shall have the set of fuel parameter values 
identified as ``summer'' in Sec. 80.45(b)(2). The anti-dumping summer 
API gravity shall be 57.4 [deg]API.
    (ii) The winter anti-dumping statutory baseline shall have the set 
of fuel parameter values identified as ``winter'' in Sec. 80.45(b)(2), 
except that winter RVP shall be 8.7 psi. The anti-dumping winter API 
gravity shall be 60.2 API.
    (iii) The annual average anti-dumping statutory baseline shall have 
the following set of fuel parameter values:

Benzene, volume percent--1.60
Aromatics, volume percent--28.6
Olefins, volume percent--10.8
RVP, psi--8.7
T50, degrees F--207
T90, degrees F--332
E200, percent--46
E300, percent--83
Sulfur, ppm--338
API Gravity, [deg]API--59.1

    (iv) The annual average anti-dumping statutory baseline shall have 
the following set of emission values:

Exhaust benzene emissions, simple model--6.45
Exhaust benzene emissions, complex model--33.03 mg/mile
Exhaust toxics emissions, Phase I--50.67 mg/mile
Exhaust toxics emissions, Phase II--104.5 mg/mile
NOX emissions, Phase I--714.4 mg/mile
NOX emissions, Phase II--1461. mg/mile

    (d) Data collection and testing requirements--(1) Minimum sampling 
requirements--(i) General requirements. (A) Data shall have been 
obtained for at least three months of the refiner's or importer's 
production of summer gasoline and at least three months of its 
production of winter gasoline. When method 1 per batch RVP data is 
available, a month is considered equivalent to 4 weeks of seasonal data.
    (1) Method 1, per batch, actual RVP data will be used to define that 
batch as either summer fuel or winter fuel. Summer fuel is defined as 
fuel produced and intended for sale to satisfy Federal summer volatility 
standards. When such per batch actual RVP data is not available, data is 
allocated per month as follows. A summer month is defined as any month 
during which more than 50 percent (by volume) of the gasoline produced 
by a refiner met the Federal summer gasoline volatility requirements. 
Winter shall be any month which could not be considered a summer month 
under this definition.
    (2) The three months which compose the summer and the winter data do 
not have to be consecutive nor within the same year.
    (3) If, in 1990, a refiner marketed all of its gasoline only in an 
area or areas which experience no seasonal changes relative to gasoline 
requirements, e.g., Hawaii, only 3 months of data are required.
    (B) Once the minimum sampling requirements have been met, data 
collection may cease. Additional data may only be included for the 
remainder of the calendar year in which the minimum sampling 
requirements were met. In any case, all data collected through the date 
of collection of the last data point included in the determination of a 
baseline fuel parameter value must be utilized in the baseline 
determination of that fuel parameter.
    (C) Less than the minimum requirements specified in paragraph (d)(1) 
of this section may be allowed, upon petition and approval (per Sec. 
80.93), if it can be shown that the available data is sufficient in 
quality and quantity to use in the baseline determination.
    (ii) Method 1 sampling requirements. At least half of the batches, 
or shipments if not batch blended, in a calendar month shall have been 
sampled over a minimum of six months in 1990.
    (iii) Method 2 sampling requirements. (A) Continuous blendstock 
streams shall have been sampled at least weekly over a minimum of six 
months in 1990.
    (B) For blendstocks produced on a batch basis, at least half of all 
batches

[[Page 747]]

of a single blendstock type produced in a calendar month shall have been 
sampled over a minimum of six months in 1990.
    (iv) Method 3 sampling requirements--(A) Blendstock data. (1) Post-
1990 continuous blendstock streams shall have been sampled at least 
weekly over a minimum of six months.
    (2) For post-1990 blendstocks produced on a batch basis, at least 
half of all batches of a single blendstock type produced in a calendar 
month shall have been sampled over a minimum of six months.
    (B) Gasoline data. At least half of the post-1990 batches, or 
shipments if not batch blended, in a calendar month shall have been 
sampled over a minimum of six months in order to use post-1990 gasoline 
data.
    (2) Sampling beyond today's date. The necessity and actual 
occurrence of data collection after today's date must be shown.
    (3) Negligible quantity sampling. Testing of a blendstock stream for 
a fuel parameter listed in this paragraph (d)(3) is not required if the 
refiner can show that the fuel parameter exists in the stream at less 
than or equal to the amount, on average, shown in this paragraph (d)(3) 
for that fuel parameter. Any fuel parameter shown to exist in a refinery 
stream in negligible amounts shall be assigned a value of 0.0:

Aromatics, volume percent--1.0
Benzene, volume percent--0.15
Olefins, volume percent--1.0
Oxygen, weight percent--0.2
Sulfur, ppm--30.0

    (4) Sample compositing. (i) Samples of gasoline or blendstock which 
have been retained, but not analyzed, may be mixed prior to analysis and 
analyzed, as described in paragraphs (d)(4)(iii) (A) through (H) of this 
section, for the required fuel parameters. Samples must be from the same 
season and year and must be of a single grade or of a single type of 
batch-produced blendstock.
    (ii) Blendstock samples of a single blendstock type obtained from 
continuous processes over a calendar month may be mixed together in 
equal volumes to form one blendstock sample and the sample subsequently 
analyzed for the required fuel parameters.
    (iii)(A) Samples shall have been collected and stored per the method 
normally employed at the refinery in order to prevent change in product 
composition with regard to baseline properties and to minimize loss of 
volatile fractions of the sample.
    (B) Properties of the retained samples shall be adjusted for loss of 
butane by comparing the RVP measured right after blending with the RVP 
determined at the time that the supplemental properties are measured.
    (C) The volume of each batch or shipment sampled shall have been 
noted and the sum of the volumes calculated to the nearest hundred (100) 
barrels.
    (D) For each batch or shipment sampled, the ratio of its volume to 
the total volume determined in paragraph (d)(4)(iii)(C) of this section 
shall be determined to three (3) decimal places. This shall be the 
volumetric fraction of the shipment in the mixture.
    (E) The total minimum volume required to perform duplicate analyses 
to obtain values of all of the required fuel parameters shall be 
determined.
    (F) The volumetric fraction determined in paragraph (d)(4)(iii)(D) 
of this section for each batch or shipment shall be multiplied by the 
value determined in paragraph (d)(4)(iii)(E) of this section.
    (G) The resulting value determined in paragraph (d)(4)(iii)(F) of 
this section for each batch or shipment shall be the volume of each 
batch or shipment's sample to be added to the mixture. This volume shall 
be determined to the nearest milliliter.
    (H) The appropriate volumes of each shipment's sample shall be 
thoroughly mixed and the solution analyzed per the methods normally 
employed at the refinery.
    (5) Test methods. (i) If the test methods used to obtain fuel 
parameter values of gasoline and gasoline blendstocks differ or are 
otherwise not equivalent in precision or accuracy to the corresponding 
test method specified in Sec. 80.46, results obtained under those 
procedures will only be acceptable, upon petition and approval (per 
Sec. 80.93), if the procedures are or were industry-accepted procedures 
for measuring the properties of gasoline and

[[Page 748]]

gasoline blendstocks at the time the measurement was made.
    (ii) Oxygen content may have been determined analytically or from 
oxygenate blending records.
    (A) The fuel parameter values, other than oxygen content, specified 
in paragraph (a) of this section, must be established as for any 
blendstock, per the requirements of this paragraph (d).
    (B) All oxygen associated with allowable gasoline oxygenates per 
Sec. 80.2(jj) shall be included in the determination of the baseline 
oxygen content, if oxygen content was determined analytically.
    (C) Oxygen content shall be assumed to be contributed solely by the 
oxygenate which is indicated on the blending records, if oxygen content 
was determined from blending records.
    (6) Data quality. Data may be excluded from the baseline 
determination if it is shown to the satisfaction of the Director of the 
Office of Mobile Sources, or designee, that it is not within the normal 
range of values expected for the gasoline or blendstock sample, 
considering unit configuration, operating conditions, etc.; due to:
    (i) Improper labeling; or
    (ii) Improper testing; or
    (iii) Other reasons as verified by the auditor specified in Sec. 
80.92.
    (e) Baseline fuel parameter determination--(1) Closely integrated 
gasoline producing facilities. Each refinery or blending facility must 
determine a set of baseline fuel parameter values per this paragraph 
(e). A single set of baseline fuel parameters may be determined, upon 
petition and approval, for two or more facilities under either of the 
following circumstances:
    (i) Two or more refineries or sets of gasoline blendstock-producing 
units of a refiner engaged in the production of gasoline per paragraph 
(b)(1) of this section which are geographically proximate to each other, 
yet not within a single refinery gate, and whose 1990 operations were 
significantly interconnected.
    (ii) A gasoline blending facility operating per paragraph (b)(3) of 
this section received at least 75 percent of its 1990 blendstock volume 
from a single refinery, or from one or more refineries which are part of 
an aggregate baseline per Sec. 80.101(h). The blending facility and 
associated refinery(ies) must be owned by the same refiner.
    (2) Equations--(i) Parameter determinations. Average baseline fuel 
parameters shall be determined separately for summer and winter using 
summer and winter data (per paragraph (d)(1)(i)(A) of this section), 
respectively, in the applicable equation listed in paragraphs (e)(2) 
(ii) through (iv) of this section, except that average baseline winter 
RVP shall be 8.7 psi.
    (ii) Product included in parameter determinations. In each of the 
equations listed in paragraphs (e)(2) (ii) through (iv) of this section, 
the following shall apply:
    (A)(1) All gasoline produced to meet EPA's 1990 summertime 
volatility requirements shall be considered summer gasoline. All other 
gasoline shall be considered winter gasoline, except:
    (2) Gasoline produced or imported for use in Hawaii, the 
Commonwealth of Puerto Rico, and the Virgin Islands that is subject to 
an approved petition under Sec. 80.93(d)(2) shall be considered summer 
gasoline for purposes of paragraph (e) of this section.
    (B)(1) Baseline total annual 1990 gasoline volume shall be the 
larger of the total volume of gasoline produced in or shipped from the 
refinery in 1990.
    (2) Baseline summer gasoline volume shall be the total volume of low 
volatility gasoline which met EPA's 1990 summertime volatility 
requirements. Baseline summer gasoline volume shall be determined on the 
same basis (produced or shipped) as baseline total annual gasoline 
volume.
    (3) Baseline winter gasoline volume shall be the baseline total 
annual gasoline volume minus the baseline summer gasoline volume.
    (C) Fuel parameter values shall be determined in the same units and 
at least to the same number of decimal places as the corresponding fuel 
parameter listed in paragraph (c)(5) of this section.
    (D) Volumes shall be reported to the nearest barrel or to the degree 
at which historical records were kept.
    (iii) Method 1. Summer and winter Method 1-type data, per paragraph 
(c)(1) of this section, shall be evaluated

[[Page 749]]

separately according to the following equation:
[GRAPHIC] [TIFF OMITTED] TR16FE94.013

where:

Xbs = summer or winter baseline value of fuel parameter X for 
the refinery
s = season, summer or winter, per paragraph (d)(1)(i)(A)(1) of this 
section
g = separate grade of season s gasoline produced by the refinery in 1990
ps = total number of different grades of season s gasoline 
produced by the refinery in 1990
Tgs = total volume of season s grade g gasoline produced in 
1990
Ns = total volume of season s gasoline produced by the 
refinery in 1990
i = separate batch or shipment of season s 1990 gasoline sampled
ngs = total number of season s samples of grade g gasoline
Xgis = parameter value of grade g gasoline sample i in season 
s
Vgis = volume of season s grade g gasoline sample i
SGgis = specific gravity of season s grade g gasoline sample 
i (used only for fuel parameters measured on a weight basis)

    (iv) Method 2. Summer and winter Method 2-type data, per paragraph 
(c)(2) of this section, shall be evaluated separately according to the 
following equation:
[GRAPHIC] [TIFF OMITTED] TR20JY94.000

where

Xbs = Summer or winter baseline value of fuel parameter x for 
the refinery
s = season, summer or winter, per paragraph (d)(1)(i)(A)(1) of this 
section
j = type of blendstock (e.g., reformate, isomerate, alkylate, etc.)
ms = total types of blendstocks in season s 1990 gasoline
Tjs = total 1990 volume of blendstock j used in the 
refinery's season s gasoline
Ns = total volume of season s gasoline produced in the 
refinery in 1990
i = sample of blendstock j
njs = number of samples of season s blendstock j from 
continuous process streams
Xijs = parameter value of sample i of season s blendstock j
pjs = number of samples of season s batch-produced blendstock 
j
Vijs = volume of batch of sample i of season s blendstock j
SGijs = specific gravity of sample i of season s blendstock j 
(used only for fuel parameters measured on a weight basis)

    (v) Method 3. (A) Post-1990 Blendstock. Summer and winter Method 3-
type data, per paragraph (c)(3) of this section, shall be evaluated 
separately according to the following equation:

[[Page 750]]

[GRAPHIC] [TIFF OMITTED] TR16FE94.015

where

Xbs = Summer or winter baseline value of fuel parameter X for 
the refinery
s = season, summer or winter, per paragraph (d)(1)(i)(A)(1) of this 
section
j = type of blendstock (e.g., reformate, isomerate, alkylate, etc.)
ms = total types of blendstocks in season s 1990 gasoline
Tjs = total 1990 volume of blendstock j used in the 
refinery's season s gasoline
Ns = total volume of season s gasoline produced in the 
refinery in 1990
i=sample of post-1990 season s blendstock j
njs = number of samples of post-1990 season s blendstock j 
from continuous process streams
Xijs = parameter value of sample i of post-1990 season s 
blendstock j
pjs = number of samples of post-1990 season s batch-produced 
blendstock j
Vijs = volume of post-1990 batch of sample i of season s 
blendstock j
SGijs = specific gravity of sample i of season s blendstock j 
(used only for fuel parameters measured on a weight basis)

    (B) Post-1990 gasoline. Summer and winter Method 3-type gasoline 
data, per paragraph (c)(3) of this section, shall be evaluated 
separately according tothe following equation:
[GRAPHIC] [TIFF OMITTED] TR16FE94.016

where:
Xbs = Summer or winter baseline value of fuel parameter X for 
the refinery
s = season, summer or winter, per paragraph (d)(1)(i)(A)(1) of this 
section
g = separate grade of season s gasoline produced by the refinery in 1990
ps = total number of different grades of season s gasoline 
produced by the refinery in 1990
Tgs = total volume of season s grade g gasoline produced in 
1990
Ns = total volume of season s gasoline produced by the 
refinery in 1990
i = separate batch or shipment of post-1990 season s gasoline sampled
ngs = total number of samples of post-1990 season s grade g 
gasoline
Xgis = parameter value of post-1990 grade g season s gasoline 
sample i
Vgis = volume of post-1990 season s grade g gasoline sample i
SGgis = specific gravity of post-1990 season s grade g 
gasoline sample i (used only for fuel parameters measured on a weight 
basis)

    (3) Percent evaporated determination. (i) Baseline E200 and E300 
values shall be determined directly from actual measurement data.
    (ii) If the data per paragraph (e)(3)(i) of this section are 
unavailable, upon petition and approval, baseline E200 and E300 values 
shall be determined from the following equations using the baseline T50 
and T90 values, if the baseline T50 and T90 values are otherwise 
acceptable:

E200 = 147.91 - (0.49 x T50)
E300 = 155.47 - (0.22 x T90)

    (4) Oxygen in the baseline. Baseline fuel parameter values shall be 
determined on both an oxygenated and non-oxygenated basis.

[[Page 751]]

    (i) If baseline values are determined first on an oxygenated basis, 
per paragraph (e) of this section, the calculations in paragraphs 
(e)(4)(i) (A) through (C) of this section shall be performed to 
determine the value of each baseline parameter on a non-oxygenated 
basis.
    (A) Benzene, aromatic, olefin and sulfur content shall be determined 
on a non-oxygenated basis according to the following equation:

UV = [AV/(100-OV)] x 100

where

UV = non-oxygenated parameter value
AV = oxygenated parameter value
OV = 1990 oxygenate volume as a percent of total production

    (B) Reid vapor pressure (RVP) shall be determined on a non-
oxygenated basis according to the following equation:
[GRAPHIC] [TIFF OMITTED] TR20JY94.001

where

UR = non-oxygenated RVP (baseline value)
BR = oxygenated RVP
i = type of oxygenate used in 1990
n = total number of different types of oxygenates used in 1990
OVi = 1990 volume, as a percent of total production, of 
oxygenate i
ORi = blending RVP of oxygenate i

    (C) Test data and engineering judgement shall be used to estimate 
T90, T50, E300 and E200 baseline values on a non-oxygenated basis. 
Allowances shall be made for physical dilution and distillation effects 
only, and not for refinery operational changes, e.g., decreased reformer 
severity required due to the octane value of oxygenate which would 
reduce aromatics.
    (ii) If baseline values are determined first on a non-oxygenated 
basis, the calculations in paragraphs (e)(4)(ii) (A) through (C) of this 
section shall be performed to determine the value of each baseline 
parameter on an oxygenated basis.
    (A) Benzene, aromatic, olefin and sulfur content shall be determined 
on an oxygenated basis according to the following equation:

AV = UV x (100 - OV) / 100

where

AV = oxygenated parameter value
UV = non-oxygenated parameter value
OV = 1990 oxygenate volume as a percent of total production

    (B) Reid vapor pressure (RVP) shall be determined on an oxygenated 
basis according to the following equation:
[GRAPHIC] [TIFF OMITTED] TR20JY94.002

where

BR = oxygenated RVP
UR = non-oxygenated RVP
i = type of oxygenate
n = total number of different types of oxygenates
OVi = 1990 volume, as a percent of total production, of 
oxygenate i
ORi = blending RVP of oxygenate i

    (C) Test data and engineering judgement shall be used to estimate 
T90, T50, E300 and E200 baseline values on an oxygenated basis. 
Allowances shall be made for physical dilution and distillation effects 
only, and not for refinery operational changes, e.g., decreased reformer 
severity required due to the octane value of oxygenate which would 
reduce aromatics.

[[Page 752]]

    (5) Work-in-progress. A refiner may, upon petition and approval (per 
Sec. 80.93), be allowed to account for work- in-progress at one or more 
of its refineries in 1990 in the determination of that refinery's 
baseline fuel parameters using Method 1, 2 or 3-type data if it meets 
the requirements specified in this paragraph (e)(5).
    (i) Work-in-progress shall include:
    (A) Refinery modification projects involving gasoline blendstock or 
distillate producing units which were under construction in 1990; or
    (B) Refinery modification projects involving gasoline blendstock or 
distillate producing units which were contracted for prior to or in 1990 
such that the refiner was committed to purchasing materials and 
constructing the project.
    (ii) The modifications discussed in paragraph (e)(5)(i) of this 
section must have been initiated with intent of complying with a 
legislative or regulatory environmental requirement enacted or 
promulgated prior to January 1, 1991.
    (iii) When comparing emissions or parameter values determined with 
and without the anticipated work-in-progress adjustment, at least one of 
the following situations results when comparing annual average baseline 
values per Sec. 80.90:
    (A) A 2.5 percent or greater difference in exhaust benzene emissions 
(per Sec. 80.90); or
    (B) A 2.5 percent or greater difference in total exhaust toxics 
emissions (per Sec. 80.90(d)); or
    (C) A 2.5 percent or greater difference in NOX emissions 
(per Sec. 80.90(e)); or
    (D) A 10.0 percent or greater difference in sulfur values; or
    (E) A 10.0 percent or greater difference in olefin values; or
    (F) A 10.0 percent or greater difference in T90 values.
    (iv) The requirements of paragraph (e)(5)(iii) of this section shall 
be determined according to the following equation:
[GRAPHIC] [TIFF OMITTED] TR16FE94.020

    (v) The capital involved in the work-in-progress is at least:
    (A) 10.0 percent of the refinery's depreciated book value as of the 
work-in-progress start-up date; or
    (B) $10 million.
    (vi) Sufficient data shall have been obtained since reliable 
operation of the work-in-progress was achieved. Such data shall be used 
in the determination of the baseline value, due to the work-in-progress, 
of each of the fuel parameters specified in Sec. 80.91(a)(2)(i) and as 
verification of the effect of the work-in-progress.
    (A) The baseline value, due to the work-in-progress, of each of the 
fuel parameters specified in Sec. 80.91(a)(2)(i) shall be used in the 
determination of the emissions specified in Sec. 80.90.
    (B) The baseline values of sulfur, olefins and E300, due to the 
work-in-progress, shall be used in the determination of the emissions 
specified in Sec. 80.41(j)(3).
    (vii) The annual average baseline values of exhaust benzene 
emissions, per Sec. 80.90(b) and Sec. 80.90(c), exhaust toxics 
emissions, per Sec. 80.90(d), and NOX emissions, per Sec. 
80.90(e), are the values resulting from the work-in-progress baseline 
adjustment, not to exceed the larger of:
    (A) The unadjusted annual average baseline value of each emission 
specified in this paragraph (e)(5)(vii); or
    (B) The following values:
    (1) Exhaust benzene emissions, simple model, 6.77;
    (2) Exhaust benzene emissions, complex model, 34.68 mg/mile;
    (3) Exhaust toxics emissions, 53.20 mg/mile in Phase I, 109.7 mg/
mile in Phase II;
    (4) NOX emissions, 750.1 mg/mile in Phase I, 1534. mg/
mile in Phase II.

[[Page 753]]

    (viii) When compliance is achieved using the simple model, per Sec. 
80.41 and/or Sec. 80.101, the baseline values of sulfur, olefins and 
T90 are the values resulting from the work-in-progress baseline 
adjustment, not to exceed the larger of:
    (A) The unadjusted annual average baseline value of each fuel 
parameter specified in paragraph (e)(5)(viii) of this section; or
    (B) The following values:
    (1) Sulfur, 355 ppm;
    (2) Olefins, 11.3 volume percent;
    (3) T90, 349 [deg]F; or
    (C) An adjusted annual average baseline fuel parameter value for 
sulfur, olefins and T90 such that exhaust emissions of VOC, toxics, and 
NOX do not exceed the complex model emission levels specified 
in paragraph (e)(5)(vii)(B) of this section. In the petition for a work-
in-progress adjustment, the refiner shall specify sulfur, olefins and 
T90 values that meet these emission levels.
    (ix) All work-in-progress adjustments must be accompanied by:
    (A) Unadjusted and adjusted fuel parameters, emissions, and volumes; 
and
    (B) A description of the current status of the work-in-progress 
(i.e., the refinery modification project) and the date on which normal 
operations were achieved; and
    (C) A narrative describing the situation, the types of calculations, 
and the reasoning supporting the types of calculations done to determine 
the adjusted values.
    (6) Baseline adjustment for extenuating circumstances. (i) Baseline 
adjustments may be allowed, upon petition and approval (per Sec. 
80.93), if a refinery had downtime of a gasoline blendstock producing 
unit for 30 days or more in 1990 due to:
    (A) Unplanned, unforeseen circumstances; or
    (B) Non-annual maintenance (turnaround).
    (ii) Fuel parameter and volume adjustments shall be made by assuming 
that the downtime did not occur in 1990.
    (iii) All extenuating circumstance adjustments must be accompanied 
by:
    (A) Unadjusted and adjusted fuel parameters, emissions, and volumes; 
and
    (B) A description of the current status of the extenuating 
circumstance and the date on which normal operations were achieved; and
    (C) A narrative describing the situation, the types of calculations, 
and the reasoning supporting the types of calculations done to determine 
the adjusted values.
    (7) Baseline adjustments for 1990 JP-4 production. (i) Baseline 
adjustments may be allowed, upon petition and approval (per Sec. 
80.93), if a refinery produced JP-4 jet fuel in 1990 and all of the 
following requirements are also met:
    (A) Refinery type.
    (1) The refinery is the only refinery of a refiner such that it 
cannot form an aggregate baseline with another refinery (per Sec. 
80.101(h)); or
    (2) The refinery is one refinery of a multi-refinery refiner for 
which all of the refiner's refineries produced JP-4 in 1990; or
    (3) The refinery is one refinery of a multi-refinery refiner for 
which not all of the refiner's refineries produced JP-4 in 1990.
    (B) No refinery of a given refiner produces reformulated gasoline. 
If any refinery of the refiner produces reformulated gasoline at any 
time in a calendar year, the compliance baselines of all the refiner's 
refineries receiving a baseline adjustment per this paragraph (e)(7) 
shall revert to the unadjusted baselines of each respective refinery for 
that year and all subsequent years.
    (C) 1990 JP-4 to gasoline ratio.
    (1) For a refiner per paragraph (e)(7)(i)(A)(1) of this section, the 
ratio of its refinery's 1990 JP-4 production to its 1990 gasoline 
production must be greater than or equal to 0.15.
    (2) For a refiner per paragraph (e)(7)(i)(A)(2) of this section, the 
ratio of each of its refinery's 1990 JP-4 production to its 1990 
gasoline production must be greater than or equal to 0.15.
    (3) For a refiner per paragraph (e)(7)(i)(A)(3) of this section, the 
ratio of the refiner's 1990 JP-4 production to its 1990 gasoline 
production must be greater than or equal to 0.15, when determined across 
all of its refineries. Such a refiner must comply with its

[[Page 754]]

anti-dumping requirements on an aggregate basis, per Sec. 80.101(h), 
across all of its refineries.
    (ii) Fuel parameter and volume adjustments shall be made by assuming 
that no JP-4 was produced in 1990.
    (iii) All adjustments due to 1990 JP-4 production must be 
accompanied by:
    (A) Unadjusted and adjusted fuel parameters, emissions, and volumes; 
and
    (B) A narrative describing the situation, the types of calculations, 
and the reasoning supporting the types of calculations done to determine 
the adjusted values.
    (8) Baseline adjustments due to increasing crude sulfur content.
    (i) Baseline adjustments may be allowed, upon petition and approval 
(per Sec. 80.93), if a refinery meets all of the following 
requirements:
    (A) The refinery does not produce reformulated gasoline. If the 
refinery produces reformulated gasoline at any time in a calendar year, 
its compliance baseline shall revert to its unadjusted baseline for that 
year and all subsequent years;
    (B) Has an unadjusted baseline sulfur value which is less than or 
equal to 50 parts per million (ppm);
    (C) Is not aggregated with one or more other refineries (per Sec. 
80.101(h)). If a refinery which received an adjustment per this 
paragraph (e)(8) subsequently is included in an aggregate baseline, its 
compliance baseline shall revert to its unadjusted baseline for that 
year and all subsequent years;
    (D) Can show that installation of the refinery units necessary to 
process higher sulfur crude oil supplies to comply with the refinery's 
unadjusted baseline would cost at least $10 million or be greater than 
or equal to 10 percent of the depreciated book value of the refinery as 
of January 1, 1995;
    (E) Can show that it could not reasonably or economically obtain 
crude oil from an alternative source that would permit it to produce 
conventional gasoline which would comply with its unadjusted baseline;
    (F) Has experienced an increase of greater than or equal to 25 
percent in the average sulfur content of the crude oil used in the 
production of gasoline in the refinery since 1990, calculated as 
follows:
[GRAPHIC] [TIFF OMITTED] TR04MR97.002

where:

CSHI = highest annual average crude sulfur (in ppm), of the crude slates 
used in the production of gasoline, determined over the years 1991-1994;
CS90 = 1990 annual average crude slate sulfur (in ppm), of the crude 
slates used in the production of gasoline;
CS%CHG = percent change in average sulfur content of crude slate;

    (G) Can show that gasoline sulfur changes are directly and solely 
attributable to the crude sulfur change, and not due to alterations in 
refinery operation nor choice of products.
    (ii) The adjusted baseline sulfur value shall be the actual baseline 
sulfur value, in ppm, plus 100 ppm.
    (iii) All adjustments made pursuant to this paragraph (e)(8) must be 
accompanied by:
    (A) Unadjusted and adjusted fuel parameters and emissions; and
    (B) A narrative describing the situation, the types of calculations, 
and the reasoning supporting the types of calculations done to determine 
the adjusted values.
    (9) Baseline adjustment for low sulfur and olefins.
    (i) Baseline adjustments may be allowed if a refinery meets all of 
the following requirements:
    (A) The unadjusted annual average baseline sulfur value of the 
refinery is less than or equal to 30 parts per million (ppm);
    (B) The unadjusted annual average baseline olefin value of the 
refinery is less than or equal to 1.0 percent by volume (vol%).
    (ii) Adjusted baseline values.
    (A) The adjusted baseline shall have an annual average sulfur value 
of 30 ppm, and an annual average olefin value of 1.0 vol%.
    (B) The adjusted baseline shall have a summer sulfur value of 30 
ppm, and a summer olefin value of 1.0 vol%.
    (C) The adjusted baseline shall have a winter sulfur value of 30 
ppm, and a winter olefin value of 1.0 vol%.
    (f) Baseline volume and emissions determination--(1) Individual 
baseline volume. (i) The individual baseline volume of a refinery 
described in paragraph (b)(1)(i)

[[Page 755]]

of this section shall be the larger of the total gasoline volume 
produced in or shipped from the refinery in 1990, excluding gasoline 
blendstocks and exported gasoline, and including the oxygenate volume 
associated with any product meeting the requirements specified in 
paragraph (c)(1)(ii) of this section.
    (ii) Gasoline brought into the refinery in 1990 which exited the 
refinery, in 1990, unchanged shall not be included in determining the 
refinery's baseline volume.
    (iii) If a refiner is allowed to adjust its baseline per paragraphs 
(e)(5) through (e)(7) of this section, its individual baseline volume 
shall be the volume determined after the adjustment.
    (iv) The individual baseline volume for facilities deemed closely 
integrated, per paragraph (e)(1) of this section, shall be the combined 
1990 gasoline production of the facilities, so long as mutual volumes 
are not double-counted, i.e., volumes of blendstock sent from the 
refinery to the blending facility should not be included in the blending 
facility's volume.
    (v) The baseline volume of a refiner, per paragraph (b)(3) of this 
section, shall be the larger of the total gasoline volume produced in or 
shipped from the refinery in 1990, excluding gasoline blendstocks and 
exported gasoline.
    (vi) The baseline volume of an importer, per paragraph (b)(4) of 
this section, shall be the total gasoline volume imported into the U.S. 
in 1990.
    (2) Individual baseline emissions. (i) Individual annual average 
baseline emissions (per Sec. 80.90) shall be determined for every 
refinery, refiner or importer, as applicable.
    (ii) If the baseline fuel value for aromatics, olefins, and/or 
benzene (determined per paragraph (e) of this section) is higher than 
the high end of the valid range limits specified in Sec. 80.42(c)(1) if 
compliance is being determined under the Simple Model, or in Sec. 
80.45(f)(1)(ii) if compliance is being determined under the Complex 
Model, then the valid range limits may be extended for conventional 
gasoline in the following manner:
    (A) The new high end of the valid range for aromatics is determined 
from the following equation:

NAROLIM = AROBASE + 5.0 volume percent

where

NAROLIM = The new high end of the valid range limit for aromatics, in 
volume percent
AROBASE = The seasonal baseline fuel value for aromatics, in volume 
percent

    (B) The new high end of the valid range for olefins is determined 
from the following equation:

NOLELIM = OLEBASE + 3.0 volume percent

where

NOLELIM = The new high end of the valid range limit for olefins, in 
volume percent
OLEBASE = The seasonal baseline fuel value for olefins, in volume 
percent

    (C) The new high end of the valid range for benzene is determined 
from the following equation:

NBENLIM = BENBASE + 0.5 volume percent

where

NBENLIM = The new high end of the valid range limit for benzene, in 
volume percent
BENBASE = The seasonal baseline fuel value for benzene, in volume 
percent

    (D) The extension of the valid range is limited to the applicable 
summer or winter season in which the baseline fuel values for aromatics, 
olefins, and/or benzene exceed the high end of the valid range as 
described in paragraph (f)(2)(ii) of this section. Also, the extension 
of the valid range is limited to use by the refiner whose baseline value 
for aromatics, olefins, and/or benzene was higher than the valid range 
limits as described in paragraph (f)(2)(ii) of this section.
    (E) Any extension of the Simple Model valid range limits is 
applicable only to the Simple Model. Likewise any extension of the 
Complex Model valid range limits is applicable only to the Complex 
Model.
    (F) The valid range extensions calculated in paragraphs 
(f)(2)(ii)(A), (B), and (C) of this section are applicable to both the 
baseline fuel and target fuel for the purposes of determining the 
compliance status of conventional gasolines. The extended valid range 
limit represents the maximum value for that parameter above which fuels 
cannot be

[[Page 756]]

evaluated with the applicable compliance model.
    (G) Under the Simple Model, baseline and compliance calculations 
shall subscribe to the following limitations:
    (1) If the aromatics valid range has been extended per paragraph 
(f)(2)(ii)(A) of this section, an aromatics value equal to the high end 
of the valid range specified in Sec. 80.42(c)(1) shall be used for the 
purposes of calculating the exhaust benzene fraction.
    (2) If the fuel benzene valid range has been extended per paragraph 
(f)(2)(ii)(C) of this section, a benzene value equal to the high end of 
the valid range specified in Sec. 80.42(c)(1) shall be used for the 
purposes of calculating the exhaust benzene fraction.
    (H) Under the Complex Model, baseline and compliance calculations 
shall subscribe to the following limitations:
    (1) If the aromatics valid range has been extended per paragraph 
(f)(2)(ii)(A) of this section, an aromatics value equal to the high end 
of the valid range specified in Sec. 80.45(f)(1)(ii) shall be used for 
the purposes of calculating emissions performances.
    (2) If the olefins valid range has been extended per paragraph 
(f)(2)(ii)(B) of this section, an olefins value equal to the high end of 
the valid range specified in Sec. 80.45(f)(1)(ii) shall be used for the 
target fuel for the purposes of calculating emissions performances.
    (3) If the benzene valid range has been extended per paragraph 
(f)(2)(ii)(C) of this section, a benzene value equal to the high end of 
the valid range specified in Sec. 80.45(f)(1)(ii) shall be used for the 
target fuel for the purposes of calculating emissions performances.
    (iii) Facilities deemed closely integrated, per paragraph (e)(1) of 
this section, shall have a single set of annual average individual 
baseline emissions.
    (iv) Aggregate baselines (per Sec. 80.101(h)) must have the 
NOX emissions of all refineries in the aggregate determined 
on the same basis, using either oxygenated or non-oxygenated baseline 
fuel parameters.
    (3) Geographic considerations requiring individual conventional 
gasoline compliance baselines. (i) Anyone may petition EPA to establish 
separate baselines for refineries located in and providing conventional 
gasoline to an area with a limited gasoline distribution system if it 
can show that the area is experiencing increased toxics emissions due to 
an ozone nonattainment area opting into the reformulated gasoline 
program pursuant to section 211(k)(6) of the Act.
    (ii) If EPA agrees with the finding of paragraph (f)(4)(i) of this 
section, it shall require that the baselines of such refineries be 
separate from refineries not located in the area.
    (iii) If two (2) or more of a refiner's refineries are located in 
the geographic area of concern, the refiner may aggregate the baseline 
emissions and sulfur, olefin and T90 values of the refineries or have an 
individual baseline for one or more of the refineries, per paragraph 
(f)(3) of this section.
    (4) Baseline recalculations. Aggregate baseline exhaust emissions 
(per Sec. 80.90) and baseline sulfur, olefin and T90 values and 
aggregate baseline volumes shall be recalculated under the following 
circumstances:
    (i) A refinery included in an aggregate baseline is entirely 
shutdown. If the shutdown refinery was part of an aggregate baseline, 
the aggregate baseline emissions, aggregate baseline sulfur, olefin and 
T90 values and aggregate volume shall be recalculated to account for the 
removal of the shutdown refinery's contributions to the aggregate 
baseline.
    (ii) A refinery exchanges owners.
    (A) All aggregate baselines affected by the exchange shall be 
recalculated to reflect the addition or subtraction of the baseline 
exhaust emissions, sulfur, olefin and T90 values and volumes of that 
refinery.
    (B) The new owner may elect to establish an individual baseline for 
the refinery or to include it in an aggregate baseline.
    (C) If the refinery was part of an aggregate of three or more 
refineries, the remaining refineries in the aggregate from which that 
refinery was removed will have a new aggregate baseline. If the refinery 
was part of an aggregate of only two refineries, the remaining refinery 
will have an individual baseline.
    (g) Inability to meet the requirements of this section. If a refiner 
or importer is

[[Page 757]]

unable to comply with one or more of the requirements specified in 
paragraphs (a) through (f) of this section, it may, upon petition and 
approval, accommodate the lack of compliance in a reasonable, logical, 
technically sound manner, considering the appropriateness of the 
alternative. A narrative of the situation, as well as any calculations 
and results determined, must be documented.

[59 FR 7860, Feb. 16, 1994, as amended at 59 FR 36966, July 20, 1994; 60 
FR 6032, Feb. 1, 1995; 60 FR 40008, Aug. 4, 1995; 62 FR 9883, Mar. 4, 
1997; 67 FR 8737, Feb. 26, 2002; 72 FR 60579, Oct. 25, 2007]

    Editorial Note: At 62 FR 68207, Dec. 31, 1997, Sec. 80.91 was 
amended by revising paragraph (e)(1)(iii) and adding paragraph 
(f)(2)(ii); however, these amendments could not be incorporated because 
(e)(1)(iii) did not exist, and (f)(2)(ii) already existed in the 1997 
edition of this volume. For the convenience of the user, the revised and 
added text is set forth as follows:



Sec. 80.91  Individual baseline determination.

                                * * * * *

    (e) * * *
    (1) * * *
    (iii) For facilities determined to be closely integrated gasoline 
producing facilities and for which EPA has granted a single set of 
baseline fuel parameter values per this paragraph (e)(1)(i):
    (A) All reformulated gasoline and anti-dumping standards shall be 
met by such closely integrated facilities on an aggregate basis;
    (B) A combined facility registration shall be submitted under 
Sec. Sec. 80.76 and 80.103; and
    (C) Record keeping requirements under Sec. Sec. 80.74 and 80.104 
and reporting requirements under Sec. Sec. 80.75 and 80.105 shall be 
met for such closely integrated facilities on an aggregate basis.

                                * * * * *

    (f) * * *
    (2) * * *
    (ii) [Reserved]

                                * * * * *



Sec. 80.92  Baseline auditor requirements.

    (a) General requirements. (1) Each refiner or importer is required 
to have its individual baseline determination methodology, resulting 
baseline fuel parameter, volume and emissions values verified by an 
auditor which meets the requirements described in this section. A 
refiner or importer which has the anti-dumping statutory baseline as its 
individual baseline is exempt from this requirement.
    (2) An auditor may be an individual or organization, and may utilize 
contractors and subcontractors to assist in the verification of a 
baseline.
    (3) If an auditor is an organization, one or more persons shall be 
designated as primary analyst(s). The primary analyst(s) shall meet the 
requirements described in paragraphs (c) (2) and (3) of this section and 
shall be responsible for the baseline audit per paragraph (f) of this 
section.
    (b) Independence. The auditor, its contractors, subcontractors and 
their organizations shall be independent of the submitting organization. 
All of the criteria listed in paragraphs (b) (1) and (2) of this section 
must be met by every individual involved in substantive aspects of the 
baseline verification.
    (1) Previous employment criteria. (i) None of the auditing 
personnel, including any contractor or subcontractor personnel, involved 
in the baseline verification for a refiner or importer shall have been 
employed by the refiner or importer at any time during the three (3) 
years preceding the date of hire of the auditor by the refiner or 
importer for baseline verification purposes.
    (ii) Auditor personnel may have been a contractor or subcontractor 
to the refiner or importer, as long as all other criteria listed in this 
section are met.
    (iii) Auditor personnel may also have developed the baseline of the 
refiner or importer whose baseline they are auditing, but not as an 
employee (per paragraph (b)(1)(i) of this section). Those involved only 
in the development of the baseline of the refiner or importer need not 
meet the requirements specified in this section.
    (2) Financial criteria. Neither the primary analyst, nor the 
auditing organization nor any organization or individual which may be 
contracted or subcontracted to supply baseline verification expertise 
shall:
    (i) Have received more than one quarter of its revenue from the 
refiner or importer during the year prior to the

[[Page 758]]

date of hire of the auditor by the refiner or importer for auditing 
purposes. Income received from the refiner or importer to develop the 
baseline being audited is excepted; nor
    (ii) Have a total of more than 10 percent of its net worth with the 
refiner or importer; nor
    (iii) Receive compensation for the audit which is dependent on the 
outcome of the audit.
    (c) Technical ability. All of the following criteria must be met by 
the auditor in order to demonstrate its technical capability to perform 
the baseline audit:
    (1) The auditor shall be technically capable of evaluating a 
baseline determination. It shall have personnel familiar with petroleum 
refining processes, including associated computational procedures, 
methods of product analysis and economics, and expertise in conducting 
the auditing process, including skills for effective data gathering and 
analysis.
    (2) The primary analyst must understand all technical details of the 
entire baseline audit process.
    (3)(i) The primary analyst shall have worked at least five (5) years 
in either refinery operations or as a consultant for the refining 
industry.
    (ii) If one or more computer models designed for refinery planning 
and/or economic analysis are used in the verification of an individual 
baseline, the primary analyst must have at least three (3) years 
experience working with the model(s) utilized in the verification.
    (iii) EPA may, upon petition, waive one or more of the requirements 
specified in paragraph (c)(3) of this section if the technical 
capability of the primary analyst is demonstrated to the satisfaction of 
the Director of the Office of Mobile Sources, or designee.
    (d) Auditor qualification statement. A statement documenting the 
qualifications of the auditor, primary analyst(s), contractors, 
subcontractors and their organizations must be submitted to EPA (Fuel 
Studies and Standards Branch, Baseline Auditor, U.S. EPA, 2565 Plymouth 
Rd., Ann Arbor, MI 48105).
    (1) Timing. (i) The auditor qualification statement may be submitted 
by the refiner or importer prior to baseline submission (per Sec. 
80.93) or by a potential auditor at any time. The auditor will be deemed 
certified when all qualifications are met, to the satisfaction of the 
Director of the Office of Mobile Sources, or designee. If no response is 
received from EPA within 45 days of application or today's date, 
whichever is later, the auditor shall be deemed certified.
    (ii) The auditor qualification statement may be submitted by the 
refiner or importer with its baseline submission (per Sec. 80.93). If 
the auditor does not meet the criteria specified in this section, the 
baseline submission will not be accepted.
    (2) Content. The auditor qualification statement must contain all of 
the following information and may contain additional information which 
may aid EPA's review of the qualification statement:
    (i) The name and address of each person and organization involved in 
substantive aspects of the baseline audit, including the auditor, 
primary analyst(s), others within the organization, and contractors and 
subcontractors;
    (ii) The refiners and/or importers for which the auditor, its 
contractors and subcontractors and their organizations do not meet the 
independence criteria described in paragraph (b) of this section; and
    (iii) The technical qualifications and experience of each person 
involved in the baseline audit, including a showing that the 
requirements described in paragraph (c) of this section are met.
    (e) Refiner and importer responsibility. (1) Each refiner and 
importer required to have its baseline verified by an auditor (per 
paragraph (a)(1) of this section) is responsible for utilizing an 
auditor for baseline verification which meets the requirements specified 
in paragraphs (b) and (c) of this section.
    (2) A refiner's or importer's baseline submission will not be 
accepted until it has been verified using an auditor which meets the 
requirements specified in paragraphs (b) and (c) of this section.
    (f) Auditor responsibilities. (1) The auditor must verify that all 
baseline submission requirements are fulfilled.

[[Page 759]]

This includes, but is not limited to, the following:
    (i) Verifying that all data is correctly accounted for;
    (ii) Verifying that all calculations are performed correctly;
    (iii) Verifying that all adjustments to the data and/or calculations 
to account for post-1990 data, work-in-progress, and/or extenuating or 
other circumstances, as allowed per Sec. 80.91, are valid and performed 
correctly.
    (2) The primary analyst shall prepare and sign a statement, to be 
included in the baseline submission of the refiner or importer, stating 
that:
    (i) He/she has thoroughly reviewed the sampling methodology and 
baseline calculations; and
    (ii) To the best of his/her knowledge, the requirements and 
intentions of the rulemaking are met in the baseline determination; and
    (iii) He/she agrees with the final baseline parameter, volume and 
emission values listed in the baseline submission.
    (3) The auditor may be subject to debarment under U.S.C. 1001 if it 
displays gross incompetency, intentionally commits an error in the 
verification process or misrepresents itself or information in the 
baseline verification.

[59 FR 7860, Feb. 16, 1994, as amended at 67 FR 8737, Feb. 26, 2002]



Sec. 80.93  Individual baseline submission and approval.

    (a) Submission timing. (1) Each refiner, blender or importer shall 
submit two copies of its individual baseline to EPA (Fuel Studies and 
Standards Branch, Baseline Submission, U.S. EPA, 2565 Plymouth Rd., Ann 
Arbor, MI 48105) not later than June 1, 1994.
    (2) If a refiner must collect data after December 15, 1993 (per 
Sec. 80.91(d)(2)), it shall submit two copies of its individual 
baseline to EPA (per Sec. 80.93(a)(1)) by September 1, 1994.
    (3)(i) All petitions required for baseline adjustments or 
methodology deviations will be approved or disapproved by the Director 
of the Office of Mobile Sources, or designee. All instances where a 
``showing'' or other proof is required are also subject to approval by 
the Director of the Office of Mobile Sources, or designee.
    (ii) Petitions, ``showings,'' and other associated proof may be 
submitted to EPA prior to submittal of the individual baseline (per 
paragraphs (a)(1) and (a)(2) of this section). EPA will attempt to 
review and approve, disapprove or otherwise comment on the petition, 
etc., prior to the deadline for baseline submittal.
    (iii) In the event that EPA does not comment on the petition prior 
to the deadline for baseline submittal, the refiner or importer must 
still comply with the applicable baseline submittal deadline.
    (iv) Petitions submitted prior to the deadline for baseline 
submittals shall be submitted to the EPA at the following address: Fuels 
Studies and Standards Branch, Baseline Petition, U.S. EPA, 2565 Plymouth 
Road, Ann Arbor, Michigan 48105.
    (4) If a baseline recalculation is required per Sec. 80.91(f), 
documentation and recalculation of all affected baselines shall be 
submitted to EPA within 30 days of the previous baseline(s) becoming 
inaccurate due to the circumstances outlined in Sec. 80.91(f).
    (b) Submission content. (1) Individual baseline submissions shall 
include, at minimum, the information specified in this paragraph (b).
    (i) During its review and evaluation of the baseline submission, EPA 
may require a refiner or importer to submit additional information in 
support of the baseline determination.
    (ii) Additional information which may assist EPA during its review 
and evaluation of the baseline may be included at the submitter's 
discretion.
    (2) Administrative information shall include:
    (i) Name and business address of the refiner or importer;
    (ii) Name, business address and business phone number of the company 
contact;
    (iii) Address and physical location of each refinery, terminal or 
import facility;
    (iv) Address and physical location where documents which are 
supportive of the baseline determination for each facility are kept;
    (3) The chief executive officer statement shall be:

[[Page 760]]

    (i) A statement signed by the chief executive officer of the 
company, or designee, which states that:
    (A) The company is complying with the requirements as a refiner, 
blender or importer, as appropriate;
    (B) The data used in the baseline determination is the extent of the 
data available for the determination of all required baseline fuel 
parameters;
    (C) All calculations and procedures followed per Sec. Sec. 80.90 
through 80.93 have been done correctly;
    (D) Proper adjustments have been made to the data or in the 
calculations, as applicable;
    (E) The requirements and intentions of the rulemaking have been met 
in determining the baseline fuel parameters; and
    (F) The baseline fuel parameter values determined for each facility 
represent that facility's 1990 gasoline to the fullest extent possible.
    (ii) A refiner or importer which is permitted to utilize the 
parameter values specified in Sec. 80.91(c)(5), and does so, shall 
submit a statement signed by the chief executive officer of the company, 
or designee, indicating that insufficient data exist for a baseline 
determination by the types of data allowed for that entity, as specified 
in Sec. 80.91.
    (4) The auditor-related requirements are:
    (i) Name, address, telephone number and date of hire of each auditor 
hired for baseline verification, whether or not the auditor was retained 
through the baseline approval process.
    (ii) Identification of the auditor responsible for the verification. 
A copy of this auditor's qualification statement, per Sec. 80.92, must 
be included if the auditor has not been approved by EPA, per Sec. 
80.92;
    (iii) Indication of the primary analyst(s) involved in each 
refinery's baseline verification; and
    (iv) The signed auditor verification statement, per Sec. 80.92.
    (5) The following baseline information for each refinery, refiner or 
importer, as applicable, shall be provided:
    (i) Individual baseline fuel parameter values, on an oxygenated and 
non-oxygenated basis, and on a summer and winter basis, per Sec. 80.91;
    (ii) Individual baseline exhaust emissions shall be shown 
separately, on a summer, winter and annual average basis (per Sec. 
80.90) as follows:
    (A) Simple model exhaust benzene emissions;
    (B) Complex model exhaust benzene emissions;
    (C) Complex model exhaust toxics emissions, for Phase I;
    (D) Complex model exhaust NOX emissions, for Phase I, 
using oxygenated individual baseline fuel parameters;
    (E) Complex model exhaust NOX emissions, for Phase I, 
using non-oxygenated individual baseline fuel parameters;
    (F) Complex model exhaust toxics emissions, for Phase II;
    (G) Complex model exhaust NOX emissions, for Phase II, 
using oxygenated individual baseline fuel parameters; and
    (H) Complex model exhaust NOX emissions, for Phase II, 
using non-oxygenated individual baseline fuel parameters;
    (iii) Individual 1990 baseline gasoline volumes, per Sec. 80.91, 
shall be shown separately on a summer, winter and annual average basis; 
and
    (iv) Blendstock-to-gasoline ratios for each calendar year 1990 
through to 1993, per Sec. 80.102.
    (6) Confidential business information. (i) Upon approval of an 
individual baseline, EPA will publish the individual annualized baseline 
exhaust emissions, on an annual average basis, specified in paragraph 
(b)(5)(ii) of this section. Such individual baseline exhaust emissions 
shall not be considered confidential. In addition, the reporting 
information required under Sec. 80.75(b)(2)(ii) (D), (G) and (J), and 
Sec. 80.105(a)(4)(i) (E), (H) and (K) shall not be considered 
confidential.
    (ii) Information in the baseline submission which the submitter 
desires to be considered confidential business information (per 40 CFR 
part 2, subpart B) must be clearly identified. If no claim of 
confidentiality accompanies a submission when it is received by EPA, the 
information may be made available to the public without further notice 
to the submitter pursuant to the provisions of 40 CFR part 2, subpart B.

[[Page 761]]

    (7) Information related to baseline determination as specified in 
Sec. 80.91 and paragraph (c) of this section.
    (c) Additional baseline submission requirements when Method 1-, 2- 
and/or 3-type data is utilized. All requirements of this paragraph shall 
be reported separately for each facility, unless the facilities are 
closely integrated, per Sec. 80.91.
    (1) General. The following information shall be provided:
    (i) The number of months in 1990 during which the facility was 
operating;
    (ii) 1990 summer gasoline production volume, per Sec. 80.91, total 
and by grade, for all gasoline produced but not exported;
    (iii) 1990 winter gasoline production volume, per Sec. 80.91, total 
and by grade, for all gasoline produced, excluding gasoline exported; 
and
    (iv) Whether this facility is actually two facilities which are 
closely integrated, per Sec. 80.91.
    (2) Baseline values. The following shall be included for each fuel 
parameter for which a baseline value is required, per Sec. 80.91:
    (i) Narrative of the development of the baseline value of the fuel 
parameter, including discussion of the sampling and calculation 
methodologies, technical judgment used, effects of petition results on 
calculated values, and any additional information which may assist EPA 
in its review of the baseline;
    (ii) Identification of the data-type(s), per Sec. 80.91, used in 
the determination of a given fuel parameter;
    (iii) Identification of test method. If not per Sec. 80.46, include 
a narrative, explain differences and describing adequacy, per Sec. 
80.91;
    (iv) Documentation that the minimum sampling requirements per Sec. 
80.91 have been met;
    (v) Petition and narrative, if needed, for use of less than the 
minimum required data, per Sec. 80.91;
    (vi) Identification of instances of sample compositing per Sec. 
80.91;
    (vii) Identification of streams for which one or more parameter 
values were deemed negligible per Sec. 80.91; and
    (viii) Discussion of the calculation of oxygenated or non-oxygenated 
fuel parameter values from non-oxygenated or oxygenated values, 
respectively, per Sec. 80.91.
    (3) Method 1. If Method 1-type data is utilized in the baseline 
determination, the following information on 1990 batches of gasoline, or 
shipments if not batch blended, are required by grade shall be provided:
    (i) First and last sampling dates;
    (ii) The following shall be indicated separately on a summer and 
winter basis, by month:
    (A) Number of months sampled;
    (B) Number of 1990 batches, or shipments if not batch blended;
    (C) Total volume of all batches or shipments;
    (D) Number of batches or shipments sampled;
    (E) Total volume of all batches or shipments sampled;
    (F) Baseline fuel parameter value, per Sec. 80.91; and
    (iii) A showing that data was available on every batch of 1990 
gasoline, if applicable, per Sec. 80.91 (b)(3) or (b)(4).
    (4) Method 2. If Method 2-type data is utilized in the baseline 
determination, the following information on each type of 1990 blendstock 
used in the refinery's gasoline are required, by blendstock type shall 
be provided:
    (i) First and last sampling dates; and
    (ii) The following shall be indicated separately on a summer and 
winter basis, by month:
    (A) Number of months sampled;
    (B) Each type of blendstock used in 1990 gasoline and total number 
of blendstocks. Include all blendstocks produced, purchased or otherwise 
received which were blended to produce gasoline within the facility. 
Identify all blendstocks not produced in the facility but used in the 
facility's 1990 gasoline;
    (C) Total volume of each blendstock used in gasoline in 1990;
    (D) Identification of blendstock streams as batch or continuous;
    (E) Number of blendstock samples from continuous blendstock streams;
    (F) Number of blendstock samples from batch processes, including 
volume of each batch sampled; and
    (G) Baseline fuel parameter value, per Sec. 80.91.
    (5) Method 3, blendstock data. The following information on each 
type of

[[Page 762]]

post-1990 gasoline blendstock used in the refinery's gasoline are 
required, by blendstock type shall be provided:
    (i) First and last sampling dates;
    (ii) The following shall be indicated separately on a summer and 
winter basis, by month:
    (A) Number of post-1990 months sampled;
    (B) Each type of blendstock used in 1990 gasoline and total number 
of blendstocks. Include all blendstocks produced, purchased or otherwise 
received which were blended to produce gasoline within the facility. 
Identify all blendstocks not produced in the facility but used in the 
facility's 1990 gasoline;
    (C) Total volume of each blendstock used in gasoline in 1990;
    (D) Identification of post-1990 blendstock streams as batch or 
continuous;
    (E) Number of post-1990 blendstock samples from continuous 
blendstock streams;
    (F) Number of post-1990 blendstock samples from batch processes, 
including volume of each batch sampled; and
    (G) Baseline fuel parameter value, per Sec. 80.91; and
    (iii) Support documentation showing that the criteria of Sec. 80.91 
for using Method 3-type blendstock data are met.
    (6) Method 3, post-1990 gasoline data. The following information on 
post-1990 batches of gasoline, or shipments if not batch blended, are 
required by grade:
    (i) First and last sampling dates;
    (ii) The following shall be indicated separately for summer and 
winter production, by month:
    (A) Number of post-1990 months sampled;
    (B) Number of post-1990 batches, or shipments if not batch blended;
    (C) Total volume of all post-1990 batches or shipments;
    (D) Number of post-1990 batches or shipments sampled;
    (E) Volume of each post-1990 batch or shipment sampled; and
    (F) Baseline fuel parameter value, per Sec. 80.91; and
    (iii) Support documentation showing that the criteria of Sec. 80.91 
for using post-1990 gasoline data are met.
    (7) Work-in-progress (WIP). All of the following must be included in 
support of a WIP adjustment (per Sec. 80.91(e)(5)):
    (i) Petition including identification of the specific baseline 
emission(s) or parameter for which the WIP adjustment is desired;
    (ii) Showing that all WIP criteria, per Sec. 80.91(e)(5), are met;
    (iii) Unadjusted and adjusted baseline fuel parameters, emissions 
and volume for the facility; and
    (iv) Narrative, per Sec. 80.91 (e)(5).
    (8) Extenuating circumstances. All of the following must be included 
in support of an extenuating circumstance adjustment (per Sec. 80.91 
(e)(6) through (e)(7)):
    (i) Petition including identification of the allowable circumstance, 
per Sec. 80.91 (e)(6) through (e)(7);
    (ii) Showing that all applicable criteria, per Sec. 80.91 (e)(6) 
through (e)(7), are met;
    (iii) Unadjusted and adjusted baseline fuel parameters, emissions 
and volume for the facility; and
    (iv) Narrative, per Sec. 80.91.
    (9) Other baseline information. Narrative discussing any aspects of 
the baseline determination not already indicated per the requirements of 
paragraph (c)(8) of this section shall be provided.
    (10) Refinery information. The following information, on a summer or 
winter basis, shall be provided:
    (i) Refinery block flow diagram, showing principal refining units;
    (ii) Principal refining unit charge rates and capacities;
    (iii) Crude types utilized (names, gravities, and sulfur content) 
and crude charge rates; and
    (iv) Information on the following units, if utilized in the 
refinery:
    (A) Catalytic Cracking Unit: conversion, unit yields, gasoline fuel 
parameter values (per Sec. 80.91(a)(2));
    (B) Hydrocracking Unit: unit yields, gasoline fuel parameter values 
(per Sec. 80.91(a)(2));
    (C) Catalytic Reformer: unit yields, severities;
    (D) Bottoms Processing Units (including, but not limited to, coking, 
extraction and hydrogen processing): gasoline stream yields;

[[Page 763]]

    (E) Yield structures for other principal units in the refinery 
(including but not limited to Alkylation, Polymerization, Isomerization, 
Etherification, Steam Cracking).
    (d) Requirements for a petition applicable to gasoline produced or 
imported for use in Alaska, Hawaii, the Commonwealth of Puerto Rico, and 
the Virgin Islands. (1)(i) Any refiner for any refinery or importer with 
gasoline produced or imported for use in Alaska in its individual 1990 
baseline may petition EPA to establish a separate 1990 baseline for 
gasoline produced or imported for use in Alaska using the winter Complex 
Model, and to use the winter statutory baseline values under Sec. 
80.91(c)(5) for any gasoline produced or imported for use in Alaska 
which is in excess of the refinery's or importer's 1990 volume of 
gasoline produced or imported for use in Alaska for purposes of 
determining the refinery's or importer's compliance baseline under Sec. 
80.101(f)(4).
    (ii) Any refiner for any refinery or importer with an individual 
1990 baseline which did not include any gasoline produced or imported 
for use in Alaska in 1990 may petition EPA to establish the refinery's 
or importer's winter baseline values as the compliance baseline under 
Sec. 80.101(f)(3) for gasoline which the refiner or importer produces 
or imports for use in Alaska.
    (iii) Any refiner for any refinery or importer subject only to the 
anti-dumping statutory baseline under Sec. 80.91(c)(5) may petition EPA 
to have the winter statutory baseline values under Sec. 80.91(c)(5) 
apply instead for purposes of determining the refinery's or importer's 
compliance baseline under Sec. 80.101(f)(2) for gasoline which the 
refiner or importer produces or imports for use in Alaska.
    (2)(i) Any refiner for any refinery or importer with gasoline 
produced or imported for use in Hawaii, and/or the Commonwealth of 
Puerto Rico, and/or the Virgin Islands in its individual 1990 baseline 
may petition EPA to establish a separate 1990 baseline for gasoline 
produced or imported for use in these areas using the summer Complex 
Model, and to use the summer statutory baseline values under Sec. 
80.91(c)(5) for any gasoline produced or imported for use in these areas 
in excess of the refinery's or importer's 1990 volume of gasoline 
produced or imported for use in these areas, for purposes of determining 
the refinery's or importer's compliance baseline under Sec. 
80.101(f)(4).
    (ii) Any refiner for any refinery or importer with an individual 
1990 baseline which did not include any gasoline produced or imported 
for use in Hawaii, and/or the Commonwealth of Puerto Rico, and/or the 
Virgin Islands in 1990 may petition EPA to establish the refinery's or 
importer's summer baseline values as the compliance baseline under Sec. 
80.101(f)(3) for gasoline which the refiner or importer produces or 
imports for use in these areas.
    (iii) Any refiner or importer subject only to the anti-dumping 
statutory baseline under Sec. 80.91(c)(5) may petition EPA to have the 
summer statutory baseline values under Sec. 80.91(c)(5) apply instead 
for purposes of determining the refinery's or importer's compliance 
baseline under Sec. 80.101(f)(2) for gasoline which the refiner or 
importer produces or imports for use in Hawaii, and/or the Commonwealth 
of Puerto Rico, and/or the Virgin Islands.
    (iv) Any petition submitted in accordance with paragraphs (d)(2)(i), 
(d)(2)(ii) or (d)(2)(iii) of this section shall apply to gasoline 
produced or imported for use in all of the areas specified in the 
operative paragraphs.
    (3) A petition under paragraphs (d)(1) or (d)(2) of this section 
must include the following:
    (i) Identification of the refiner and refinery or importer;
    (ii) EPA company and facility registration numbers issued under 
Sec. 80.76;
    (iii) Identification of a contact person; and
    (iv) For petitions submitted under paragraphs (d)(1)(i) and 
(d)(2)(i) of this section:
    (A) Revised 1990 individual baseline determination wherein the 
baseline for gasoline produced or imported for use in Alaska has been 
evaluated using the winter Complex Model, or gasoline produced or 
imported for use in Hawaii, and/or the Commonwealth of Puerto Rico, and/
or the Virgin Islands has been evaluated using the summer Complex Model, 
as applicable, with the calculations clearly and fully described and 
displayed; and

[[Page 764]]

    (B) Revised 1990 individual baseline determination for gasoline in 
the refinery's or importer's original individual 1990 baseline which was 
not produced or imported for use in Alaska, and/or Hawaii, and/or the 
Commonwealth of Puerto Rico, and/or the Virgin Islands, as applicable, 
with the calculations clearly and fully described and displayed.
    (C) Baseline auditor agreement with the revised baseline values.
    (4) For U.S. Postal delivery, the petition shall be sent to: Attn: 
RFG Program, Mailstop 6406J, U.S. Environmental Protection Agency, 1200 
Pennsylvania Avenue, NW., Washington, DC 20460. For commercial delivery: 
Attn: RFG Program, 6th Floor (202-343-9038), U.S. Environmental 
Protection Agency, 1310 L St., NW., Washington, DC 20005.
    (5) EPA reserves the right to request additional information. If 
such information is not forthcoming in a timely manner, the petition 
will not be approved.
    (6) A petition under this section may be submitted at any time 
during the annual averaging period. The baseline and compliance methods 
approved in a petition submitted under paragraph (d) of this section 
shall apply beginning with the annual averaging period in which the 
petition was approved and shall continue to apply in each annual 
averaging period thereafter. Once a petition has been approved under 
this section, the refiner or importer may not revert back to its 
original baseline.
    (7) A refiner for any refinery or importer with an approved petition 
under paragraph (d)(1) of this section and an approved petition under 
paragraph (d)(2) of this section will be subject to a separate baseline 
and baseline volume for its gasoline produced or imported for use in 
Alaska, and a separate baseline and baseline volume for its gasoline 
produced or imported for use in Hawaii, the Commonwealth of Puerto Rico 
and the Virgin Islands.
    (8)(i) Any refiner for any refinery or importer must have an 
approved petition under paragraph (d)(1) of this section in order to use 
the seasonal baseline and seasonal Complex Model, as provided in 
paragraph (d)(1) of this section, for gasoline produced or imported for 
use in Alaska.
    (ii) Any refiner for any refinery or importer must have an approved 
petition under paragraph (d)(2) of this section in order to use the 
seasonal baseline and seasonal Complex Model, as provided in paragraph 
(d)(2) of this section, for gasoline produced or imported for use in 
Hawaii, the Commonwealth of Puerto Rico, and the Virgin Islands.
    (iii) Any new refiner or importer without an individual anti-dumping 
baseline shall be subject to the annual average anti-dumping statutory 
baseline under Sec. 80.91(c)(5) unless the refiner or importer 
petitions for and receives approval of use of a seasonal baseline and 
seasonal Complex Model under this section.
    (9)(i) The provisions of this paragraph (d) shall apply to any 
refiner, for any refinery, or importer that received approval of a 
petition under this paragraph (d) prior to November 26, 2007 beginning 
with the 2008 annual averaging period.
    (ii) Any refiner, for any refinery, or importer that received 
approval of a petition under paragraph (d) of this section prior to 
November 26, 2007 may petition EPA to withdraw such approval. Such 
petition must be submitted to EPA by December 31, 2007. A withdrawal of 
approval under this paragraph is effective beginning with the 2008 
annual averaging period and shall remain in effect in each annual 
averaging period thereafter.
    (iii) A refiner or importer with an approved withdrawal under 
paragraph (d)(9)(i) of this section will be subject to the baseline 
which was in effect prior to the effective date of the refiner's or 
importer's approved petition under this paragraph (d). Once a refiner or 
importer receives approval of a withdrawal of a petition under paragraph 
(d)(9)(i) of this section the refiner or importer is ineligible to 
receive approval of a change in baseline under this section.

[59 FR 7860, Feb. 16, 1994, as amended at 59 FR 36968, July 20, 1994; 60 
FR 65575, Dec. 20, 1995; 64 FR 30910, June 9, 1999; 72 FR 60579, Oct. 
25, 2007]

[[Page 765]]



Sec. 80.94  Requirements for gasoline produced at foreign refineries.

    (a) Definitions. (1) A foreign refinery is a refinery that is 
located outside the United States, including the Commonwealth of Puerto 
Rico, the Virgin Islands, Guam, American Samoa, and the Commonwealth of 
the Northern Mariana Islands (collectively referred to in this section 
as ``the United States'').
    (2) A foreign refiner is a person who meets the definition of 
refiner under Sec. 80.2(i) for foreign refinery.
    (3) FRGAS means gasoline produced at a foreign refinery that has 
been assigned an individual refinery baseline and that is imported into 
the United States.
    (4) Non-FRGAS means gasoline that is produced at a foreign refinery 
that has not been assigned an individual refinery baseline, gasoline 
produced at a foreign refinery with an individual refinery baseline that 
is not imported into the United States, and gasoline produced at a 
foreign refinery with an individual baseline during a year when the 
foreign refiner has opted to not participate in the FRGAS program under 
paragraph (c)(3) of this section.
    (5) Certified FRGAS means FRGAS the foreign refiner intends to 
include in the foreign refinery's NOX and exhaust toxics 
compliance calculations under Sec. 80.101(g), and does include in these 
compliance calculations when reported to EPA.
    (6) Non-certified FRGAS means FRGAS that is not certified FRGAS.
    (b) Baseline establishment. Any foreign refiner may submit to EPA a 
petition for an individual refinery baseline, under Sec. Sec. 80.90 
through 80.93.
    (1) The provisions for baselines as specified in Sec. Sec. 80.90 
through 80.93 shall apply to a foreign refinery, except where provided 
otherwise in this section.
    (2) The baseline for a foreign refinery shall reflect only the 
volume and properties of gasoline produced in 1990 that was imported 
into the United States.
    (3) A baseline petition shall establish the volume of conventional 
gasoline produced at a foreign refinery and imported into the United 
States during the calendar year immediately preceding the year the 
baseline petition is submitted.
    (4) In making determinations for foreign refinery baselines EPA will 
consider all information supplied by a foreign refiner, and in addition 
may rely on any and all appropriate assumptions necessary to make such a 
determination.
    (5) Where a foreign refiner submits a petition that is incomplete or 
inadequate to establish an accurate baseline, and the refiner fails to 
cure this defect after a request for more information, then EPA shall 
not assign an individual refinery baseline.
    (6) Baseline petitions under this paragraph (b) of this section must 
be submitted before January 1, 2002.
    (c) General requirements for foreign refiners with individual 
refinery baselines. Any foreign refiner of a refinery that has been 
assigned an individual baseline under paragraph (b) of this section 
shall designate all gasoline produced at the foreign refinery that is 
exported to the United States as either certified FRGAS or as non-
certified FRGAS, except as provided in paragraph (c)(3) of this section.
    (1)(i) In the case of certified FRGAS, the foreign refiner shall 
meet all requirements that apply to refiners under 40 CFR part 80, 
subparts D, E and F.
    (ii) If the foreign refinery baseline is assigned, or a foreign 
refiner begins early use of a refinery baseline under paragraph (r) of 
this section, on a date other than January 1, the compliance baseline 
for the initial year shall be calculated under Sec. 80.101(f) using an 
adjusted baseline volume, as follows:

AV1990 = (D/365) x V1990

where:

AV1990 = Adjusted 1990 baseline volume
D = Number of days remaining in the year, beginning with the day the 
foreign refinery baseline is approved or the day the foreign refiner 
begins early use of a refinery baseline, whichever is later
V1990 = Foreign refinery's 1990 baseline volume.

    (2) In the case of non-certified FRGAS, the foreign refiner shall 
meet the following requirements, except the foreign refiner shall 
substitute the name ``non-certified FRGAS'' for the names ``reformulated 
gasoline'' or ``RBOB'' wherever they appear in the following 
requirements:

[[Page 766]]

    (i) The designation requirements in Sec. 80.65(d)(1);
    (ii) The recordkeeping requirements in Sec. 80.74 (a), and (b)(3);
    (iii) The reporting requirements in Sec. 80.75 (a), (m), and (n);
    (iv) The registration requirements in Sec. 80.76;
    (v) The product transfer document requirements in Sec. 80.77 (a) 
through (f), and (j);
    (vi) The prohibition in Sec. 80.78(a)(10), (b) and (c); and
    (vii) The independent audit requirements in Sec. Sec. 80.125 
through 80.127, 80.128 (a) through (c), and (g) through (i), and 80.130.
    (3)(i) Any foreign refiner that has been assigned an individual 
baseline for a foreign refinery under paragraph (b) of this section may 
elect to classify no gasoline imported into the United States as FRGAS, 
provided the foreign refiner notifies EPA of the election no later than 
November 1 of the prior calendar year.
    (ii) An election under paragraph (c)(3)(i) of this section shall:
    (A) Be for an entire calendar year averaging period and apply to all 
gasoline produced during the calendar year at the foreign refinery that 
is imported into the United States; and
    (B) Remain in effect for each succeeding calendar year averaging 
period, unless and until the foreign refiner notifies EPA of a 
termination of the election. The change in election shall take effect at 
the beginning of the next calendar year.
    (iii) A foreign refiner who has aggregated refineries under Sec. 
80.101(h) shall make the same election under paragraph (c)(3)(i) of this 
section for all refineries in the aggregation.
    (d) Designation, product transfer documents, and foreign refiner 
certification. (1) Any foreign refiner of a foreign refinery that has 
been assigned an individual baseline shall designate each batch of FRGAS 
as such at the time the gasoline is produced, unless the foreign refiner 
has elected to classify no gasoline exported to the United States as 
FRGAS under paragraph (c)(3)(i) of this section.
    (2) On each occasion when any person transfers custody or title to 
any FRGAS prior to its being imported into the United States, the 
following information shall be included as part of the product transfer 
document information in Sec. Sec. 80.77 and 80.106:
    (i) Identification of the gasoline as certified FRGAS or as non-
certified FRGAS; and
    (ii) The name and EPA refinery registration number of the refinery 
where the FRGAS was produced.
    (3) On each occasion when FRGAS is loaded onto a vessel or other 
transportation mode for transport to the United States, the foreign 
refiner shall prepare a certification for each batch of the FRGAS that 
meets the following requirements:
    (i) The certification shall include the report of the independent 
third party under paragraph (f) of this section, and the following 
additional information:
    (A) The name and EPA registration number of the refinery that 
produced the FRGAS;
    (B) The identification of the gasoline as certified FRGAS or non-
certified FRGAS;
    (C) The volume of FRGAS being transported, in gallons;
    (D) A declaration that the FRGAS is being included in the compliance 
baseline calculations under Sec. 80.101(f) for the refinery that 
produced the FRGAS; and
    (E) In the case of certified FRGAS:
    (1) The values for each parameter required to calculate 
NOX and exhaust toxics emissions performance as determined 
under paragraph (f) of this section; and
    (2) A declaration that the FRGAS is being included in the compliance 
calculations under Sec. 80.101(g) for the refinery that produced the 
FRGAS.
    (ii) The certification shall be made part of the product transfer 
documents for the FRGAS.
    (e) Transfers of FRGAS to non-United States markets. The foreign 
refiner is responsible to ensure that all gasoline classified as FRGAS 
is imported into the United States. A foreign refiner may remove the 
FRGAS classification, and the gasoline need not be imported into the 
United States, but only if:
    (1)(i) The foreign refiner excludes:
    (A) The volume of gasoline from the refinery's compliance baseline 
calculations under Sec. 80.101(h); and

[[Page 767]]

    (B) In the case of certified FRGAS, the volume and parameter values 
of the gasoline from the compliance calculations under Sec. 80.101(g);
    (ii) The exclusions under paragraph (e)(1)(i) of this section shall 
be on the basis of the parameter and volumes determined under paragraph 
(f) of this section; and
    (2) The foreign refiner obtains sufficient evidence in the form of 
documentation that the gasoline was not imported into the United States.
    (f) Load port independent sampling, testing and refinery 
identification. (1) On each occasion FRGAS is loaded onto a vessel for 
transport to the United States a foreign refiner shall have an 
independent third party:
    (i) Inspect the vessel prior to loading and determine the volume of 
any tank bottoms;
    (ii) Determine the volume of FRGAS loaded onto the vessel (exclusive 
of any tank bottoms present before vessel loading);
    (iii) Obtain the EPA-assigned registration number of the foreign 
refinery;
    (iv) Determine the name and country of registration of the vessel 
used to transport the FRGAS to the United States; and
    (v) Determine the date and time the vessel departs the port serving 
the foreign refinery.
    (2) On each occasion certified FRGAS is loaded onto a vessel for 
transport to the United States a foreign refiner shall have an 
independent third party:
    (i) Collect a representative sample of the certified FRGAS from each 
vessel compartment subsequent to loading on the vessel and prior to 
departure of the vessel from the port serving the foreign refinery;
    (ii) Prepare a volume-weighted vessel composite sample from the 
compartment samples, and determine the values for sulfur, benzene, 
gravity, E200 and E300 using the methodologies specified in Sec. 80.46, 
by:
    (A) The third party analyzing the sample; or
    (B) The third party observing the foreign refiner analyze the 
sample;
    (iii) Determine the values for aromatics, olefins, RVP and each 
oxygenate specified in Sec. 80.65(e)(2) for the gasoline loaded onto 
the vessel, by:
    (A) Completing the analysis procedures under paragraph (f)(2)(ii) of 
this section for the additional parameters; or
    (B) Obtaining from the foreign refiner the test results of samples 
collected from each shore tank containing gasoline that was loaded onto 
the vessel, and calculating the parameter values for the gasoline loaded 
onto the vessel from the tank parameter values and the gasoline volume 
from each such shore tank that was loaded;
    (iv) Review original documents that reflect movement and storage of 
the certified FRGAS from the refinery to the load port, and from this 
review determine:
    (A) The refinery at which the FRGAS was produced; and
    (B) That the FRGAS remained segregated from:
    (1) Non-FRGAS and non-certified FRGAS; and
    (2) Other certified FRGAS produced at a different refinery, except 
that certified FRGAS may be combined with other certified FRGAS produced 
at refineries that are aggregated under Sec. 80.101(h);
    (3) The independent third party shall submit a report:
    (i) To the foreign refiner containing the information required under 
paragraphs (f) (1) and (2) of this section, to accompany the product 
transfer documents for the vessel; and
    (ii) To the Administrator containing the information required under 
paragraphs (f) (1) and (2) of this section, within thirty days following 
the date of the independent third party's inspection. This report shall 
include a description of the method used to determine the identity of 
the refinery at which the gasoline was produced, that the gasoline 
remained segregated as specified in paragraph (n)(1) of this section, 
and a description of the gasoline's movement and storage between 
production at the source refinery and vessel loading.
    (4) A person may be used to meet the third party requirements in 
this paragraph (f) only if:
    (i) The person is approved in advance by EPA, based on a 
demonstration of

[[Page 768]]

ability to perform the procedures required in this paragraph (f);
    (ii) The person is independent under the criteria specified in Sec. 
80.65(f)(2)(iii); and
    (iii) The person signs a commitment that contains the provisions 
specified in paragraph (i) of this section with regard to activities, 
facilities and documents relevant to compliance with the requirements of 
this paragraph (f).
    (g) Comparison of load port and port of entry testing. (1)(i) Any 
foreign refiner and any United States importer of certified FRGAS shall 
compare the results from the load port testing under paragraph (f) of 
this section, with the port of entry testing as reported under paragraph 
(o) of this section, for the volume of gasoline, for the parameter 
values for sulfur, benzene, gravity, E200 and E300, and for the 
NOX and exhaust toxics emissions performance; except that
    (ii) Where a vessel transporting certified FRGAS off loads this 
gasoline at more than one United States port of entry, and the 
conditions of paragraph (g)(2)(i) of this section are not met at the 
first United States port of entry, the requirements of paragraph (g)(1) 
and (g)(2) of this section do not apply at subsequent ports of entry if 
the United States importer obtains a certification from the vessel owner 
or his immediate designee that the vessel has not loaded any gasoline or 
blendstock between the first United States port of entry and the 
subsequent port of entry.
    (2)(i) The requirements of paragraph (g)(2)(ii) apply if:
    (A)(1) The temperature-corrected volumes determined at the port of 
entry and at the load port differ by more than one percent; or
    (2) For any parameter specified in paragraph (f)(2)(ii) of this 
section, the values determined at the port of entry and at the load port 
differ by more than the reproducibility amount specified for the port of 
entry test result by the American Society of Testing and Materials 
(ASTM); unless
    (B) The NOX and exhaust toxics emissions performance, in 
grams per mile, calculated using the port of entry test results, are 
each equal to or less than the NOX and exhaust toxics 
emissions performance calculated using the load port test results;
    (ii) The United States importer and the foreign refiner shall treat 
the gasoline as non-certified FRGAS, and the foreign refiner shall:
    (A) Exclude the gasoline volume and properties from its conventional 
gasoline NOX and exhaust toxics compliance calculations under 
Sec. 80.101(g); and
    (B) Include the gasoline volume in its compliance baseline 
calculation under Sec. 80.101(f), unless the foreign refiner 
establishes that the United States importer classified the gasoline only 
as conventional gasoline and not as reformulated gasoline.
    (h) Attest requirements. The following additional procedures shall 
be carried out by any foreign refiner of FRGAS as part of the attest 
engagement for each foreign refinery under 40 CFR part 80, subpart F.
    (1) Include in the inventory reconciliation analysis under Sec. 
80.128(b) and the tender analysis under Sec. 80.128(c) non-FRGAS in 
addition to the gasoline types listed in Sec. 80.128 (b) and (c).
    (2) Obtain separate listings of all tenders of certified FRGAS, and 
of non-certified FRGAS. Agree the total volume of tenders from the 
listings to the gasoline inventory reconciliation analysis in Sec. 
80.128(b), and to the volumes determined by the third party under 
paragraph (f)(1) of this section.
    (3) For each tender under paragraph (h)(2) of this section where the 
gasoline is loaded onto a marine vessel, report as a finding the name 
and country of registration of each vessel, and the volumes of FRGAS 
loaded onto each vessel.
    (4) Select a sample from the list of vessels identified in paragraph 
(h)(3) of this section used to transport certified FRGAS, in accordance 
with the guidelines in Sec. 80.127, and for each vessel selected 
perform the following:
    (i) Obtain the report of the independent third party, under 
paragraph (f) of this section, and of the United States importer under 
paragraph (o) of this section.
    (A) Agree the information in these reports with regard to vessel 
identification, gasoline volumes and test results.
    (B) Identify, and report as a finding, each occasion the load port 
and port of

[[Page 769]]

entry parameter and volume results differ by more than the amounts 
allowed in paragraph (g) of this section, and determine whether the 
foreign refiner adjusted its refinery calculations as required in 
paragraph (g) of this section.
    (ii) Obtain the documents used by the independent third party to 
determine transportation and storage of the certified FRGAS from the 
refinery to the load port, under paragraph (f) of this section. Obtain 
tank activity records for any storage tank where the certified FRGAS is 
stored, and pipeline activity records for any pipeline used to transport 
the certified FRGAS, prior to being loaded onto the vessel. Use these 
records to determine whether the certified FRGAS was produced at the 
refinery that is the subject of the attest engagement, and whether the 
certified FRGAS was mixed with any non-certified FRGAS, non-FRGAS, or 
any certified FRGAS produced at a different refinery that was not 
aggregated under Sec. 80.101(h).
    (5)(i) Select a sample from the list of vessels identified in 
paragraph (h)(3) of this section used to transport certified and non-
certified FRGAS, in accordance with the guidelines in Sec. 80.127, and 
for each vessel selected perform the following:
    (ii) Obtain a commercial document of general circulation that lists 
vessel arrivals and departures, and that includes the port and date of 
departure of the vessel, and the port of entry and date of arrival of 
the vessel. Agree the vessel's departure and arrival locations and dates 
from the independent third party and United States importer reports to 
the information contained in the commercial document.
    (6) Obtain separate listings of all tenders of non-FRGAS, and 
perform the following:
    (i) Agree the total volume of tenders from the listings to the 
gasoline inventory reconciliation analysis in Sec. 80.128(b).
    (ii) Obtain a separate listing of the tenders under paragraph (h)(6) 
of this section where the gasoline is loaded onto a marine vessel. 
Select a sample from this listing in accordance with the guidelines in 
Sec. 80.127, and obtain a commercial document of general circulation 
that lists vessel arrivals and departures, and that includes the port 
and date of departure and the ports and dates where the gasoline was off 
loaded for the selected vessels. Determine and report as a finding the 
country where the gasoline was off loaded for each vessel selected.
    (7) In order to complete the requirements of this paragraph (h) an 
auditor shall:
    (i) Be independent of the foreign refiner;
    (ii) Be licensed as a Certified Public Accountant in the United 
States and a citizen of the United States, or be approved in advance by 
EPA based on a demonstration of ability to perform the procedures 
required in Sec. Sec. 80.125 through 80.130 and this paragraph (h); and
    (iii) Sign a commitment that contains the provisions specified in 
paragraph (i) of this section with regard to activities and documents 
relevant to compliance with the requirements of Sec. Sec. 80.125 
through 80.130 and this paragraph (h).
    (i) Foreign refiner commitments. Any foreign refiner shall commit to 
and comply with the provisions contained in this paragraph (i) as a 
condition to being assigned an individual refinery baseline.
    (1) Any United States Environmental Protection Agency inspector or 
auditor will be given full, complete and immediate access to conduct 
inspections and audits of the foreign refinery.
    (i) Inspections and audits may be either announced in advance by 
EPA, or unannounced.
    (ii) Access will be provided to any location where:
    (A) Gasoline is produced;
    (B) Documents related to refinery operations are kept;
    (C) Gasoline or blendstock samples are tested or stored; and
    (D) FRGAS is stored or transported between the foreign refinery and 
the United States, including storage tanks, vessels and pipelines.
    (iii) Inspections and audits may be by EPA employees or contractors 
to EPA.
    (iv) Any documents requested that are related to matters covered by 
inspections and audits will be provided to

[[Page 770]]

an EPA inspector or auditor on request.
    (v) Inspections and audits by EPA may include review and copying of 
any documents related to:
    (A) Refinery baseline establishment, including the volume and 
parameters, and transfers of title or custody, of any gasoline or 
blendstocks, whether FRGAS or non-FRGAS, produced at the foreign 
refinery during the period January 1, 1990 through the date of the 
refinery baseline petition or through the date of the inspection or 
audit if a baseline petition has not been approved, and any work papers 
related to refinery baseline establishment;
    (B) The parameters and volume of FRGAS;
    (C) The proper classification of gasoline as being FRGAS or as not 
being FRGAS, or as certified FRGAS or as non-certified FRGAS;
    (D) Transfers of title or custody to FRGAS;
    (E) Sampling and testing of FRGAS;
    (F) Work performed and reports prepared by independent third parties 
and by independent auditors under the requirements of this section, 
including work papers; and
    (G) Reports prepared for submission to EPA, and any work papers 
related to such reports.
    (vi) Inspections and audits by EPA may include taking samples of 
gasoline or blendstock, and interviewing employees.
    (vii) Any employee of the foreign refiner will be made available for 
interview by the EPA inspector or auditor, on request, within a 
reasonable time period.
    (viii) English language translations of any documents will be 
provided to an EPA inspector or auditor, on request, within 10 working 
days.
    (ix) English language interpreters will be provided to accompany EPA 
inspectors and auditors, on request.
    (2) An agent for service of process located in the District of 
Columbia will be named, and service on this agent constitutes service on 
the foreign refiner or any officer, or employee of the foreign refiner 
for any action by EPA or otherwise by the United States related to the 
requirements of 40 CFR part 80, subparts D, E and F.
    (3) The forum for any civil or criminal enforcement action related 
to the provisions of this section for violations of the Clean Air Act or 
regulations promulgated thereunder shall be governed by the Clean Air 
Act, including the EPA administrative forum where allowed under the 
Clean Air Act.
    (4) United States substantive and procedural laws shall apply to any 
civil or criminal enforcement action against the foreign refiner or any 
employee of the foreign refiner related to the provisions of this 
section.
    (5) Submitting a petition for an individual refinery baseline, 
producing and exporting gasoline under an individual refinery baseline, 
and all other actions to comply with the requirements of 40 CFR part 80, 
subparts D, E and F relating to the establishment and use of an 
individual refinery baseline constitute actions or activities covered by 
and within the meaning of 28 U.S.C. 1605(a)(2), but solely with respect 
to actions instituted against the foreign refiner, its agents, officers, 
and employees in any court or other tribunal in the United States for 
conduct that violates the requirements applicable to the foreign refiner 
under 40 CFR part 80, subparts D, E and F, including such conduct that 
violates Title 18 U.S.C. section 1001, Clean Air Act section 113(c)(2), 
or other applicable provisions of the Clean Air Act.
    (6) The foreign refiner, or its agents, officers, or employees, will 
not seek to detain or to impose civil or criminal remedies against EPA 
inspectors or auditors, whether EPA employees or EPA contractors, for 
actions performed within the scope of EPA employment related to the 
provisions of this section.
    (7) The commitment required by this paragraph (i) shall be signed by 
the owner or president of the foreign refiner business.
    (8) In any case where FRGAS produced at a foreign refinery is stored 
or transported by another company between the refinery and the vessel 
that transports the FRGAS to the United States, the foreign refiner 
shall obtain from each such other company a commitment that meets the 
requirements specified in paragraphs (i) (1) through

[[Page 771]]

(7) of this section, and these commitments shall be included in the 
foreign refiner's baseline petition.
    (j) Sovereign immunity. By submitting a petition for an individual 
foreign refinery baseline under this section, or by producing and 
exporting gasoline to the United States under an individual refinery 
baseline under this section, the foreign refiner, its agents, officers, 
and employees, without exception, become subject to the full operation 
of the administrative and judicial enforcement powers and provisions of 
the United States without limitation based on sovereign immunity, with 
respect to actions instituted against the foreign refiner, its agents, 
officers, and employees in any court or other tribunal in the United 
States for conduct that violates the requirements applicable to the 
foreign refiner under 40 CFR part 80, subparts D, E and F, including 
such conduct that violates Title 18 U.S.C. section 1001, Clean Air Act 
section 113(c)(2), or other applicable provisions of the Clean Air Act.
    (k) Bond posting. Any foreign refiner shall meet the requirements of 
this paragraph (k) as a condition to being assigned an individual 
refinery baseline.
    (1) The foreign refiner shall post a bond of the amount calculated 
using the following equation:

Bond = G x $0.01

where:

Bond = amount of the bond in U.S. dollars
G = the largest volume of conventional gasoline produced at the foreign 
refinery and exported to the United States, in gallons, during a single 
calendar year among the most recent of the following calendar years, up 
to a maximum of five calendar years: the calendar year immediately 
preceding the date the baseline petition is submitted, the calendar year 
the baseline petition is submitted, and each succeeding calendar year

    (2) Bonds shall be posted by:
    (i) Paying the amount of the bond to the Treasurer of the United 
States;
    (ii) Obtaining a bond in the proper amount from a third party surety 
agent that is payable to satisfy United States judicial judgments 
against the foreign refiner, provided EPA agrees in advance as to the 
third party and the nature of the surety agreement; or
    (iii) An alternative commitment that results in assets of an 
appropriate liquidity and value being readily available to the United 
States, provided EPA agrees in advance as to the alternative commitment.
    (3) If the bond amount for a foreign refinery increases the foreign 
refiner shall increase the bond to cover the shortfall within 90 days of 
the date the bond amount changes. If the bond amount decreases, the 
foreign refiner may reduce the amount of the bond beginning 90 days 
after the date the bond amount changes.
    (4) Bonds posted under this paragraph (k) shall be used to satisfy 
any judicial judgment that results from an administrative or judicial 
enforcement action for conduct in violation of 40 CFR part 80, subparts 
D, E and F, including such conduct that violates Title 18 U.S.C. section 
1001, Clean Air Act section 113(c)(2), or other applicable provisions of 
the Clean Air Act.
    (5) On any occasion a foreign refiner bond is used to satisfy any 
judgment, the foreign refiner shall increase the bond to cover the 
amount used within 90 days of the date the bond is used.
    (l) Blendstock tracking. For purposes of blendstock tracking by any 
foreign refiner under Sec. 80.102 by a foreign refiner with an 
individual refinery baseline, the foreign refiner may exclude from the 
calculations required in Sec. 80.102(d) the volume of applicable 
blendstocks for which the foreign refiner has sufficient evidence in the 
form of documentation that the blendstocks were used to produce gasoline 
used outside the United States.
    (m) English language reports. Any report or other document submitted 
to EPA by any foreign refiner shall be in the English language, or shall 
include an English language translation.
    (n) Prohibitions. (1) No person may combine certified FRGAS with any 
non-certified FRGAS or non-FRGAS, and no person may combine certified 
FRGAS with any certified FRGAS produced at a different refinery that is 
not aggregated under Sec. 80.101(h), except as provided in paragraph 
(e) of this section.
    (2) No foreign refiner or other person may cause another person to 
commit an action prohibited in paragraph (n)(1)

[[Page 772]]

of this section, or that otherwise violates the requirements of this 
section.
    (o) United States importer requirements. Any United States importer 
shall meet the following requirements.
    (1) Each batch of imported gasoline shall be classified by the 
importer as being FRGAS or as non-FRGAS, and each batch classified as 
FRGAS shall be further classified as certified FRGAS or as non-certified 
FRGAS.
    (2) Gasoline shall be classified as certified FRGAS or as non-
certified FRGAS according to the designation by the foreign refiner if 
this designation is supported by product transfer documents prepared by 
the foreign refiner as required in paragraph (d) of this section, unless 
the gasoline is classified as non-certified FRGAS under paragraph (g) of 
this section.
    (3) For each gasoline batch classified as FRGAS, any United States 
importer shall perform the following procedures.
    (i) In the case of both certified and non-certified FRGAS, have an 
independent third party:
    (A) Determine the volume of gasoline in the vessel;
    (B) Use the foreign refiner's FRGAS certification to determine the 
name and EPA-assigned registration number of the foreign refinery that 
produced the FRGAS;
    (C) Determine the name and country of registration of the vessel 
used to transport the FRGAS to the United States; and
    (D) Determine the date and time the vessel arrives at the United 
States port of entry.
    (ii) In the case of certified FRGAS, have an independent third 
party:
    (A) Collect a representative sample from each vessel compartment 
subsequent to the vessel's arrival at the United States port of entry 
and prior to off loading any gasoline from the vessel;
    (B) Prepare a volume-weighted vessel composite sample from the 
compartment samples; and
    (C) Determine the values for sulfur, benzene, gravity, E200 and E300 
using the methodologies specified in Sec. 80.46, by:
    (1) The third party analyzing the sample; or
    (2) The third party observing the importer analyze the sample
    (4) Any importer shall submit reports within thirty days following 
the date any vessel transporting FRGAS arrives at the United States port 
of entry:
    (i) To the Administrator containing the information determined under 
paragraph (o)(3) of this section; and
    (ii) To the foreign refiner containing the information determined 
under paragraph (o)(3)(ii) of this section.
    (5)(i) Any United States importer shall meet the requirements 
specified for conventional gasoline in Sec. 80.101 for any imported 
conventional gasoline that is not classified as certified FRGAS under 
paragraph (o)(2) of this section.
    (ii) The baseline applicable to a United States importer who has not 
been assigned an individual importer baseline under Sec. 80.91(b)(4) 
shall be the baseline specified in paragraph (p) of this section.
    (p) Importer Baseline. (1) Each calendar year starting in 2000, the 
Administrator shall calculate the volume weighted average NOX 
emissions of imported conventional gasoline for a multi-year period 
(MYANOx). This calculation:
    (i) Shall use the Phase II Complex Model;
    (ii) Shall include all conventional gasoline in the following 
categories:
    (A) Imported conventional gasoline that is classified as 
conventional gasoline, and included in the conventional gasoline 
compliance calculations of importers for each year; and
    (B) Imported conventional gasoline that is classified as certified 
FRGAS, and included in the conventional gasoline compliance calculations 
of foreign refiners for each year;
    (iii)(A) In 2000 only, shall be for the 1998 and 1999 averaging 
periods and also shall include all conventional gasoline classified as 
FRGAS and included in the conventional gasoline compliance calculations 
of a foreign refiner for 1997, and all conventional gasoline batches not 
classified as FRGAS that are imported during 1997 beginning on the date 
the first batch of FRGAS arrives at a United States port of entry; and

[[Page 773]]

    (B) Starting in 2001, shall include imported conventional gasoline 
during the prior three calendar year averaging periods.
    (2)(i) If the volume-weighted average NOX emissions 
(MYANOx), calculated in paragraph (p)(1) of this section, is 
greater than 1,465 mg/mile, the Administrator shall calculate an 
adjusted baseline for NOX according to the following 
equation:

ABNOx = 1,465 mg/mile - (MYANOx - 1,465 mg/mile)

where:

ABNOx = Adjusted NOX baseline, in mg/mile
MYANOx = Multi-year average NOX emissions, in mg/
mile

    (ii) For the 1998 and 1999 multi-year averaging period only the 
value of ABNOx shall not be larger than 1,480 mg/mile 
regardless of the calculation under paragraph (p)(2)(i) of this section.
    (3)(i) Notwithstanding the provisions of Sec. 80.91(b)(4)(iii), the 
baseline NOX emissions values applicable to any United States 
importer who has not been assigned an individual importer baseline under 
Sec. 80.91(b)(4) shall be the more stringent of the statutory baseline 
value for NOX under Sec. 80.91(c)(5), or the adjusted 
NOX baseline calculated in paragraph (p)(2) of this section.
    (ii) On or before June 1 of each calendar year, the Administrator 
shall announce the NOX baseline that applies to importers 
under this paragraph (p). If the baseline is an adjusted baseline, it 
shall be effective for any conventional gasoline imported beginning 60 
days following the Administrator's announcement. If the baseline is the 
statutory baseline, it shall be effective upon announcement. A baseline 
shall remain in effect until the effective date of a subsequent change 
to the baseline pursuant to this paragraph (p).
    (q) Withdrawal or suspension of a foreign refinery's baseline. EPA 
may withdraw or suspend a baseline that has been assigned to a foreign 
refinery where:
    (1) A foreign refiner fails to meet any requirement of this section;
    (2) A foreign government fails to allow EPA inspections as provided 
in paragraph (i)(1) of this section;
    (3) A foreign refiner asserts a claim of, or a right to claim, 
sovereign immunity in an action to enforce the requirements in 40 CFR 
part 80, subparts D, E and F; or
    (4) A foreign refiner fails to pay a civil or criminal penalty that 
is not satisfied using the foreign refiner bond specified in paragraph 
(k) of this section.
    (r) Early use of a foreign refinery baseline. (1) A foreign refiner 
may begin using an individual refinery baseline before EPA has approved 
the baseline, provided that:
    (i) A baseline petition has been submitted as required in paragraph 
(b) of this section;
    (ii) EPA has made a provisional finding that the baseline petition 
is complete;
    (iii) The foreign refiner has made the commitments required in 
paragraph (i) of this section;
    (iv) The persons who will meet the independent third party and 
independent attest requirements for the foreign refinery have made the 
commitments required in paragraphs (f)(3)(iii) and (h)(7)(iii) of this 
section; and
    (v) The foreign refiner has met the bond requirements of paragraph 
(k) of this section.
    (2) In any case where a foreign refiner uses an individual refinery 
baseline before final approval under paragraph (r)(1) of this section, 
and the foreign refinery baseline values that ultimately are approved by 
EPA are more stringent than the early baseline values used by the 
foreign refiner, the foreign refiner shall recalculate its compliance, 
ab initio, using the baseline values approved by EPA, and the foreign 
refiner shall be liable for any resulting violation of the conventional 
gasoline requirements.
    (s) Additional requirements for petitions, reports and certificates. 
Any petition for a refinery baseline under paragraph (b) of this 
section, any report or other submission required by paragraphs (c), 
(f)(2), or (i) of this section, and any certification under paragraph 
(d)(3) or (g)(1)(ii) of this section shall be:
    (1) Submitted in accordance with procedures specified by the 
Administrator,

[[Page 774]]

including use of any forms that may specified by the Administrator.
    (2) Be signed by the president or owner of the foreign refiner 
company, or in the case of (g)(1)(ii) the vessel owner, or by that 
person's immediate designee, and shall contain the following 
declaration:

    I hereby certify: (1) that I have actual authority to sign on behalf 
of and to bind [insert name of foreign refiner or vessel owner] with 
regard to all statements contained herein; (2) that I am aware that the 
information contained herein is being certified, or submitted to the 
United States Environmental Protection Agency, under the requirements of 
40 CFR part 80, subparts D, E and F and that the information is material 
for determining compliance under these regulations; and (3) that I have 
read and understand the information being certified or submitted, and 
this information is true, complete and correct to the best of my 
knowledge and belief after I have taken reasonable and appropriate steps 
to verify the accuracy thereof.
    I affirm that I have read and understand that the provisions of 40 
CFR part 80, subparts D, E and F, including 40 CFR 80.94 (i), (j) and 
(k), apply to [insert name of foreign refiner or vessel owner]. Pursuant 
to Clean Air Act section 113(c) and Title 18, United States Code, 
section 1001, the penalty for furnishing false, incomplete or misleading 
information in this certification or submission is a fine of up to 
$10,000, and/or imprisonment for up to five years.

[62 FR 45563, Aug. 28, 1997]



Sec. Sec. 80.95-80.100  [Reserved]



Sec. 80.101  Standards applicable to refiners and importers.

    Any refiner or importer of conventional gasoline shall meet the 
standards specified in this section over the specified averaging period, 
beginning on January 1, 1995.
    (a) Averaging period. The averaging period for the standards 
specified in this section shall be January 1 through December 31, except 
as provided in paragraphs (k) and (l) of this section.
    (b) Conventional gasoline compliance standards--(1) Simple model 
standards. The simple model standards are the following:
    (i) Annual average exhaust benzene emissions, calculated according 
to paragraph (g)(1)(i) of this section, shall not exceed the refiner's 
or importer's compliance baseline for exhaust benzene emissions;
    (ii) Annual average levels of sulfur shall not exceed 125% of the 
refiner's or importer's compliance baseline for sulfur;
    (iii) Annual average levels of olefins shall not exceed 125% of the 
refiner's or importer's compliance baseline for olefins; and
    (iv) Annual average values of T-90 shall not exceed 125% of the 
refiner's or importer's compliance baseline for T-90.
    (2) Optional complex model standards. Annual average levels of 
exhaust benzene emissions, weighted by volume for each batch and 
calculated using the applicable complex model under Sec. 80.45, shall 
not exceed the refiner's or importer's 1990 average exhaust benzene 
emissions.
    (3) Complex model standards. (i) Annual average levels of exhaust 
toxics emissions and NOX emissions, weighted by volume for 
each batch and calculated using the applicable complex model under Sec. 
80.45, shall not exceed the refiner's or importer's compliance baseline 
for exhaust toxics and NOX emissions, respectively.
    (ii) Annual average levels of RVP, benzene, aromatics, olefins, 
sulfur, E200 and E300 shall not be greater than the conventional 
gasoline complex model valid range limits for the parameter under Sec. 
80.45(f)(1)(ii), or the refiner or importer's annual 1990 baseline for 
the parameter if outside the valid range limit, whichever is greater.
    (c) Applicability of standards. (1) For each averaging period prior 
to January 1, 1998, a refiner or importer shall be subject to either the 
Simple Model or Optional Complex Model Standards, at their option, 
except that any refiner or importer shall be subject to:
    (i) The Simple Model Standards if the refiner or importer uses the 
Simple Model Standards for reformulated gasoline; or
    (ii) The Optional Complex Model Standards if the refiner or importer 
used the Complex Model Standards for reformulated gasoline.
    (2) Beginning January 1, 1998, each refiner and importer shall be 
subject to the Complex Model Standards for each averaging period.

[[Page 775]]

    (3)(i) The NOX emissions standard specified in paragraph 
(b)(3)(i) of this section shall no longer apply beginning January 1, 
2007, except as provided in paragraph (c)(3)(ii) of this section.
    (ii) For a refiner subject to the small refiner gasoline sulfur 
standards at Sec. 80.240, the NOX emissions standard 
specified in paragraph (b)(3)(i) of this section shall no longer apply 
beginning January 1, 2008. For a refiner subject to the gasoline sulfur 
standards at Sec. 80.240 that has received an extension of its small 
refiner gasoline sulfur standards under Sec. 80.553, the NOX 
emissions standard specified in paragraph (b)(3)(i) of this section 
shall no longer apply beginning January 1, 2011.
    (4)(i) Beginning January 1, 2011, or January 1, 2015 for small 
refiners approved under Sec. 80.1340, the exhaust toxics emissions 
standard specified in paragraph (b)(3)(i) of this section shall apply 
only to conventional gasoline that is not subject to the benzene 
standard of Sec. 80.1230, pursuant to the provisions of Sec. 80.1235.
    (ii) The exhaust toxic emissions standard specified in paragraph 
(b)(3)(i) of this section shall not apply to conventional gasoline 
produced by a refinery approved under Sec. 80.1334, pursuant to Sec. 
80.1334(c).
    (d) Product to which standards apply. Any refiner for each refinery, 
or any importer, shall include in its compliance calculations:
    (1) Any conventional gasoline produced or imported during the 
averaging period;
    (2) [Reserved]
    (3) Any gasoline blending stock produced or imported during the 
averaging period which becomes conventional gasoline solely upon the 
addition of oxygenate;
    (4)(i) Any oxygenate that is added to conventional gasoline, or 
gasoline blending stock as described in paragraph (d)(3) of this 
section, where such gasoline or gasoline blending stock is produced or 
imported during the averaging period;
    (ii) In the case of oxygenate that is added at a point downstream of 
the refinery or import facility, the oxygenate may be included only if 
the refiner or importer can establish the oxygenate was in fact added to 
the gasoline or gasoline blendstock produced, by showing that the 
oxygenate was added by:
    (A) The refiner or importer; or
    (B) By a person other than the refiner or importer, provided that 
the refiner or importer:
    (1) Has a contract with the oxygenate blender that specifies 
procedures to be followed by the oxygenate blender that are reasonably 
calculated to ensure blending with the amount and type of oxygenate 
claimed by the refiner or importer; and
    (2) Monitors the oxygenate blending operation to ensure the volume 
and type of oxygenate claimed by the refiner or importer is correct, 
through periodic audits of the oxygenate blender designed to assess 
whether the overall volumes and type of oxygenate purchased and used by 
the oxygenate blender are consistent with the oxygenate claimed by the 
refiner or importer and that this oxygenate was blended with the 
refiner's or importer's gasoline or blending stock, periodic sampling 
and testing of the gasoline produced subsequent to oxygenate blending, 
and periodic inspections to ensure the contractual requirements imposed 
by the refiner or importer on the oxygenate blender are being met.
    (e) Product to which standards do not apply. Any refiner for each 
refinery, or any importer, shall exclude from its compliance 
calculations:
    (1) Gasoline that was not produced at the refinery or was not 
imported by the importer;
    (2) [Reserved]
    (3) California gasoline as defined in Sec. 80.81(a)(2); and
    (4) Gasoline that is exported.
    (f) Compliance baseline determinations. (1) In the case of any 
refiner or importer for whom an individual baseline has been established 
under Sec. 80.91, the individual baseline for each parameter or 
emissions performance shall be the compliance baseline for that refiner 
or importer.
    (2)(i) In the case of any refiner for any refinery or importer for 
whom the anti-dumping statutory baseline applies under Sec. 80.91, the 
anti-dumping statutory baseline for each parameter or emissions 
performance shall be the compliance baseline for that refinery or 
importer.

[[Page 776]]

    (ii) In the case of any refiner for any refinery or importer that 
has received approval of a petition submitted under Sec. 
80.93(d)(1)(iii), the compliance baseline for each emissions performance 
for that refinery or importer for gasoline produced or imported for use 
in Alaska shall be the winter statutory baseline value under Sec. 
80.45(b)(3), Table 5.
    (iii) In the case of any refiner for any refinery or importer that 
has received approval of a petition submitted under Sec. 
80.93(d)(2)(iii), the compliance baseline for each emissions performance 
for that refinery or importer for gasoline produced or imported for use 
in Hawaii, the Commonwealth of Puerto Rico, and/or the Virgin Islands 
shall be:
    (A) The summer statutory baseline value under Sec. 80.45(b)(3), 
Table 5 for NOX.
    (B) The summer statutory baseline value under Sec. 80.45(b)(3), 
Table 5 for Toxics less the corresponding value for Benzene under Sec. 
80.45(b)(3), Table 4.
    (3)(i) In the case of any refiner for any refinery or importer that 
has received approval of a petition submitted under Sec. 
80.93(d)(1)(ii), the compliance baseline for each emissions performance 
for that refinery or importer for gasoline produced or imported for use 
in Alaska shall be the refinery's or importer's winter baseline value 
determined under Sec. 80.91.
    (ii) In the case of any refiner for any refinery or importer that 
has received approval of a petition submitted under Sec. 
80.93(d)(2)(ii), the compliance baseline for each emissions performance 
for that refinery or importer for gasoline produced or imported for use 
in Hawaii, the Commonwealth of Puerto Rico, and/or the Virgin Islands 
shall be the refinery's or importer's summer baseline value determined 
under Sec. 80.91.
    (4) Any compliance baseline under paragraph (f)(1) of this section 
shall be adjusted for each averaging period as follows:
    (i) If the total volume of the conventional gasoline, RBOB, 
reformulated gasoline, and California gasoline as defined in Sec. 
80.81(a)(2), produced or imported by any refiner or importer during the 
averaging period is equal to or less than that refiner's or importer's 
1990 baseline volume as determined under Sec. 80.91(f)(1), the 
compliance baseline for each parameter or emissions performance shall be 
that refiner's or importer's individual 1990 baseline; or
    (ii) If the total volume of the conventional gasoline, RBOB, 
reformulated gasoline, and California gasoline as defined in Sec. 
80.81(a)(2), produced or imported by any refiner or importer during the 
averaging period is greater than that refiner's or importer's 1990 
baseline volume as determined under Sec. 80.91(f)(1), the compliance 
baseline for each parameter or emissions performance shall be calculated 
according to the following formula:
[GRAPHIC] [TIFF OMITTED] TR13JY99.000

Where:

CBi = The compliance baseline value for parameter or 
emissions performance i.
Bi = The refiner's or importer's individual baseline value 
for parameter or emission performance i calculated according to the 
methodology in Sec. 80.91.
DBi = The anti-dumping statutory baseline value for parameter 
or emissions performance i, as specified at Sec. 80.91(c)(5)(iii) or 
(c)(5)(iv), respectively.
V1990 = The 1990 baseline volume as determined under Sec. 
80.91(f)(1).
Va = The total volume of reformulated gasoline, conventional 
gasoline, RBOB, and California gasoline as defined in Sec. 80.81(a)(2) 
produced or imported by a refiner or importer during the averaging 
period.

    (iii) Any refiner or importer with an individual baseline that has 
received approval of a petition submitted under Sec. 80.93(d) and has 
produced or imported gasoline for use in Alaska, Hawaii, the 
Commonwealth of Puerto Rico, or the Virgin Islands must calculate the 
compliance baseline for each parameter or emissions performance as 
follows:

[[Page 777]]

[GRAPHIC] [TIFF OMITTED] TR25OC07.000


If Vj = V1990j  0:
[GRAPHIC] [TIFF OMITTED] TR25OC07.001


If Vj < V1990j or V1990j = 0: 
CBi,j = Bi,j
Where:

CBi = The compliance baseline for parameter or emissions 
performance i
CBi,j = The compliance baseline for parameter or emissions 
performance i applicable to the conventional gasoline in production 
volume Vj

j is a subscript identifying a portion of gasoline and RBOB produced or 
imported as follows:

j=1: Conventional gasoline supplied to Hawaii, the Commonwealth of 
Puerto Rico and the Virgin Islands, if gasoline supplied to these areas 
is covered by a petition for a separate baseline.
j=2: Conventional gasoline supplied to Alaska, if gasoline supplied to 
this area is covered by a petition for a separate baseline.
j=3: Conventional gasoline, reformulated gasoline, RBOB and California 
gasoline produced or imported by a refiner or importer, and not included 
in portions 1 or 2.
Vj = The averaging period volume for portion j.
Vr = The volume of reformulated gasoline, RBOB and California 
gasoline included in V3.
Bi,j = The refiner/importer's individual baseline for 
parameter or emissions performance i applicable to the conventional 
gasoline in portion j, or the applicable statutory baseline if assigned 
in lieu of an individual baseline.
DBi,j = The statutory baseline for parameter or emissions 
performance i applicable to the conventional gasoline in portion j 
(i.e., the annual or seasonal statutory baseline).
V1990j = The 1990 baseline volume applicable to portion j.

    (g) Compliance calculations--(1)(i) Simple model calculations. In 
the case of any refiner or importer subject to an individual refinery 
baseline, the annual average value for each parameter or emissions 
performance during the averaging period, calculated according to the 
following methodologies, shall be less than or equal to the refiner's or 
importer's standard under paragraph (b) of this section for that 
parameter.
    (A) The average value for sulfur, T-90, olefin, benzene, and 
aromatics for an averaging period shall be calculated as follows:
[GRAPHIC] [TIFF OMITTED] TR20JY94.004

where

APARM = the average value for the parameter being evaluated
Vi = the volume of conventional gasoline or other products 
included under paragraph (d) of this section, in batch i
PARMi = the value of the parameter being evaluated for batch 
i as determined in accordance with the test methods specified in Sec. 
80.46
n = the number of batches of conventional gasoline and other products 
included under paragraph (d) of this section produced or imported during 
the averaging period
SGi = specific gravity of batch i (only applicable for 
sulfur)

    (B) Exhaust benzene emissions under the Simple Model for an 
averaging period are calculated as follows:

[[Page 778]]

[GRAPHIC] [TIFF OMITTED] TR20JY94.005

where

EXHBEN = the average exhaust benzene emissions for the averaging period
BZ = the average benzene content for the averaging period, calculated 
per paragraph (g)(1)(i)(A) of this section
AR = the average aromatics content for the averaging period, calculated 
per paragraph (g)(1)(i)(A) of this section

    (ii) Complex Model calculations.
    (A) Exhaust benzene, exhaust toxics, and exhaust NOX 
emissions performance for each batch shall be calculated in accordance 
with the applicable model under Sec. 80.45.
    (B) Any refiner for any refinery or importer that has received EPA 
approval of a petition submitted in accordance with the provisions of 
Sec. 80.93(d)(1) must use the applicable winter complex model under 
Sec. 80.45, using an RVP of 8.7 psi, to evaluate its averaging period 
gasoline produced or imported for use in Alaska.
    (C) Any refiner for any refinery or importer that has received EPA 
approval of a petition submitted in accordance with the provisions of 
Sec. 80.93(d)(2) must use the applicable summer complex model under 
Sec. 80.45 to evaluate its averaging period gasoline produced or 
imported for use in Hawaii, the Commonwealth of Puerto Rico, and the 
Virgin Islands.
    (2) In the case of any refiner or importer subject to the anti-
dumping statutory baseline, the summer statutory baseline and/or the 
winter statutory baseline, the refiner or importer shall determine 
compliance using the following methodology:
    (i) Calculate the compliance total for the averaging period for 
sulfur, T-90, olefins, exhaust benzene emissions, exhaust toxics and 
exhaust NOX emissions, as applicable, based upon the anti-
dumping statutory baseline value, the summer statutory baseline value, 
or the winter statutory baseline value, as applicable, for that 
parameter using the formula specified at 80.67.
    (ii) Calculate the actual total for the averaging period for sulfur, 
T-90, olefins, exhaust benzene emissions, exhaust toxics and exhaust 
NOX emissions, as applicable, based upon the value of the 
parameter for each batch of conventional gasoline and gasoline 
blendstocks, if applicable, using the formula specified at Sec. 80.67.
    (iii) The actual total for exhaust benzene emissions, exhaust toxics 
and exhaust NOX emissions, shall not exceed the compliance 
total, and the actual totals for sulfur, olefins and T-90 shall not 
exceed 125% of the compliance totals, as required under the applicable 
model.
    (3) Exhaust toxics and NOX emissions performance of a 
blendstock batch shall be determined as follows:
    (i) Determine the volume and properties of the blendstock.
    (ii) Determine the blendstock volume fraction (F) based on the 
volume of blendstock, and the volume of gasoline with which the 
blendstock is blended, using the following equation:
[GRAPHIC] [TIFF OMITTED] TR31DE97.009

where:

F = blendstock volume fraction
Vb = volume of blendstock
Vg = volume of gasoline with which the blendstock is blended

    (iii) For each parameter required by the complex model, calculate 
the parameter value that would result by combining, at the blendstock 
volume fraction (F), the blendstock with a gasoline having properties 
equal to the refinery's or importer's baseline, using the following 
formula:
[GRAPHIC] [TIFF OMITTED] TR31DE97.010

where:

CPj = calculated value for parameter j
BAPj = baseline value for parameter j
BLPj = value of parameter j for the blendstock or oxygenate
j = each parameter required by the complex model


[[Page 779]]


    (A) The baseline value shall be the refinery's ``summer'' or 
``winter'' baseline, based on the ``summer'' or ``winter'' 
classification of the gasoline produced as determined under paragraphs 
(g)(5) or (g)(6) of this section. In the case of a refinery that is 
aggregated under paragraph (h) of this section, the refinery baseline 
shall be used, and not the aggregate baseline.
    (B) The sulfur content and oxygen wt% computations under paragraph 
(g)(3)(iii) of this section shall be adjusted for the specific gravity 
of the gasoline and blendstock using specific gravities of 0.749 for 
``summer'' gasoline and of 0.738 for ``winter'' gasoline.
    (C) In the case of ``summer'' gasoline, where the blendstock is 
ethanol and the volume fraction calculated under paragraph (g)(3)(ii) is 
equal to or greater than 0.015, the value for RVP calculated under 
paragraph (g)(3)(iii) of this section shall be 1.0 psi greater than the 
RVP of the gasoline with which the blendstock is blended.
    (iv) Using the summer or winter complex model, as appropriate, 
calculate the exhaust toxics and NOX emissions performance, 
in mg/mi, of:
    (A) A hypothetical gasoline having properties equal to those 
calculated in paragraph (g)(3)(iii) of this section (HEP); and
    (B) A gasoline having properties equal to the refinery's or 
importer's baseline (BEP).
    (v) Calculate the exhaust toxics and NOX equivalent 
emissions performance (EEP) of the blendstock, in mg/mi, using the 
following equation:
[GRAPHIC] [TIFF OMITTED] TR31DE97.011

where:

EEPj = equivalent emissions performance of the blendstock for 
emissions performance j
BEPj = emissions performance j of a gasoline having the 
properties of the refinery's baseline
HEPj = emissions performance j of a hypothetical blendstock/
gasoline blend
F = blendstock volume fraction
j = exhaust toxics or NOX emissions performance

    (vi) For each blendstock batch, the volume, and exhaust toxics and 
NOX equivalent emissions performance (EEP) shall be included 
in the refinery's compliance calculations.
    (4) Compliance calculations under this subpart E shall be based on 
computations to the same degree of accuracy that are specified in 
establishing individual baselines under Sec. 80.91.
    (5) The emissions performance of gasoline that has an RVP that is 
equal to or less than the RVP required under Sec. 80.27 (``summer 
gasoline'') shall be determined using the applicable summer complex 
model under Sec. 80.45.
    (6)(i) The emissions performance of gasoline that has an RVP greater 
than the RVP required under Sec. 80.27 (``winter gasoline'') shall be 
determined using the applicable winter complex model under Sec. 80.45, 
using an RVP of 8.7 psi for compliance calculation purposes under this 
subpart E.
    (ii) Except as provided in paragraph (g)(1)(ii) of this section, the 
emissions performance of gasoline produced or imported for use in areas 
that are not subject to the requirements of Sec. 80.27 shall be 
determined using the applicable winter complex model under Sec. 80.45, 
using an RVP of 8.7 psi for compliance calculation purposes under this 
subpart E.
    (7)(i) For the 1998 averaging period any refiner or importer may 
elect to determine compliance with the requirement for exhaust 
NOX emissions performance either with or without the 
inclusion of oxygenates in its compliance calculations, in accordance 
with Sec. 80.91(e)(4), provided that the baseline exhaust 
NOX emissions performance is calculated using the same with- 
or without-oxygen approach.
    (ii)(A) Any refiner or importer must use the with- or without-oxygen 
approach elected under paragraph (g)(7)(i) of this section for all 
subsequent averaging periods; except that
    (B) In the case of any refiner or importer who elects to determines 
compliance for the calendar year 1998 averaging period without the 
inclusion of oxygenates, such refiner or importer may elect to include 
oxygenates in its compliance calculations for the 1999 averaging period.
    (iii) Any refiner or importer who elects to use the with-oxygen 
approach

[[Page 780]]

under paragraph (g)(7)(ii)(B) of this section must use this approach for 
all subsequent averaging periods.
    (8) Emissions performance of conventional gasoline with parameters 
outside the complex model valid range limits. Notwithstanding the 
provisions of Sec. 80.45(f)(2), in the case of any parameter value that 
does not fall within the complex model range limit in Sec. 
80.45(f)(1)(ii), the refiner or importer shall determine the emissions 
performance of the batch using the following parameter values:

------------------------------------------------------------------------
                                         Parameter value to use for
                                                calculating
Parameter outside the range limit --------------------------------------
                                     Exhaust toxics           NOX
------------------------------------------------------------------------
Sulfur...........................  Test value\1\.....  Test value.\1\
 RVP (summer only):
    < 6.4 psi....................  6.4 psi...........  6.4 psi.
     11.0 psi.........  Test value\1\.....  Test value.\1\
Aromatics........................  Test value\1\.....  Test value.\1\
Olefins..........................  Test value\1\.....  Test value.\1\
Benzene..........................  Test value\1\.....  Test value.\1\
 E200:
    < 30%........................  Test value\1\.....  30%
     70%..............  70%...............  Test value.\1\
E300 < 70%.......................  Test value\1\.....  Test value.\1\
------------------------------------------------------------------------
\1\ Test value is the value for a parameter determined pursuant to
  paragraph 80.101(i)(1)(i) of this section.

    (9) Exclusion of previously certified gasoline. (i) Any refiner who 
uses previously certified reformulated or conventional gasoline or RBOB 
to produce conventional gasoline at a refinery, must exclude the 
previously certified gasoline for purposes of demonstrating compliance 
with the standards under paragraph (b) of this section.
    (ii) To accomplish the exclusion required in paragraph (g)(9)(i) of 
this section, the refiner must determine the volume and properties of 
the previously certified gasoline used at the refinery, and the volume 
and properties of gasoline produced at the refinery, and use the 
compliance calculation procedures in paragraphs (g)(9)(iii) and 
(g)(9)(iv) of this section.
    (iii) For each batch of previously certified gasoline that is used 
to produce conventional gasoline the refiner must:
    (A) Determine the volume and properties using the procedures in 
paragraph (i) of this section;
    (B) Determine the exhaust toxics and NOX emissions 
performance using the summer or winter complex model as appropriate;
    (C) Include the volume and emissions performance of the previously 
certified gasoline as a negative volume and a negative emissions 
performance in the refiner's compliance calculations for the refinery, 
or where applicable, the refiner's aggregation under paragraph (h) of 
this section, for exhaust toxics and NOX.
    (iv) For each batch of conventional gasoline produced at the 
refinery using previously certified gasoline, the refiner must determine 
the volume and properties, and exhaust toxics and NOX 
emissions performance, and include each batch in the refinery's 
compliance calculations for exhaust toxics and NOX without 
regard to the presence of previously certified gasoline in the batch.
    (v) The refiner must use any previously certified gasoline that the 
refiner includes as a negative batch in its compliance calculations for 
the refinery, or where appropriate, the refiner's aggregation, as a 
component in gasoline production during the annual averaging period in 
which the previously certified gasoline was included as a negative batch 
in the refiner's compliance calculations.
    (vi) Notwithstanding the provisions of this paragraph (g)(9), the 
provisions of paragraph (g)(3) of this section may be used to calculate 
the exhaust toxics and NOX emissions performance of a 
blendstock added to conventional gasoline for purposes of demonstrating 
compliance with the standards under paragraph (b) of this section.
    (h) Refinery grouping for determining compliance. (1) Any refiner 
that operates more than one refinery may:
    (i) Elect to achieve compliance individually for the refineries; or
    (ii) Elect to achieve compliance on an aggregate basis for a group, 
or for groups, of refineries, some of which may be individual 
refineries; provided that
    (iii) Compliance is achieved for each refinery separately or as part 
of a group; and
    (iv) The data for any refinery is included only in one compliance 
calculation.
    (2) Any election by a refiner to group refineries under paragraph 
(h)(1) of this section shall:

[[Page 781]]

    (i) Be made as part of the report for the 1995 averaging period 
required by Sec. 80.105; and
    (ii) Apply for the 1995 averaging period and for each subsequent 
averaging period, and may not thereafter be changed.
    (3)(i) Any standards under this section shall apply, and compliance 
calculations shall be made, separately for each refinery or refinery 
group; except that
    (ii) Any refiner that produces conventional gasoline for 
distribution to a specified geographic area which is the subject of a 
petition approved by EPA pursuant to Sec. 80.91(f)(3) shall achieve 
compliance separately for gasoline supplied to such specified geographic 
area.
    (i) Sampling and testing. (1) Any refiner or importer shall for each 
batch of conventional gasoline, and other products if included in 
paragraph (d) of this section:
    (i)(A) Determine the value of each of the properties required for 
determining compliance with the standards that are applicable to the 
refiner or importer, by collecting and analyzing a representative sample 
of gasoline or blendstock taken from the batch, using the methodologies 
specified in Sec. 80.46; except that
    (B) Any refiner that produces gasoline by combining blendstock with 
gasoline that has been included in the compliance calculations of 
another refiner or of an importer may for such gasoline meet this 
sampling and testing requirement by collecting and analyzing a 
representative sample of the blendstock used subsequent to each receipt 
of such blendstock if the compliance calculation method specified in 
paragraph (g)(3) of this section is used.
    (ii) Assign a number to the batch (the ``batch number''), as 
specified in Sec. 80.65(d)(3);
    (2) For the purposes of meeting the sampling and testing 
requirements under paragraph (i)(1) of this section, any refiner or 
importer may, prior to analysis, combine samples of gasoline collected 
from more than one batch of gasoline or blendstock (``composite 
sample''), and treat such composite sample as one batch of gasoline or 
blendstock provided that the refiner or importer:
    (i) Meets each of the requirements specified in Sec. 
80.91(d)(4)(iii) for the samples contained in the composite sample;
    (ii) Combines samples of gasoline that are produced or imported over 
a period no longer than one month;
    (iii) Uses the total of the volumes of the batches of gasoline that 
comprise the composite sample, and the results of the analyses of the 
composite sample, for purposes of compliance calculations under 
paragraph (g) of this section; and
    (iv) Does not combine summer and winter gasoline, as specified under 
paragraphs (g) (5) and (6) of this section, in a composite sample.
    (3) An importer who imports conventional gasoline into the United 
States by truck may meet the sampling and testing requirements under 
paragraph (i)(1) of this section as follows:
    (i)(A) The importer must demonstrate that the imported gasoline 
meets the applicable conventional gasoline standards, through test 
results of samples of the gasoline contained in the storage tank from 
which the trucks used to transport gasoline into the United States are 
loaded.
    (B) The frequency of this sampling and testing must be subsequent to 
each receipt of gasoline into the storage tank, or immediately prior to 
each transfer of gasoline to the importer's truck.
    (C) The testing must be for each applicable parameter specified 
under Sec. 80.65(e)(2)(i), using the test methods specified under Sec. 
80.46.
    (D) The importer must obtain a copy of the terminal test results 
that reflects the quality of each truck load of gasoline that is 
imported into the United States.
    (ii)(A) The importer must conduct separate programs of periodic 
quality assurance sampling and testing of the gasoline obtained from 
each truck-loading terminal, to ensure the accuracy of the terminal test 
results.
    (B) The quality assurance samples must be obtained from the truck-
loading terminal by the importer, and terminal operator may not know in 
advance when samples are to be collected.

[[Page 782]]

    (C) The importer must test each sample (or use a laboratory that is 
independent under Sec. 80.82(b)(2) to test the sample) for the 
parameters specified under Sec. 80.65(e)(2)(i) using the test methods 
specified under Sec. 80.46, and the results must correlate with the 
terminal's test results within the ranges specified under Sec. 
80.65(e)(2)(i).
    (D) The frequency of quality assurance sampling and testing must be 
at least one sample for each fifty of an importer's trucks that are 
loaded at a terminal, or one sample per month, whichever is more 
frequent.
    (iii) The requirements of paragraph (i)(3)(ii) of this section are 
satisfied if the sampling and testing required under paragraph (i)(3)(i) 
is conducted by a laboratory that is an independent laboratory under the 
criteria of Sec. 80.82(b)(2).
    (iv) The importer must treat each truck load of imported gasoline as 
a separate batch for purposes of assigning batch numbers under Sec. 
80.101(i), recordkeeping under Sec. 80.104, and reporting under Sec. 
80.105.
    (v) EPA inspectors or auditors, and auditors conducting attest 
engagements under subpart F, must be given full and immediate access to 
the truck-loading terminal and any laboratory at which samples of 
gasoline collected at the terminal are analyzed, and be allowed to 
conduct inspections, review records, collect gasoline samples, and 
perform audits. These inspections or audits may be either announced or 
unannounced.
    (vi) In the event the requirements specified in paragraphs (i)(3)(i) 
through (v) of this section are not met, in whole or in part, the 
importer shall immediately lose the option of importing gasoline under 
the terms of this paragraph (i)(3).
    (j) Evasion of standards through exporting and importing gasoline. 
Notwithstanding the requirements of this section, no refiner or importer 
shall export gasoline and import the same or other gasoline for the 
purpose of evading a more stringent baseline requirement.
    (k) Petitions for an alternative anti-dumping averaging period--(1) 
Eligibility for petition. (i) The Administrator may grant an averaging 
period of two, three, four or five years upon petition of a refiner who:
    (A) Activates or plans to activate conventional gasoline production 
at a refinery that has never produced gasoline subject to the anti-
dumping requirements of subpart E of this part; and
    (B) Faces substantial, demonstrated hardship in meeting the anti-
dumping statutory baseline NOX standard during the early 
years of production.
    (ii) The Administrator will consider the refiner's or refinery's 
compliance with all applicable Federal, state, and local environmental 
statutes or requirements in evaluating the petition, including, but not 
limited to, any applicable stationary source requirement or standards.
    (2) Contents of a petition. A petition for a four or five year 
averaging period must be submitted by June 1, 2001. A petition for a two 
or three year averaging period must be submitted by June 1, 2003. 
Regardless of the averaging period requested, the petition must include:
    (i) The business name and address of the affected refinery and any 
location(s) where the refiner conducts operations.
    (ii) The name, address, phone number, fax number, and e-mail address 
of the responsible corporate officer and contact person who can provide 
clarification and explanation with regard to any information in the 
petition.
    (iii) A detailed explanation of why the refinery is eligible for an 
alternative anti-dumping compliance period under paragraph (k)(1) of 
this section, including:
    (A) Documentation the refinery has never produced gasoline that was 
subject to the anti-dumping standards under subpart E of this part and
    (B) Documentation demonstrating the hardship the refinery will 
experience meeting the anti-dumping statutory baseline NOX 
standard.
    (iv) The length of the averaging period requested and a 
justification for why that length of averaging period is required.
    (v) An estimate as to when the refinery can produce gasoline that 
will meet the statutory baseline standard for NOX.

[[Page 783]]

    (vi) The refinery's estimated gasoline production and annual average 
NOX level for each of the years for which the alternative 
averaging period is requested.
    (vii) A detailed description of the current refinery equipment and 
configuration.
    (viii) A detailed description of changes to the refinery equipment 
the refiner intends to complete in order to begin producing gasoline 
that will allow the refinery to comply with the overall alternative 
averaging period NOX standard, and for such changes the 
intended dates for events the refiner believes are appropriate for 
demonstrating reasonable progress towards completion of the changes, 
including the following events:
    (A) Sign the design contract;
    (B) Obtain necessary permits;
    (C) Obtain construction financing commitments;
    (D) Begin construction.
    (E) Complete construction
    (ix) The current nominal crude capacity of the refinery as reported 
to the Energy Information Administration (EIA) of the Department of 
Energy (DOE).
    (x) A detailed explanation of the refiner's plans to finance capital 
improvements at the refinery in order to meet all current applicable EPA 
gasoline and diesel fuel quality standards.
    (xi) A demonstration that the refiner has the funds and identified 
sources from which to purchase stationary source NOX credits 
sufficient to offset the maximum projected NOX deficit as 
calculated in accordance with paragraph (k)(4)(ii) of this section on a 
quarterly basis.
    (xii) A full disclosure and explanation of any matters of non-
compliance or violations of any environmental statutes or requirements 
for which the refiner has received notification by any state, local, or 
Federal agency.
    (xiii) A signed agreement by any parent company or, in the case of a 
joint venture, individual partners, if applicable, acknowledging that 
they will be liable for any violations.
    (xiv) Any other information the Administrator may require in order 
to fully evaluate the refiner's petition.
    (xv) The signature of a responsible corporate officer, certifying 
that the information contained in the petition is true.
    (3) NOX standards and other requirements applicable to refineries 
operating under an alternative anti-dumping averaging period. If a 
petition by a refiner is approved, the standards described in this 
paragraph shall be the standards applicable to the refinery identified 
in the petition for purposes of the anti-dumping program during the 
period of the alternative averaging period. Except as specifically 
modified by this section, the refinery must continue to comply with all 
other standards applicable under the anti-dumping standards of subpart E 
of this part.
    (i) A refinery shall meet the following deadlines for compliance 
with the statutory baseline, depending on the length of the alternative 
averaging period applicable to the refinery:

------------------------------------------------------------------------
                                                         Refinery must
                                                        comply with the
                                   Compliance period  Statutory Baseline
 Length of compliance period in      must start no     NOX standard, on
              years               later than January     average, for
                                        1st of         gasoline produced
                                                      beginning with the
------------------------------------------------------------------------
2...............................  2004..............  7th quarter and
                                                       all subsequent
                                                       quarters.
3...............................  2003..............  10th quarter and
                                                       all subsequent
                                                       quarters.
4...............................  2002..............  13th quarter and
                                                       all subsequent
                                                       quarters.
5...............................  2001..............  16th quarter and
                                                       all subsequent
                                                       quarters.
------------------------------------------------------------------------

    (ii)(A) By the end of the applicable alternative averaging period, 
the refinery must generate a net NOX benefit (compared to the 
statutory baseline) that is at least twice as large as the total 
NOX deficit generated during the period of time during which 
the refiner produced gasoline that did not comply with the statutory 
baseline.
    (B) At least one-half of the total NOX benefit required 
under paragraph (k)(3)(ii)(A) of this section must be generated by 
production of conventional gasoline at the refinery that is cleaner than 
the statutory baseline NOX standard, as calculated on a 
quarterly basis in accordance with the provision of this paragraph 
(k)(3)(ii).
    (C) Any portion of the total NOX benefit beyond that 
portion described under paragraph (k)(3)(ii)(B) of this section may come 
from either the production of conventional gasoline at the

[[Page 784]]

refinery that is cleaner than the statutory baseline NOX 
standard, as calculated on a quarterly basis, or from the purchase and 
retirement of stationary source NOX credits or allowances, as 
provided in paragraph (k)(3)(iii) of this section.
    (D) For the purposes of this Sec. 80.101(k) and Sec. 80.101(l), 
the NOX deficit in tons shall be calculated in accordance 
with the following equation:

NOXDef = (NOXad - NOXsea)* 
    Gd*2.7x10-8

Where:

NOXDef = the NOX deficit, in tons, for a calendar 
quarter in which the refiner's NOX performance for that 
quarter exceeds NOXsea.
NOXad = the average volume weighted NOX emissions 
performance, in mg/mile, for a calendar quarter in which the refiner 
exceeds NOXsea.
NOXsea = quarterly statutory NOX performance 
values. First calendar quarter = 1540 mg/mile; Second calendar quarter = 
1383 mg/mile; Third calendar quarter = 1381 mg/mile; Fourth calendar 
quarter = 1540 mg/mile.
Gd = the volume of gasoline produced during a quarter in 
which the refiner exceeds the applicable NOX standard, 
measured in gallons.

    (E) For the purposes of this Sec. 80.101(k) and Sec. 80.101(l), 
the NOX benefit in tons shall be calculated in accordance 
with the following equation:

NOXBen (NOXsea--
    NOXab)*Gd*2.7x10-8

Where:

NOxBen = the NOX benefit, in tons, for a calendar 
quarter in which the refiner's NOX performance for that 
quarter is below NOXsea.
NOXab = the average volume weighted NOX emissions 
performance, in mg/mile, for a calendar quarter in which the refiner is 
below NOXsea.
NOXsea = quarterly statutory NOX performance 
values. First calendar quarter = 1540 mg/mile; Second calendar quarter = 
1383 mg/mile; Third calendar quarter = 1381 mg/mile; Fourth calendar 
quarter = 1540 mg/mile.
Gb = the volume of gasoline produced during a quarter in 
which the refiner is below the applicable NOX standard, 
measured in gallons.

    (iii) NOX Credits and Allowances. (A) Within 60 days of 
the end of each quarter for which the refinery produces gasoline for 
which there is a NOX deficit, the refiner shall purchase 
stationary source NOX credits or allowances that are equal to 
or greater than the amount of the NOX deficit generated 
during the quarter, and provide written demonstration of such 
transaction to the Administrator. These NOX credits or 
allowances are in addition to any NOX credits or allowances 
purchased during any previous quarters. NOX deficit is to be 
calculated on a quarterly basis in accordance with the equation in 
paragraph (k)(3)(ii)(D) of this section.
    (B) No NOX credits or allowances purchased by the refiner 
may contribute to the refinery's compliance with the requirements of 
paragraphs (k)(3)(ii)(B) of this section.
    (C) The refinery may sell NOX credits or allowances 
purchased under this paragraph (k)(3)(iii) only in an amount equal to or 
less than any NOX benefit that the refinery generates 
subsequently through the production of conventional gasoline at the 
refinery that is cleaner than the statutory baseline NOX 
standard, as calculated on a quarterly basis. A refiner may retire 
credits or allowances purchased under this paragraph (k)(3)(iii) at any 
time.
    (D) For purposes of satisfying a refinery's obligations under 
paragraphs (k)(3)(ii)(C), (k)(3)(iii)(A) or (l)(6)(ii) of this section, 
any NOX credits or allowances that a refiner purchases must 
have been validly generated as part of a state stationary source program 
covered by an approved state implementation plan (SIP) and must be 
current and marketable NOX credits or allowances. It shall be 
the refiner's responsibility to ensure that NOX credits or 
allowances are valid, current and marketable.
    (E) In order to be retired, NOX allowances or credits 
must be retired by EPA or the administering state agency, as provided 
for in the applicable state implementation plan (SIP). It shall be the 
refiner's responsibility to ensure that NOX credits or 
allowances are actually retired and that retirement is reflected in the 
records of EPA or the administering state agency.
    (iv) (A) The refinery shall not generate marketable credits or 
allotments under the Tier 2 gasoline program provisions of Subpart H of 
this part during the entire alternative averaging period

[[Page 785]]

and shall provide a written statement, on a quarterly basis, certifying 
that the refinery has not generated, produced, sold, or transferred any 
such marketable credits or allotments under Subpart H of this part.
    (B) If the final quarter of the alternative averaging period ends on 
a date other than December 31, then the refiner may generate credits for 
that portion of the year that was not subject to the alternative 
averaging period.
    (v) The refinery shall market any conventional gasoline it produces 
that is subject to the requirements of Sec. 80.27 as 9.0 RVP gasoline 
until the standard in paragraph (k)(3)(i) of this section is met.
    (vi) A refinery that has been granted an averaging period under this 
section must submit the following reports to the Administrator within 30 
days of the end of each calendar quarter:
    (A) Quarterly batch reports and anti-dumping averaging reports for 
gasoline produced during each quarter; and
    (B)(1) Documents that demonstrate compliance with the requirements 
under paragraph (k)(3)(iii) and (k)(3)(iv) of this section. including a 
calculation of the NOX deficit or benefit for that quarter 
and a current total, based upon all quarters, indicating the current 
NOX deficit or NOX benefit balance for the 
refinery; and
    (2) A statement of the number of NOX credits or 
allowances purchased, sold or retired during the quarter and a current 
total, based upon all quarters, indicating the current balance of 
NOX credits or allowances; and
    (3) Any contractual documents, or other documents, evidencing the 
purchasing, banking or retiring of NOX credits or allowances.
    (vii) The Administrator may specify, as part of the approved 
petition, deadlines by which a refiner is obligated to take certain 
actions (including those listed in paragraph (k)(2)(viii) of this 
section) demonstrating reasonable progress toward completion of the 
refinery changes necessary to produce gasoline that will allow the 
refinery to comply with the overall alternative averaging period 
NOX standard.
    (viii)(A) The refiner shall submit reports demonstrating compliance 
with deadline requirements under paragraph (k)(3)(vii) of this section 
no later than 30 days after the applicable deadline occurs. Upon failure 
to meet a deadline requirement under paragraph (k)(3)(vii) of this 
section, the Administrator may accelerate the date by which the refiner 
would have to produce gasoline that complies with the annual average 
statutory baseline NOX standard under paragraph (k)(3)(i) or 
(l)(6)(i) of this section such that the gasoline produced by the 
refinery beginning with the quarter immediately following the quarter 
during which the failure occurred (and during each subsequent quarter) 
would have to meet that standard. The acceleration of the requirement 
under paragraph (k)(3)(i) or (l)(6)(i) of this section, regarding 
compliance with the annual average statutory baseline NOX 
standard, does not affect the applicability of any other standard or 
requirement applicable to the refinery under this or any other section 
of the Act (e.g., the refinery must still comply with the overall 
alternative averaging period NOX requirements in paragraph 
(k)(3)(ii) of this section).
    (B) The reports required by this paragraph shall be on forms and 
following procedures specified by the Administrator of the EPA and 
signed and certified as correct by the owner or a responsible corporate 
officer of the refiner.
    (ix) The refiner shall comply with any condition or requirement 
prescribed by the Administrator as part of the petition approval.
    (x) The refinery must comply with all standards in this paragraph 
and with all applicable anti-dumping standards in Subpart E of this 
section, except the NOX standard.
    (4) Approval or disapproval of petitions. The Administrator will 
approve or disapprove the petition within six months of receipt, in 
writing, and in the case of an approval will include any conditions or 
requirements to which the approval is subject.
    (5) Effective date for alternative averaging period. (i) For an 
approved petition, the alternative averaging period shall become 
effective with the first day of the next calendar quarter, unless the 
first day of a later calendar quarter is requested.

[[Page 786]]

    (ii) If the final quarter of the alternative averaging period ends 
on a date other than December 31, then the refiner must demonstrate 
compliance with anti-dumping standards for gasoline produced during the 
remainder of that year and must demonstrate such compliance via the 
annual report as specified in Sec. 80.105.
    (6) Refinery request for a change in alternative averaging period. 
At any point during the pendency of an alternative conventional gasoline 
anti-dumping compliance period the Administrator may, upon application 
by a refiner, approve a different alternative compliance period for a 
refinery already operating subject to an alternative compliance period. 
In any such case:
    (i) A refinery for which a change in the applicable alternative 
compliance period is approved shall thereafter operate as if the 
refinery had originally requested and received such alternative 
compliance period, and shall be subject to the standards and other 
requirements applicable under such alternative compliance period.
    (ii) The Administrator will approve or disapprove any application 
for a different alternative compliance period, in writing, within six 
months of receipt, and in the case of an approval will include any 
conditions or other requirements to which the approval is subject;
    (iii) Accept as specifically modified by this section, such refinery 
must continue to comply with all other standards and other requirements 
applicable under the conventional gasoline anti-dumping standards; and
    (iv) No application may result in an alternative compliance period 
that extends beyond January 1, 2006, except as provided in paragraph (l) 
of this section.
    (7) Violations under this paragraph (k). Any person who fails to 
meet a standard or other requirement under this paragraph (k) shall be 
liable for penalties under Sec. 80.5. Additionally, in the event that 
the refiner fails to achieve the required NOX benefit 
calculated under paragraph (k)(3)(ii) of this section, any 
NOX credits still banked under paragraph (k)(3)(iii) of this 
section shall be forfeit.
    (l) Special alternative anti-dumping averaging period provisions for 
small refineries--(1) Eligibility for petition. A refiner who has been 
granted small refiner status under Sec. 80.235 and who meets the 
eligibility requirements in paragraph (k)(1) of this section may 
petition for an alternative compliance period that is greater than five 
years and/or that extends beyond January 1, 2006, provided that such 
application is submitted by January 1, 2004. No application under this 
paragraph (l) may result in an alternative compliance period that 
extends beyond January 1, 2008.
    (2) Application process. Applications must be submitted to the 
Administrator by January 1, 2004, to the following address: U.S. EPA--
Attn: Anti-Dumping Compliance Period (6406J), 1200 Pennsylvania Avenue, 
NW, Washington, DC 20460 (certified mail/return receipt) or U.S. EPA--
Attn: Anti-Dumping Compliance Period (6406J), Transportation & Regional 
Programs Division, 501 3rd Street, NW, Washington, DC 20001 (express 
mail/return receipt).
    (3) Contents of the application petition. Each petition must 
include:
    (i) The information and signed statements specified for all 
petitioners under Sec. 80.101(k)(2);
    (ii) A description of the hardships that make it infeasible, on a 
cost and/or technological basis, for the refinery to comply with an 
alternative anti-dumping compliance baseline of five years or less, or 
that ends on or before January 1, 2006.
    (iii) A quarterly timeline, from the date of the application, 
indicating the expected NOX emissions performance of the 
refinery's conventional gasoline, and the reasons for any expected non-
compliance with the statutory baseline standard for NOX on a 
quarterly basis (for example, a particular gasoline blendstock-producing 
unit not yet installed). The timeline shall include the date by which 
the refinery will produce conventional gasoline that complies with the 
annual average statutory NOX baseline on a quarterly basis as 
determined according to Sec. 80.101(k)(3)(ii).

[[Page 787]]

    (iv) A demonstration that the conditions for which the refinery was 
granted small refiner status under Sec. 80.235 are still applicable.
    (v) Information already submitted to the Administrator as part of a 
prior petition under paragraph (k) of this section, shall be updated if 
applicable.
    (4) Approval or disapproval of petitions. The Administrator may 
approve a petition under this paragraph (l) if it includes information 
sufficient to demonstrate to the Administrator's satisfaction that cost 
and/or technological constraints make it infeasible for the refinery to 
comply with an alternative anti-dumping compliance baseline of five 
years or less, or that ends on or before January 1, 2006. The 
Administrator will approve or deny the petition in writing within six 
months of receipt. An approval will include any conditions or 
requirements to which the approval is subject.
    (5) Cessation of extended alternative compliance period. (i) 
Refineries that qualify as small under Sec. 80.223, and that later are 
disqualified under Sec. 80.230(b), will be subject to the statutory 
anti-dumping baseline on an annual average basis beginning the calendar 
year immediately following the refinery's change in status.
    (ii) If the Administrator finds that a refiner provided false or 
inaccurate information on its application for small refiner status, upon 
notice from the Administrator, the refiner's extended alternative 
compliance period will be void ab initio.
    (6) Compliance requirements for qualifying small refiners. (i) If 
the refiner's application for an extended compliance period under this 
paragraph (l) is approved, then the refinery must comply with the 
statutory baseline NOX standard, on average, for gasoline 
produced beginning by not later than the 19th quarter (for a six year 
compliance period) or by no later than the 22nd quarter (for a seven 
year compliance period).
    (ii) The refinery must meet all other applicable requirements in 
paragraph (k) of this section, including the production of a net 
NOX benefit under paragraph (k)(3)(ii) of this section, 
except that the following provisions shall apply:
    (A) For any cumulative NOX deficit remaining at the 
expiration of the fifth year, based on the NOX emission 
performance of gasoline actually produced at the refinery, and as 
calculated under paragraph (k)(3)(ii) of this section, the refiner shall 
provide an additional NOX benefit equal to one half ton of 
NOX emissions per ton of deficit remaining by the end of the 
refinery's alternative anti-dumping averaging period.
    (B) For any cumulative NOX deficit remaining at the 
expiration of the sixth year, based on the NOX emission 
performance of gasoline actually produced at the refinery, and as 
calculated under paragraph (k)(3)(ii) of this section, the refiner shall 
provide an additional NOX benefit equal to one ton of 
NOX emissions per ton of deficit remaining by the end of the 
refinery's alternative anti-dumping averaging period.
    (C) The additional NOX benefits required under this 
paragraph (l)(6)(ii) of this section may come from the production of 
gasoline at the refinery that is cleaner than the statutory baseline or 
from the purchase and retirement of stationary source NOX 
credits or allowances as provided in paragraph (k)(3)(iii) of this 
section.

[59 FR 7860, Feb. 16, 1994, as amended at 59 FR 36968, July 20, 1994; 60 
FR 40008, Aug. 4, 1995; 62 FR 9884, Mar. 4, 1997; 62 FR 68207, Dec. 31, 
1997; 64 FR 30910, June 9, 1999; 64 FR 37689, July 13, 1999; 65 FR 
54431, Sept. 8, 2000; 66 FR 67107, Dec. 28, 2001; 67 FR 8738, Feb. 26, 
2002; 68 FR 24307, May 6, 2003; 70 FR 74572, Dec. 15, 2005; 72 FR 8543, 
Feb. 26, 2007; 72 FR 60580, Oct. 25, 2007]



Sec. 80.102  [Reserved]



Sec. 80.103  Registration of refiners and importers.

    Any refiner or importer of conventional gasoline must register with 
the Administrator in accordance with the provisions specified at Sec. 
80.76.



Sec. 80.104  Recordkeeping requirements.

    Any parties in the gasoline distribution network shall maintain 
records containing the information as required by this section.
    (a) For any refiner or importer, beginning in 1995, for each 
averaging period:

[[Page 788]]

    (1) Documents containing the information specified in paragraph 
(a)(2) of this section shall be obtained for:
    (i) Each batch of conventional gasoline; and
    (ii) Each batch of blendstock received in the case of any refiner 
that determines compliance on the basis of blendstocks properties under 
Sec. 80.101(g)(3).
    (2)(i) The results of tests performed in accordance with Sec. 
80.101(i);
    (ii) The volume of the batch;
    (iii) The batch number;
    (iv) The date of production, importation or receipt;
    (v) The designation regarding whether the batch is summer or winter 
gasoline;
    (vi) The product transfer documents for any conventional gasoline 
produced or imported;
    (vii) The product transfer documents for any conventional gasoline 
received;
    (viii) For any gasoline blendstocks received by or transferred from 
a refiner or importer, documents that reflect:
    (A) The identification of the product;
    (B) The date the product was transferred; and
    (C) The volume of product;
    (ix) [Reserved]
    (x) In the case of oxygenate that is added by a person other than 
the refiner or importer under Sec. 80.101(d)(4)(ii)(B), documents that 
support the volume of oxygenate claimed by the refiner or importer, 
including the contract with the oxygenate blender and records relating 
to the audits, sampling and testing, and inspections of the oxygenate 
blender operation.
    (xi) In the case of blendstocks that are included in refinery 
compliance calculations using the procedures under Sec. 80.101(g)(3), 
documents that reflect the volume of blendstock and the volume of 
gasoline with which the blendstock is blended.
    (xii) In the case of gasoline classified as previously certified 
gasoline under the terms of Sec. 80.101(g)(9), the results of the tests 
to determine the properties and volume of the previously certified 
gasoline when received at the refinery and records that reflect the 
storage and movement of the previously certified gasoline to the point 
the previously certified gasoline is used to produce conventional 
gasoline.
    (xiii) In the case of gasoline subject to an approved petition under 
Sec. 80.93(d), documents that reflect that the gasoline was produced or 
imported for use in Alaska, Hawaii, the Commonwealth of Puerto Rico, and 
the Virgin Islands, as applicable.
    (xiv) In the case of butane blended into conventional gasoline under 
Sec. 80.82, documentation of:
    (A) The volume of the butane added;
    (B) The volume of the gasoline prior to and subsequent to the butane 
blending;
    (C) The purity and properties of the butane under Sec. 80.82(c) and 
(d), as appropriate; and
    (D) Compliance with the requirements of Sec. 80.82.
    (xv) In the case of any imported GTAB, documents that reflect the 
physical movement of the GTAB from the point of importation to the point 
of blending to produce gasoline.
    (b) For all parties described in this section that produce and 
distribute gasoline, in the case of any interface or transmix used to 
produce conventional gasoline under Sec. 80.84, records that reflect 
the results of any sampling and testing of conventional gasoline under 
Sec. 80.84.
    (1) Pipelines must keep records showing that the interface was 
designated in the proper manner according to the designations listed in 
Sec. 80.84(b)(1).
    (2) Transmix processors and transmix blenders must keep records 
showing that their transmix meets the definition in Sec. 80.84(a)(2), 
or contains gasoline and distillate fuel only from the sources listed in 
Sec. 80.84(e).
    (3) Transmix processors must keep records showing the volumes of 
conventional gasoline recovered from transmix and the type and amount of 
any blendstock added, if applicable.
    (4) Transmix blenders must keep records showing compliance with the 
quality assurance program and/or sampling and testing requirements in 
Sec. 80.84(d)(2) or (d)(3) for each batch of conventional gasoline with 
which transmix is blended, the volume of the batch, and the volume of 
transmix blended into the batch.

[[Page 789]]

    (c) All parties in the gasoline distribution network shall retain 
the documents required in this section for a period of five years from 
the date the conventional gasoline or blendstock is produced or 
imported, and deliver such documents to the Administrator of EPA upon 
the Administrator's request.

[59 FR 7860, Feb. 16, 1994, as amended at 59 FR 36969, July 20, 1994; 62 
FR 68208, Dec. 31, 1997; 66 FR 67107, Dec. 28, 2001; 67 FR 8738, Feb. 
26, 2002; 70 FR 74573, Dec. 15, 2005; 71 FR 31963, June 2, 2006; 72 FR 
60581, Oct. 25, 2007]



Sec. 80.105  Reporting requirements.

    (a) Beginning with the 1995 averaging period, and for each 
subsequent averaging period, any refiner for each refinery or group of 
refineries at which any conventional gasoline is produced, and any 
importer that imports any conventional gasoline, shall submit to the 
Administrator a report which contains the following information:
    (1) The total gallons of conventional gasoline produced or imported;
    (2)-(3) [Reserved]
    (4)(i) If using the simple model:
    (A) The applicable exhaust benzene emissions standard under Sec. 
80.101(b)(1)(i);
    (B) The average exhaust benzene emissions under Sec. 80.101(g);
    (C) The applicable sulfur content standard under Sec. 
80.101(b)(1)(ii) in parts per million;
    (D) The average sulfur content under Sec. 80.101(g) in parts per 
million;
    (E) The difference between the applicable sulfur content standard 
under Sec. 80.101(b)(1)(ii) in parts per million and the average sulfur 
content under paragraph (a)(4)(i)(D) of this section in parts per 
million, indicating whether the average is greater or lesser than the 
applicable standard;
    (F) The applicable olefin content standard under Sec. 
80.101(b)(1)(iii) in volume percent;
    (G) The average olefin content under Sec. 80.101(g) in volume 
percent;
    (H) The difference between the applicable olefin content standard 
under Sec. 80.101(b)(1)(iii) in volume percent and the average olefin 
content under paragraph (a)(4)(i)(G) of this section in volume percent, 
indicating whether the average is greater or lesser than the applicable 
standard;
    (I) The applicable T90 distillation point standard under Sec. 
80.101(b)(1)(iv) in degrees Fahrenheit;
    (J) The average T90 distillation point under Sec. 80.101(g) in 
degrees Fahrenheit; and
    (K) The difference between the applicable T90 distillation point 
standard under Sec. 80.101(b)(1)(iv) in degrees Fahrenheit and the 
average T90 distillation point under paragraph (a)(4)(i)(J) of this 
section in degrees Fahrenheit, indicating whether the average is greater 
or lesser than the applicable standard.
    (ii) If using the optional complex model, the applicable exhaust 
benzene emissions standard and the average exhaust benzene emissions, 
under Sec. 80.101(b)(2) and (g).
    (iii) If using the complex model:
    (A) The applicable exhaust toxics emissions standard and the average 
exhaust toxics emissions, under Sec. 80.101(b)(3) and (g); and
    (B) The applicable NOX emissions standard and the average 
NOX emissions, under Sec. 80.101(b)(3) and (g).
    (5) The following information for each batch of conventional 
gasoline or batch of blendstock included under paragraph (a) of this 
section:
    (i) The batch number;
    (ii) The date of production;
    (iii) The volume of the batch;
    (iv) The grade of gasoline produced (i.e., premium, mid-grade, or 
regular);
    (v) The properties, pursuant to Sec. 80.101(i);
    (vi) In the case of any previously certified gasoline used in a 
refinery operation under the terms of Sec. 80.101(g)(9), the following 
information relative to the previously certified gasoline when received 
at the refinery:
    (A) Identification of the previously certified gasoline as such;
    (B) The batch number assigned by the receiving refinery;
    (C) The date of receipt; and
    (D) The volume, properties and designation of the batch;
    (vii) In the case of butane blended with conventional gasoline under 
Sec. 80.82:
    (A) Identification of the butane batch as complying with the 
provisions of Sec. 80.82;

[[Page 790]]

    (B) Identification of the butane batch as commercial or non-
commercial grade butane;
    (C) The batch number of the butane;
    (D) The date of production of the gasoline produced using the 
butane;
    (E) The volume of the butane batch;
    (F) The properties of the butane batch specified by the butane 
supplier, or the properties specified in Sec. 80.82(c) or (d), as 
appropriate.
    (G) Where butane is blended with conventional gasoline during the 
period May 1 through September 15, the Reid vapor pressure, as measured 
using the appropriate test method in Sec. 80.46; and
    (viii) In the case of any imported GTAB, identification of the 
gasoline as GTAB.
    (6) Such other information as EPA may require.
    (7) For refiners that blend any butane with conventional gasoline 
under Sec. 80.82, the report required under paragraph (a) of this 
section must include the following information for the annual averaging 
period:
    (i) The total volume of butane blended with conventional gasoline;
    (ii) The total volume of conventional gasoline produced using 
butane;
    (iii) A statement that the gasoline produced using butane meets all 
applicable downstream standard that apply to conventional gasoline under 
Subpart E; and
    (iv) A statement that all butane blended with conventional gasoline 
at the refinery is included in the volume under paragraph (a)(7)(i) of 
this section, or a statement that all butane blended with conventional 
gasoline is included in the refinery's annual average compliance 
calculations under Sec. 80.101.
    (b) The reporting requirements of paragraph (a) of this section do 
not apply in the case of any conventional gasoline or gasoline 
blendstock that is excluded from a refiner's or importer's compliance 
calculation pursuant to Sec. 80.101(e).
    (c) For each averaging period, each refiner for each refinery and 
importer shall cause to be submitted to the Administrator of EPA, by May 
31 of each year, a report in accordance with the requirements for the 
Attest Engagements of Sec. 80.125 through Sec. 80.131.
    (d) The report required by paragraph (a) of this section shall be:
    (1) Submitted on forms and following procedures specified by the 
Administrator of EPA;
    (2) Submitted to EPA by the last day of February each year for the 
prior calendar year averaging period; and
    (3) Signed and certified as correct by the owner or a responsible 
corporate officer of the refiner or importer.

[59 FR 7860, Feb. 16, 1994, as amended at 59 FR 36969, July 20, 1994; 60 
FR 65575, Dec. 20, 1995; 66 FR 67108, Dec. 28, 2001; 67 FR 8738, Feb. 
26, 2002; 70 FR 74573, Dec. 15, 2005]



Sec. 80.106  Product transfer documents.

    (a)(1) On each occasion when any person transfers custody or title 
to any conventional gasoline, the transferor shall provide to the 
transferee documents which include the following information:
    (i) The name and address of the transferor;
    (ii) The name and address of the transferee;
    (iii) The volume of gasoline being transferred;
    (iv) The location of the gasoline at the time of the transfer;
    (v) The date of the transfer; and
    (vi) The following statement: ``This product does not meet the 
requirements for reformulated gasoline, and may not be used in any 
reformulated gasoline covered area.''
    (2) The requirements of paragraph (a)(1) of this section apply to 
product that becomes gasoline upon the addition of oxygenate only.
    (b) [Reserved]

[59 FR 7860, Feb. 16, 1994, as amended at 67 FR 8738, Feb. 26, 2002; 70 
FR 74573, Dec. 15, 2005]



Sec. Sec. 80.107-80.124  [Reserved]



                      Subpart F_Attest Engagements

    Source: 59 FR 7875, Feb. 16, 1994, unless otherwise noted.



Sec. 80.125  Attest engagements.

    (a) Any refiner and importer subject to the requirements of this 
subpart F shall engage an independent certified

[[Page 791]]

public accountant, or firm of such accountants (hereinafter referred to 
in this subpart F as ``CPA''), to perform an agreed-upon procedures 
attestation engagement of the underlying documentation that forms the 
basis of the reports required by Sec. Sec. 80.75 and 80.105.
    (b) The CPA shall perform the attestation engagements in accordance 
with the Statements on Standards for Attestation Engagements.
    (c) The CPA may complete the requirements of this subpart F with the 
assistance of internal auditors who are employees or agents of the 
refiner or importer, so long as such assistance is in accordance with 
the Statements on Standards for Attestation Engagements.
    (d) Notwithstanding the requirements of paragraph (a) of this 
section, any refiner or importer may satisfy the requirements of this 
subpart F if the requirements of this subpart F are completed by an 
auditor who is an employee of the refiner or importer, provided that 
such employee:
    (1) Is an internal auditor certified by the Institute of Internal 
Auditors, Inc. (hereinafter referred to in this subpart F as ``CIA''); 
and
    (2) Completes the internal audits in accordance with the 
Codification of Standards for the Professional Practice of Internal 
Auditing.
    (e) Use of a CPA or CIA who is debarred, suspended, or proposed for 
debarment pursuant to the Governmentwide Debarment and Suspension 
Regulations, 2 CFR part 1532, or the Debarment, Suspension, and 
Ineligibility Provisions of the Federal Acquisition Regulations, 48 CFR 
part 9, subpart 9.4, shall be deemed in noncompliance with the 
requirements of this section.
    (f) The following documents are incorporated by reference: the 
Statements on Standards for Attestation Engagements, Codification of 
Statements on Auditing Standards, written by the American Institute of 
Certified Public Accountants, Inc., 1991, and published by the Commerce 
Clearing House, Inc., Identification Number 059021, and the Codification 
of Standards for the Professional Practice of Internal Auditing, written 
and published by the Institute of Internal Auditors, Inc., 1989, 
Identification Number ISBN 0-89413-207-5. 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. Copies of the 
Statements on Standards for Attestation Engagements may be obtained from 
the American Institute of Certified Public Accountants, Inc., 1211 
Avenue of the Americas, New York, New York 10036, and copies of the 
Codification of Standards for the Professional Practice of Internal 
Auditing may be obtained from the Institute of Internal Auditors, Inc., 
249 Maitland Avenue, Altamonte Springs, Florida 32701-4201. Copies may 
be inspected at the U.S. Environmental Protection Agency, Office of the 
Air Docket, 401 M St., SW., Washington, DC., 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.

[59 FR 7875, Feb. 16, 1994, as amended at 59 FR 36969, July 20, 1994; 70 
FR 74573, Dec. 15, 2005; 71 FR 26701, May 8, 2006; 72 FR 2427, Jan. 19, 
2007]



Sec. 80.126  Definitions.

    The following definitions shall apply for the purposes of this 
subpart F:
    (a) Averaging compliance records shall include the calculations used 
to determine compliance with relevant standards on average, for each 
averaging period and for each quantity of gasoline for which standards 
must be achieved separately.
    (b) Credit Trading Records. Credit trading records shall include 
worksheets and EPA reports showing actual and complying totals for 
benzene; credit calculation worksheets; contracts; letter agreements; 
and invoices and other documentation evidencing the transfer of credits.
    (c) Designation records shall include laboratory analysis reports 
that identify whether gasoline meets the requirements for a given 
designation; operational and accounting reports of product storage; and 
product transfer documents.

[[Page 792]]

    (d) Oxygenate blender records shall include laboratory analysis 
reports; refiner, importer and oxygenate blender contracts; quality 
assurance program records; product transfer documents; oxygenate 
purchasing, inventory, and usage records; and daily tank inventory 
gauging reports, meter tickets, and product transfer documents.
    (e) Product transfer documents means copies of documents represented 
by the refiner/importer/oxygenate blender as having been provided to the 
transferee, and that reflect the transfer of ownership or physical 
custody of gasoline or blendstock (e.g., invoices, receipts, bills of 
lading, manifests, and/or pipeline tickets).
    (f) Tender means the transfer of ownership or physical custody of a 
volume of gasoline or other petroleum product all of which has the same 
identification (reformulated gasoline, conventional gasoline, RBOB, and 
other non-finished-gasoline petroleum products), and characteristics 
(time and place of use restrictions for reformulated gasoline and RBOB).
    (g) Volume records shall include summaries of gasoline produced or 
imported that account for the volume of each type of gasoline produced 
or imported. The volumes shall be based on tank gauges or meter reports 
and temperature adjusted to 60 degrees Fahrenheit.
    (h) Attestor means the CPA or CIA performing the agreed-upon 
procedures engagement under this subpart.
    (i) Foot (or crossfoot) means to add a series of numbers, generally 
in columns (or rows), to a total amount. When applying the attestation 
procedures in this subpart F, the attestor may foot to subtotals on a 
sample basis in those instances where subtotals (e.g., page totals) 
exist. In such instances, the total should be footed from the subtotals 
and the subtotals should be footed on a test basis using no less than 
25% of the subtotals.
    (j) Laboratory Analysis means the original test result for each 
analysis that was used to determine a product's properties. For 
laboratories using test methods that must be correlated to the standard 
test method, the correlation factors and results shall be included as 
part of the laboratory analysis. For refineries or importers that 
produce reformulated gasoline or RBOB and use the 100% independent lab 
testing, the laboratory analysis shall consist of the results reported 
to the refinery or importer by the independent lab. Where assumed 
properties used (e.g., for butane) the assumed properties may serve as 
the test results.
    (k) Non-finished-gasoline petroleum products means liquid petroleum 
products that have boiling ranges greater than 75 degrees Fahrenheit, 
but less than 450 degrees Fahrenheit, as per ASTM D 86 or equivalent.
    (l) Reporting period means the time period relating to the reports 
filed with EPA by the refiner, importer, or oxygenate blender, and 
generally is the calendar year.

[59 FR 7875, Feb. 16, 1994, as amended at 70 FR 74574, Dec. 15, 2005; 71 
FR 26701, May 8, 2006]



Sec. 80.127  Sample size guidelines.

    In performing the attest engagement, the auditor shall sample 
relevant populations to which agreed-upon procedures will be applied 
using the methods specified in this section, which shall constitute a 
representative sample.
    (a) Sample items shall be selected in such a way as to comprise a 
simple random sample of each relevant population; and
    (b) Sample size shall be determined using one of the following 
options:
    (1) Option 1. Determine the sample size using the following table:

                 Sample Size, Based Upon Population Size
------------------------------------------------------------------------
           No. in population (N)                     Sample size
------------------------------------------------------------------------
66 and larger.............................  29
41-65.....................................  25
26-40.....................................  20
0-25......................................  N or 19, whichever is
                                             smaller.
------------------------------------------------------------------------

    (2) Option 2. Determine the sample size in such a manner that the 
sample size is equal to that which would result by using the following 
parameters and standard statistical methodologies:

Confidence Level--95%
Expected Error Rate--0%
Maximum Tolerable Error Rate--10%

    (3) Option 3. The auditor may use some other form of sample 
selection and/or some other method to determine

[[Page 793]]

the sample size, provided that the resulting sample affords equal or 
better strength of inference and freedom from bias (as compared with 
paragraphs (b)(1) and (2) of this section), and that the auditor 
summarizes the substitute methods and clearly demonstrates their 
equivalence in the final report on the audit.



Sec. 80.128  Alternative agreed upon procedures for refiners and importers.

    Prior to the attest report for the 2006 reporting period, the 
following minimum attest procedures may be carried out for a refinery or 
importer, in lieu of the attest procedures specified in Sec. 80.133.
    (a) Read the refiner's or importer's reports filed with EPA for the 
previous year as required by Sec. Sec. 80.75, 80.83(g), and 80.105.
    (b) Obtain a gasoline inventory reconciliation analysis for the 
current year from the refiner or importer which includes reformulated 
gasoline, RBOB, conventional gasoline, and non-finished-gasoline 
petroleum products.
    (1) Test the mathematical accuracy of the calculations contained in 
the analysis.
    (2) Agree the beginning and ending inventories to the refiner's or 
importer's perpetual inventory records.
    (c) Obtain separate listings of all tenders during the current year 
of reformulated gasoline, RBOB, conventional gasoline, and non-finished-
gasoline petroleum products.
    (1) Test the mathematical accuracy of the calculations contained in 
the listings.
    (2) Agree the listings of tenders' volumes to the gasoline inventory 
reconciliation in paragraph (b) of this section.
    (3) Agree the listings of tenders' volumes, where applicable, to the 
EPA reports.
    (d) Select a representative sample from the listing of reformulated 
gasoline tenders, and for this sample:
    (1) Agree the volumes to the product transfer documents;
    (2) Compare the product transfer documents designation for 
consistency with the time and place, and compliance model designations 
for the tender (VOC-controlled or non-VOC-controlled, VOC region for 
VOC-controlled, summer or winter gasoline, and simple or complex model 
certified); and
    (3) Trace back to the batch or batches in which the gasoline was 
produced or imported. Obtain the refiner's or importer's internal 
laboratory analyses for each batch and compare such analyses for 
consistency with the analyses results reported to EPA and to the time 
and place designations for the tender's product transfer documents.
    (e) Select a representative sample from the listing of RBOB tenders, 
and for this sample:
    (1) Agree the volumes to the original product transfer documents;
    (2) Determine that the requisite contract was in place with the 
downstream blender designating the required blending procedures, or that 
the refiner or importer accounted for the RBOB using the assumptions in 
Sec. 80.69(a)(8) in the case of RBOB designated as ``any oxygenate,'' 
or ``ether only,'' or using the assumptions in Sec. Sec. 
80.83(c)(1)(ii) (A) and (B) in the case of RBOB designated as ``any 
renewable oxygenate,'' ``non VOC controlled renewable ether only,'' or 
``renewable ether only'';
    (3) Review the product transfer documents for the indication of the 
type and amount of oxygenate required to be added to the RBOB;
    (4) Trace back to the batch or batches in which the RBOB was 
produced or imported. Obtain refiner's or importer's internal lab 
analysis for each batch and agree the consistency of the type and volume 
of oxygenate required to be added to the RBOB with that indicated in 
applicable tender's product transfer documents;
    (5) Agree the sampling and testing frequency of the refiner's or 
importer's downstream oxygenated blender quality assurance program with 
the sampling and testing rates as required in Sec. 80.69(a)(7); and
    (6) In the case of RBOB designated as ``any renewable oxygenate,'' 
``non VOC controlled renewable ether'' or ``renewable ether only'', 
review the documentation from the producer of the oxygenate to determine 
if the oxygenate meets the requirements of Sec. 80.83(a).
    (f) Select a representative sample of reformulated gasoline and RBOB

[[Page 794]]

batches produced by computerized in-line blending, and for this sample:
    (1) Obtain the composite sample internal laboratory analyses 
results; and
    (2) Agree the results of the internal laboratory analyses to the 
quarterly batch information submitted to the EPA.
    (g) Select a representative sample from the listing of the tenders 
of conventional gasoline and conventional gasoline blendstock that 
becomes gasoline through the addition of oxygenate only, and for this 
sample:
    (1) Agree the volumes to the product transfer documents;
    (2) For a representative sample of tenders, trace back to the batch 
or batches in which the gasoline was produced or imported. Obtain the 
refiner's or importer's internal laboratory analyses for each batch and 
compare such analyses for consistency with the analyses results reported 
to EPA; and
    (3) Where the refiner or importer has included oxygenate that is 
blended downstream of the refinery or import facility in its compliance 
calculations in accordance with Sec. 80.101(d)(4)(ii), obtain a listing 
of each downstream oxygenate blending operation from which the refiner 
or importer is claiming oxygenate for use in compliance calculations, 
and for each such operation:
    (i) Determine if the refiner or importer had a contract in place 
with the downstream blender during the period oxygenate was blended;
    (ii) Determine if the refiner or importer has records reflecting 
that it conducted physical inspections of the downstream blending 
operation during the period oxygenate was blended;
    (iii) Obtain a listing from the refiner or importer of the batches 
of conventional gasoline or conventional sub-octane blendstock, and the 
compliance calculations which include oxygenate blended by the 
downstream oxygenate blender, and test the mathematical accuracy of the 
calculations contained in this listing;
    (iv) Obtain a listing from the downstream oxygenate blender of the 
oxygenate blended with conventional gasoline or sub-octane blendstock 
that was produced or imported by the refiner or importer. Test the 
mathematical accuracy of the calculations in this listing. Agree the 
overall oxygenate blending listing obtained from the refiner or importer 
with the listing obtained from the downstream oxygenate blender. Select 
a representative sample of oxygenate blending listing obtained from the 
downstream oxygenate blender, and for this sample:
    (A) Using product transfer documents, determine if the oxygenate was 
blended with conventional gasoline or conventional sub-octane blendstock 
that was produced by the refiner or imported by the importer; and
    (B) Agree the oxygenate volume with the refiner's or importer's 
listing of oxygenate claimed for this gasoline;
    (v) Obtain a listing of the sampling and testing conducted by the 
refiner or importer over the downstream oxygenate blending operation. 
Select a representative sample of the test results from this listing, 
and for this sample agree the tested oxygenate volume with the oxygenate 
use listings from the refiner or importer, and from the oxygenate 
blender; and
    (vi) Obtain a copy of the records reflecting the refiner or importer 
audit over the downstream oxygenate blending operation. Review these 
records for indications that the audit included review of the overall 
volumes and type of oxygenate purchased and used by the oxygenate 
blender to be consistent with the oxygenate claimed by the refiner or 
importer and that this oxygenate was blended with the refiner's or 
importer's gasoline or blending stock.

[59 FR 7875, Feb. 16, 1994, as amended at 59 FR 36969, July 20, 1994; 59 
FR 39292, Aug. 2, 1994; 62 FR 60136, Nov. 6, 1997; 67 FR 8738, Feb. 26, 
2002; 70 FR 74574, Dec. 15, 2005]

    Effective Date Note: At 59 FR 39292, Aug. 2, 1994, Sec. 80.128 was 
amended by revising paragraphs (a) and (e)(2); removing ``and'' at the 
end of paragraph (e)(4); removing the period at the end of paragraph 
(e)(5) and adding ``; and'' in its place; and adding paragraph (e)(6) 
effective September 1, 1994. At 59 FR 60715, Nov. 28, 1994, the 
amendment was stayed effective September 13, 1994. At 70 FR 74574, Dec. 
15, 2005, Sec. 80.128 was amended by revising paragraphs (e)(2), (e)(4) 
and (e)(5) and removing paragraph (e)(6); however, the amendment could 
not be incorporated because those paragraphs are stayed. At 71 FR 26702, 
May 8, 2006, Sec. 80.128 was amended by revising paragraph (e)(2); 
however, the amendment could not be incorporated because that paragraph 
is stayed. At 72 FR 8543, Feb. 26, 2007,

[[Page 795]]

Sec. 80.128 was amended by revising paragraph (a); however, the 
amendment could not be incorporated because that paragraph is stayed.



Sec. 80.129  [Reserved]



Sec. 80.130  Agreed upon procedures reports.

    (a) Reports. (1) The CPA or CIA shall issue to the refiner or 
importer a report summarizing the procedures performed in the findings 
in accordance with the attest engagement or internal audit performed in 
compliance with this subpart.
    (2) The refiner or importer shall provide a copy of the auditor's 
report to the EPA within the time specified in Sec. 80.75(m).
    (b) Record retention. The CPA or CIA shall retain all records 
pertaining to the performance of each agreed upon procedure and 
pertaining to the creation of the agreed upon procedures report for a 
period of five years from the date of creation and shall deliver such 
records to the Administrator upon request.

[59 FR 7875, Feb. 16, 1994, as amended at 71 FR 26702, May 8, 2006]



Sec. 80.131  Agreed upon procedures for GTAB, certain conventional
gasoline imported by truck, previously certified gasoline used

to produce gasoline, and butane blenders.

    (a) Attest procedures for GTAB. The following are the attest 
procedures to be carried out in the case of an importer who imports 
gasoline classified as blendstock (or ``GTAB'') under the terms of Sec. 
80.83:
    (1) Obtain a listing of all GTAB volumes imported for the reporting 
period. Agree the total volume of GTAB from the listing to the inventory 
reconciliation analysis under Sec. 80.133, or agree to alternative 
documents if the inventory reconciliation analysis is not sufficient.
    (2) Obtain a listing of all GTAB batches reported to EPA by the 
importer. Agree the total volume of GTAB from the listing to the GTAB 
volumes reported to EPA. Note that the EPA report includes a notation 
that the batch is not included in the compliance calculations because 
the imported product is GTAB. Also, agree these volumes to the Import 
Summary received from the U.S. Customs Service.
    (3) Select a sample, in accordance with the guidelines in Sec. 
80.127, from the listing of GTAB batches obtained in paragraph (a)(2) of 
this section, and for each GTAB batch selected perform the following:
    (i) Trace the GTAB batch to the tank activity records. From the tank 
activity records, determine the volumes of conventional gasoline and of 
RFG produced. Agree the volumes from the tank activity records to the 
batch volume reported to the EPA as reformulated or conventional 
gasoline.
    (ii) Agree the location of the refinery represented by the tank 
activity records obtained in paragraph (a)(3)(i) of this section for the 
gasoline produced from GTAB, to the location that the GTAB arrived in 
the U.S. or at a facility to which GTAB is directly transported from the 
import facility using records representing location (e.g., U.S. Customs 
Service entry records). Using product transfer records, trace volumes 
transported from the import facility directly to the refinery as 
applicable.
    (iii) Obtain tank activity records for all batches of GTAB received 
and blended. Using the tank activity records, determine whether the GTAB 
was received into an empty tank, or into a tank containing other GTAB 
imported by that importer or finished gasoline of the same category as 
the gasoline that will be produced using the GTAB or into a tank 
containing blendstock.
    (iv) Using the tank activity records obtained under paragraph 
(a)(3)(iii) of this section, determine the volume of any tank bottom 
(beginning tank inventory) that is previously certified gasoline before 
GTAB is added to the tank. Using lab reports, batch reports, or product 
transfer documents, determine the properties of the tank bottom.
    (v) Determine whether the properties and volume of gasoline produced 
using GTAB were determined in a manner that excludes the volume and 
properties of any gasoline that previously has been included in any 
refiners or importers compliance calculations, as follows:

[[Page 796]]

    (A) Note documented tank mixing procedures.
    (B) Determine the volume and properties of the gasoline contained in 
the storage tank after blending is complete. Mathematically subtract the 
volume and properties of the previously certified gasoline to determine 
the volume and properties of the GTAB plus blendstock added. Agree the 
volume and properties of the GTAB plus blendstock added to the volume 
reported to EPA as a batch of gasoline produced; or
    (C) In the alternative, using the tank activity records, note that 
only GTAB and blending components were combined, and that no gasoline 
was added to the tank. Agree the volumes and properties of the shipments 
from the tank after the GTAB and blendstock are added, blended, and 
sampled and tested, to the volumes and properties reported to the EPA by 
the refiner.
    (vi) Obtain the importer's laboratory analysis for each batch of 
GTAB selected, and agree the properties listed in the corresponding 
batch report submitted to the EPA, to the laboratory analysis.
    (b) Attest procedures for certain truck imports. The following are 
the attest procedures to be carried out in the case of an importer who 
imports conventional gasoline into the United States by truck using the 
sampling and testing option in Sec. 80.101(i)(3) (``Sec. 80.101(i)(3) 
truck imports'').
    (1) Obtain a listing of all volumes of Sec. 80.101(i)(3) truck 
imports for the reporting period. Agree the total volume of Sec. 
80.101(i)(3) truck imports from the listing to the inventory 
reconciliation analysis under Sec. 80.132.
    (2) Obtain a listing of all Sec. 80.101(i)(3) truck import batches 
reported to EPA by the importer. Agree the total volume of Sec. 
80.101(i)(3) truck imports from the listing to the volume of Sec. 
80.101(i)(3) truck imports reported to EPA. Also, agree these totals to 
the Import Summary received from the U.S. Customs Service.
    (3) Select a sample, in accordance with the guidelines in Sec. 
80.127, from the listing obtained in paragraph (b)(2) of this section, 
and for each Sec. 80.101(i)(3) truck import batch selected perform the 
following:
    (i) Obtain the copy of the terminal test results for the batch, 
under Sec. 80.101(i)(3)(iii)(A), and determine that the sample was 
analyzed using the test methods specified in Sec. 80.46, and agree the 
terminal test results to the batch properties reported to EPA; and
    (ii) Obtain tank activity records for the terminal storage tank 
showing receipts, discharges, and sampling, and determine that the 
sample under paragraph (b)(3)(i) of this section was collected 
subsequent to the most recent receipt into the storage tank.
    (4) Obtain listings for each terminal where Sec. 80.101(i)(3) truck 
import gasoline was loaded, of all quality assurance samples collected 
by the importer, and for each terminal select a sample in accordance 
with the guidelines in Sec. 80.127 from the listing. For each quality 
assurance sample selected perform the following:
    (i) Determine that the sample was analyzed by the importer or by an 
independent laboratory, and that the analysis was performed using the 
test methods specified in Sec. 80.46;
    (ii) Obtain the terminal's test results that correspond in time to 
the time the quality assurance sample was collected, and agree the 
terminal's test results with the quality assurance test results; and
    (iii) Determine that the quality assurance sample was collected 
within the frequency specified in Sec. 80.101(i)(3)(iv)(D).
    (c) Attest procedures for previously certified gasoline. The 
following are the attest procedures to be carried out in the case of a 
refiner who uses previously certified gasoline under the requirements of 
Sec. Sec. 80.65(i) and 80.101(g)(9).
    (1) Obtain a listing of all batches of previously certified gasoline 
used under the requirements of Sec. 80.65(i) which were received at the 
refinery during the reporting period. Agree the total volume of such 
previously certified gasoline from the listing to the inventory 
reconciliation analysis under Sec. 80.133, or agree to alternative 
documents if the inventory reconciliation analysis is not sufficient.
    (2) Obtain a listing of all previously certified gasoline batches 
reported to EPA by the refiner. Agree the total volume of previously 
certified gasoline

[[Page 797]]

from the listing of previously certified gasoline received in paragraph 
(c)(1) of this section to the volume of previously certified gasoline 
reported to EPA.
    (3) Select a sample, in accordance with the guidelines in Sec. 
80.127, from the listing obtained in paragraph (c)(2) of this section, 
and for each previously certified gasoline batch selected perform the 
following:
    (i) Trace the previously certified gasoline batch to the tank 
activity records. Confirm that the previously certified gasoline was 
included in a batch of reformulated or conventional gasoline produced at 
the refinery.
    (ii) Obtain the refiner's laboratory analysis and volume measurement 
for the previously certified gasoline when received and agree the 
properties and volume listed in the corresponding batch report submitted 
to the EPA, to the laboratory analysis and volume measurements.
    (iii) Obtain the product transfer documents for the previously 
certified gasoline when received and agree the designations from the 
product transfer documents to designations in the corresponding batch 
report submitted to EPA (reformulated gasoline, RBOB or conventional 
gasoline, and designations regarding VOC control).
    (d) Attest procedures for butane blenders. The following are the 
attest procedures to be carried out by a refiner who blends butane under 
Sec. 80.82.
    (1) Obtain a listing of all butane batches received at the refinery 
during the reporting period.
    (2) Obtain a listing of all butane batches reported to EPA by the 
refiner for the reporting period. Agree the total volume of butane from 
the receipt listing to the volume of butane reported to EPA.
    (3) Select a sample, in accordance with the guidelines in Sec. 
80.127, from the listing of butane batches reported to EPA, and for each 
butane batch selected perform the following:
    (i) Trace the butane included in the batch to the documents provided 
to the refiner by the butane supplier for the butane. Determine, and 
report as a finding, whether these documents establish the butane was 
commercial grade, non-commercial grade, or neither commercial nor non-
commercial grade as defined in Sec. 80.82.
    (ii) In the case of non-commercial grade butane, obtain the 
refiner's sampling and testing results for butane, and confirm that the 
frequency of the sampling and testing was consistent with the 
requirements in Sec. 80.82.

[70 FR 74574, Dec. 15, 2005]



Sec. 80.132  [Reserved]



Sec. 80.133  Agreed-upon procedures for refiners and importers.

    The following are the minimum attest procedures that shall be 
carried out for each refinery and importer. Agreed upon procedures may 
vary from the procedures stated in this section due to the nature of the 
refiner's or importer's business or records, provided that any refiner 
or importer desiring to use modified procedures obtains prior approval 
from EPA.
    (a) EPA reports. (1) Obtain and read a copy of the refinery's or 
importer's reports (except for batch reports) filed with the EPA as 
required by Sec. Sec. 80.75 and 80.105 for the reporting period.
    (2) In the case of a refiner's report to EPA that represents 
aggregate calculations for more than one refinery, obtain the refinery-
specific volume and property information that was used by the refiner to 
prepare the aggregate report. Foot and crossfoot the refinery-specific 
totals and agree to the values in the aggregate report. The procedures 
in paragraphs (b) through (m) of this section then are performed 
separately for each refinery.
    (3) Obtain a written representation from a company representative 
that the report copies are complete and accurate copies of the reports 
filed with the EPA.
    (4) Identify, and report as a finding, the name of the commercial 
computer program used by the refiner or importer to track the data 
required by the regulations in this part, if any.
    (b) Inventory reconciliation analysis. Obtain an inventory 
reconciliation analysis for the refinery or importer for the reporting 
period by product type (i.e., reformulated gasoline, RBOB, conventional 
gasoline, and non-finished-gasoline petroleum products), and perform the 
following:

[[Page 798]]

    (1) Foot and crossfoot the volume totals reflected in the analysis; 
and
    (2) Agree the beginning and ending inventory amounts in the analysis 
to the refinery's or importer's inventory records. If the analysis shows 
no production of conventional gasoline or if the refinery or importer 
represents under paragraph (l) of this section that it has a baseline 
less stringent or equal to the statutory baseline, the analysis may 
exclude non-finished-gasoline petroleum products.
    (3) Report as a finding the volume totals for each product type.
    (c) Listing of tenders. For each product type other than non-
finished gasoline petroleum products (i.e., reformulated gasoline, RBOB, 
conventional gasoline), obtain a separate listing of all tenders from 
the refinery or importer for the reporting period. Each listing should 
provide for each tender the volume shipped and other information as 
needed to distinguish tenders. Perform the following:
    (1) Foot to the volume totals per the listings; and
    (2) For each product type listed in the inventory reconciliation 
analysis obtained in paragraph (b) of this section, agree the volume 
total on the listing to the tender volume total in the inventory 
reconciliation analysis.
    (d) Listing of batches. For each product type other than non-
finished gasoline petroleum products (i.e., reformulated gasoline, RBOB, 
and conventional gasoline), obtain separate listings of all batches 
reported to the EPA and perform the following:
    (1) Foot to the volume totals per the listings; and
    (2) Agree the total volumes in the listings to the production volume 
in the inventory reconciliation analysis obtained in paragraph (b) of 
this section.
    (e) Reformulated gasoline tenders. Select a sample, in accordance 
with the guidelines in Sec. 80.127, from the listing of reformulated 
gasoline tenders obtained in paragraph (c) of this section, and for each 
tender selected perform the following:
    (1) Obtain product transfer documents associated with the tender and 
agree the volume on the tender listing to the volume on the Product 
transfer documents; and
    (2) Note whether the product transfer documents evidencing the date 
and location of the tender and the compliance model designations for the 
tender (VOC-controlled for Region 1 or 2, non VOC-controlled, and simple 
or complex model certified).
    (f) Reformulated gasoline batches. Select a sample, in accordance 
with the guidelines in Sec. 80.127, from the listing of reformulated 
gasoline batches obtained in paragraph (d) of this section, and for each 
batch selected perform the following:
    (1) Agree the volume shown on the listing, to the volume listed in 
the corresponding batch report submitted to EPA; and
    (2) Obtain the refinery's or importer's laboratory analysis and 
agree the properties listed in the corresponding batch report submitted 
to EPA, to the properties listed in the laboratory analysis.
    (g) RBOB tenders. Select a sample, in accordance with the guidelines 
in Sec. 80.127, from the listing of RBOB tenders obtained in paragraph 
(c) of this section, and for each tender selected perform the following:
    (1) Obtain product transfer documents associated with the tender and 
agree the volume on the tender listing to the volume on the product 
transfer documents; and
    (2) Inspect the product transfer documents evidencing the type and 
amount of oxygenate to be added to the RBOB.
    (h) RBOB batches. Select a sample, in accordance with the guidelines 
in Sec. 80.127, from the listing of RBOB batches obtained in paragraph 
(d) of this section, and for each batch selected perform the following:
    (1) Obtain from the refiner or importer the oxygenate type and 
volume, and oxygen volume required to be hand blended with the RBOB, in 
accordance with Sec. 80.69(a)(2).
    (2) Agree the volume shown on the listing, as adjusted to reflect 
the oxygenate volume determined under paragraph (h)(1) of this section, 
to the volume listed in the corresponding batch report submitted to EPA; 
and
    (3) Obtain the refinery's or importer's laboratory analysis of the 
RBOB hand blend and agree:

[[Page 799]]

    (i) The oxygenate type and oxygen amount determined under paragraph 
(h)(1) of this section, to the tested oxygenate type and oxygen amount 
listed in the laboratory analysis within the acceptable ranges set forth 
at Sec. 80.65(e)(2)(i); and
    (ii) The properties listed in the corresponding batch report 
submitted to EPA to the properties listed in the laboratory analysis.
    (4) Perform the following procedures for each batch report included 
in paragraph (h)(4)(i)(B) of this section:
    (i) Obtain and inspect a copy of the executed contract with the 
downstream oxygenate blender (or with an intermediate owner), and 
confirm that the contract:
    (A) Was in effect at the time of the corresponding RBOB transfer; 
and
    (B) Allowed the company to sample and test the reformulated gasoline 
made by the blender.
    (ii) Obtain a listing of RBOB blended by downstream oxygenate 
blenders and the refinery's or importer's oversight test results, and 
select a representative sample, in accordance with the guidelines in 
Sec. 80.127, from the listing of test results and for each test 
selected perform the following:
    (A) Obtain the laboratory analysis for the batch, and agree the type 
of oxygenate used and the oxygenate content appearing in the laboratory 
analysis to the instructions stated on the product transfer documents 
corresponding to a RBOB receipt immediately preceding the laboratory 
analysis and used in producing the reformulated gasoline batch selected 
within the acceptable ranges set forth at Sec. 80.65(e)(2)(i);
    (B) Calculate the frequency of sampling and testing or the volume 
blended between the test selected and the next test; and
    (C) Agree the frequency of sampling and testing or the volume 
blended between the test selected and the next test to the sampling and 
testing frequency rates stated in Sec. 80.69(a)(7).
    (i) Conventional gasoline and conventional gasoline blendstock 
tenders. Select a sample, in accordance with the guidelines in Sec. 
80.127, from the listing of the tenders of conventional gasoline and 
conventional gasoline blendstock that becomes gasoline through the 
addition of oxygenate only, and for each tender selected perform the 
following:
    (1) Obtain product transfer documents associated with the tender and 
agree the volume on the tender listing to the volume on the product 
transfer documents; and
    (2) Inspect the product transfer documents evidencing that the 
information required in Sec. 80.106(a)(1)(vii) is included.
    (j) Conventional gasoline batches. Select a sample, in accordance 
with the guidelines in Sec. 80.127, from the conventional gasoline 
batch listing obtained in paragraph (d) of this section, and for each 
batch selected perform the following:
    (1) Agree the volume shown on the listing, to the volume listed in 
the corresponding batch report submitted to EPA; and
    (2) Obtain the refinery's or importer's laboratory analysis and 
agree the properties listed in the corresponding batch report submitted 
to EPA, to the properties listed in the laboratory analysis.
    (k) Conventional gasoline oxygenate blending. Obtain a listing of 
each downstream oxygenate blending facility and its blender, as 
represented by the refiner/importer, as adding oxygenate used in the 
compliance calculations for the refinery or importer, or a written 
representation from the refiner for the refinery or importer that it has 
not used any downstream oxygenate blending in its conventional gasoline 
compliance calculations.
    (1) For each downstream oxygenate blender facility, obtain a listing 
from the refiner or importer of the batches of oxygenate included in its 
compliance calculations added by the downstream oxygenate blender and 
foot to the total volume of batches per the listing;
    (2) Obtain a listing from the downstream oxygenate blender of the 
oxygenate blended with conventional gasoline or sub-octane blendstock 
that was produced or imported by the refinery or importer and perform 
the following:
    (i) Foot to the total volume of the oxygenate batches per the 
listing; and
    (ii) Agree the total volumes in the listing obtained from the 
downstream

[[Page 800]]

oxygenate blender, to the listing obtained from the refiner or importer 
in paragraph (k)(1) of this section.
    (3) Where the downstream oxygenate blender is a person other than 
the refiner or importer, as represented by management of the refinery or 
importer, perform the following:
    (i) Obtain the contract from the refiner or importer with the 
downstream blender and inspect the contract evidencing that it covered 
the period when oxygenate was blended;
    (ii) Obtain company documents evidencing that the refiner or 
importer has records reflecting that it conducted physical inspections 
of the downstream blending operation during the period oxygenate was 
blended;
    (iii) Obtain company documents reflecting the refiner or importer 
audit over the downstream oxygenate blending operation and note whether 
these records evidencing the audit included a review of the overall 
volumes and type of oxygenate purchased and used by the oxygenate 
blender to be consistent with the oxygenate claimed by the refiner or 
importer, and that this oxygenate was blended with the refinery's or 
importer's gasoline or blending stock; and
    (iv) Obtain a listing of test results for the sampling and testing 
conducted by the refiner or importer over the downstream oxygenate 
blending operation, and select a sample, in accordance with the 
guidelines in Sec. 80.127, from this listing. For each test selected, 
agree the tested oxygenate volume with the oxygenate volume in the 
listing obtained from the oxygenate blender in paragraph (k)(2) of this 
section for this gasoline.

[70 FR 74576, Dec. 15, 2005, as amended at 71 FR 26702, May 8, 2006]



Sec. Sec. 80.134-80.135  [Reserved]



                      Subpart G_Detergent Gasoline

    Source: 59 FR 54706, Nov. 1, 1994, unless otherwise noted.



Sec. 80.140  Definitions.

    The definitions in this section apply only to subpart G of this 
part. Any terms not defined in this subpart shall have the meaning given 
them in 40 CFR part 80, subpart A, or, if not defined in 40 CFR part 80, 
subpart A, shall have the meaning given them in 40 CFR part 79, subpart 
A.
    Additization means the addition of detergent to gasoline or post-
refinery component in order to create detergent-additized gasoline or 
detergent-additized post-refinery component.
    Automated detergent blending facility means any facility (including, 
but not limited to, a truck or individual storage tank) at which 
detergent is blended with gasoline or post-refinery component, by means 
of an injector system calibrated to automatically deliver a prescribed 
amount of detergent.
    Base gasoline means any gasoline that does not contain detergent.
    Carburetor deposits means the deposits formed in the carburetor 
during operation of a carburetted gasoline engine which can disrupt the 
ability of the carburetor to maintain the proper air/fuel ratio.
    Carrier of detergent means any distributor of detergent who 
transports or stores or causes the transportation or storage of 
detergent without taking title to or otherwise having any ownership of 
the detergent, and without altering either the quality or quantity of 
the detergent.
    Deposit control effectiveness means the ability of a detergent 
additive package to prevent the formation of deposits in gasoline 
engines.
    Deposit control efficiency means the degree to which a detergent 
additive package at a given concentration in gasoline is effective in 
limiting the formation of deposits. The addition of inactive ingredients 
to a detergent additive package, to the extent that this addition 
dilutes the concentration of the detergent-active components, reduces 
the deposit control efficiency of the package.
    Detergent additive package means any chemical compound or 
combination of chemical compounds, including carrier oils, that may be 
added to gasoline, or to post-refinery component blended with gasoline, 
in order to control deposit formation. Carrier oil means an oil that may 
be added to the package to mediate or otherwise enhance the detergent 
chemical's ability to control deposits. A detergent additive package

[[Page 801]]

may contain non-detergent-active components such as corrosion 
inhibitors, antioxidants, metal deactivators, and handling solvents.
    Detergent blender means any person who owns, leases, operates, 
controls or supervises the blending operation of a detergent blending 
facility, or imports detergent-additized gasoline or detergent-additized 
post-refinery component.
    Detergent blending facility means any facility (including, but not 
limited to, a truck or individual storage tank) at which detergent is 
blended with gasoline or post-refinery component.
    Detergent-active components means the components of a detergent 
additive package which act to prevent the formation of deposits, 
including, but not necessarily limited to, the actual detergent chemical 
and any carrier oil (if present) that acts to enhance the detergent's 
ability to control deposits.
    Detergent-additized gasoline (also called detergent gasoline) means 
any gasoline that contains base gasoline and detergent.
    Detergent-additized post-refinery component means any post-refinery 
component that contains detergent.
    Distributor of detergent means any person who transports or stores 
or causes the transportation or storage of detergent at any point 
between its manufacture and its introduction into gasoline.
    Fuel injector deposits (also known as port fuel injector deposits or 
PFID) means the deposits formed on fuel injector(s) during and after 
operation of a gasoline engine, as evaluated by the reduction in the 
gasoline flow rate through the fuel injector(s).
    Gasoline means any fuel for use in motor vehicles and motor vehicle 
engines, including both highway and off-highway vehicles and engines, 
and commonly or commercially known or sold as gasoline. The term 
``gasoline'' is inclusive of base gasoline, detergent gasoline, and base 
gasoline or detergent gasoline that has been commingled with post-
refinery component.
    Hand blending detergent facility means any facility (including, but 
not limited to, a truck or individual storage tank) at which detergent 
is blended with gasoline or post-refinery component by the manual 
addition of detergent, or at which detergent is blended with these 
substances by any means that is not automated.
    Intake valve deposits (IVD) means the deposits formed on the intake 
valve(s) during operation of a gasoline engine, as evaluated by weight.
    Leaded gasoline means gasoline which is produced with the use of any 
lead additive or which contains more than 0.05 gram of lead per gallon 
or more than 0.005 gram of phosphorus per gallon.
    Manufacturer of detergent means any person who owns, leases, 
operates, controls, or supervises a facility that manufactures 
detergent. Pursuant to the definition in 40 CFR 79.2(f), a manufacturer 
of detergent is also considered an additive manufacturer.
    Post-refinery component means any gasoline blending stock or any 
oxygenate which is blended with gasoline subsequent to the gasoline 
refining process.
    Repeatability of a test method means the amount of random error 
which is expected to affect the results obtained for a given test 
substance, when the test is replicated by a single operator in a given 
laboratory within a short period of time, using the same apparatus under 
constant operating conditions. Quantitatively, it is the difference 
between two such single results that would be exceeded in the long run 
in only one out of twenty normal and correct replications of the test 
method.

[59 FR 54706, Nov. 1, 1994, as amended at 61 FR 35356, July 5, 1996]



Sec. 80.141  Interim detergent gasoline program.

    (a) Effective dates of requirements. (1) Until June 30, 1997, the 
products listed in paragraphs (a)(1)(i) through (iii) of this section 
must comply with either the interim program requirements described in 
this section or the certification program requirements described in 
Sec. 80.161. Beginning July 1, 1997, the listed products must comply 
with the requirements in Sec. 80.161. These dates and requirements 
apply to:
    (i) All gasoline sold or transferred to a party who sells or 
transfers gasoline to the ultimate consumer;
    (ii) All additized post-refinery component (PRC); and

[[Page 802]]

    (iii) All detergent additives sold or transferred for use in 
gasoline or PRC for compliance with the requirements of this subpart.
    (2) Until July 31, 1997, all gasoline sold or transferred to the 
ultimate consumer must contain detergent additive(s) meeting either the 
interim requirements of this Sec. 80.141 or the certification program 
requirements of Sec. 80.161. Beginning August 1, 1997, such gasoline 
must contain detergent additive(s) meeting the certification 
requirements of Sec. 80.161.
    (b) Applicability of gasoline and PRC detergency requirement; 
responsible parties. (1) Except as specifically exempted in Sec. 
80.160, the detergency requirements of this subpart apply to all 
gasoline, whether intended for on-highway or nonroad use, including 
conventional, reformulated, oxygenated, and leaded gasolines, as well as 
the gasoline component of fuel mixtures of gasoline and alcohol fuels, 
gasoline used as marine fuel, gasoline service accumulation fuel (as 
described in Sec. 86.113-94(a)(1) of this chapter), the gasoline 
component of fuel mixtures of gasoline and methanol used for service 
accumulation in flexible fuel vehicles (as described in Sec. 86.113-
94(d) of this chapter), gasoline used for factory fill purposes, and all 
additized PRC.
    (2) Pursuant to paragraphs (c) through (f) of this section, 
compliance with these requirements is the responsibility of parties who 
directly or indirectly sell or dispense gasoline to the ultimate 
consumer as well as parties who manufacture, supply, or transfer 
detergent additives or detergent-additized post-refinery components.
    (c) Detergent registration requirements. To be eligible for use by 
fuel manufacturers in complying with the gasoline detergency 
requirements of this subpart, a detergent additive package must be 
registered by its manufacturer under 40 CFR part 79 according to the 
specifications in paragraphs (c) (1) through (3) of this section. After 
evaluating the adequacy of registration data provided by the detergent 
manufacturer pursuant to these requirements, if EPA finds the data to be 
deficient, EPA may disqualify the detergent package for use in complying 
with the gasoline detergency requirements of this subpart, under the 
provisions of paragraph (g) of this section.
    (1) Compositional data. The compositional data supplied to EPA by 
the additive manufacturer for purpose of registering a detergent 
additive package under Sec. 79.21(a) of this chapter must include:
    (i) A complete listing of the components of the detergent additive 
package, using standard chemical nomenclature when possible or providing 
the chemical structure of any component for which the standard chemical 
name is not precise. Polymeric components may be reported as the product 
of other chemical reactants, provided that the supporting data specified 
in Sec. 80.162(b) is also reported for such components.
    (ii) The weight and/or volume percent (as applicable) of each 
component of the package, with variability in these amounts restricted 
according to the provisions of paragraph (c)(2) of this section.
    (iii) For each detergent-active component of the package, 
classification into one of the following designations:
    (A) Polyalkyl amine;
    (B) Polyether amine;
    (C) Polyalkylsuccinimide;
    (D) Polyalkylaminophenol;
    (E) Detergent-active carrier oil; and
    (F) Other detergent-active component.
    (2) Allowable variation in compositional data. (i) A single 
detergent additive registration may contain no variation in the identity 
of any of the detergent-active components identified pursuant to 
paragraph (c)(1)(iii) of this section.
    (ii) A single detergent additive registration may specify a range of 
concentrations for identified detergent-active components, provided 
that, if each such component were present in the detergent additive 
package at the lower bound of its reported range of concentration, the 
minimum recommended concentration reported in accordance with the 
requirements of paragraph (c)(3) of this section would still provide the 
deposit control effectiveness claimed by the detergent registrant.
    (iii) The identity or concentration of non-detergent-active 
components of the detergent additive package may

[[Page 803]]

vary under a single registration, provided that the range of such 
variation is specified in the registration, and that such variability 
does not reduce the deposit control effectiveness of the additive 
package as compared with the level of effectiveness claimed by the 
detergent registrant pursuant to the requirements of paragraph (c)(3) of 
this section.
    (iv) Except as provided in paragraph (c)(2)(v) of this section, 
detergent additive packages which do not satisfy these restrictions must 
be separately registered. EPA may disqualify an additive for use in 
satisfying the requirements of this subpart if EPA determines that the 
variability included within a given detergent additive registration may 
reduce the deposit control effectiveness of the detergent package such 
that it could invalidate the minimum recommended concentration reported 
in accordance with the requirements of paragraph (c)(3) of this section.
    (v) A change in minimum concentration requirements resulting from a 
modification of detergent additive composition shall not require a new 
detergent additive registration or a change in existing registration if:
    (A) The modification is effected by a detergent blender only for its 
own use or for the use of parties which are subsidiaries of, or share 
common ownership with, the blender, and the modified detergent is not 
sold or transferred to other parties; and
    (B) The modification is a dilution of the additive for the purpose 
of ensuring proper detergent flow in cold weather; and
    (C) Gasoline is the only diluting agent used; and
    (D) The diluted detergent is subsequently added to gasoline at a 
rate that attains the detergent's registered minimum recommended 
concentration, taking into account the dilution; and
    (E) EPA is notified, either before or within seven days after the 
dilution action, of the identity of the detergent, the identity of the 
diluting material, the amount or percentage of the dilution, the change 
in treat rate necessitated by the dilution, and the locations and time 
period of diluted detergent usage. The notification shall be sent or 
faxed to the address in Sec. 80.174(c).
    (3) Minimum recommended concentration. (i) The lower boundary of the 
recommended range of concentration for the detergent additive package in 
gasoline, which the additive manufacturer must report pursuant to the 
registration requirements in Sec. 79.21(d) of this chapter, must equal 
or exceed the minimum concentration which the manufacturer has 
determined to be necessary for the control of deposits in the associated 
fuel type, pursuant to paragraph (e) of this section. The minimum 
recommended concentration shall be provided to EPA in units of gallons 
of detergent additive package per thousand gallons of gasoline or PRC, 
reported to four digits. This concentration is the lowest additive 
concentration (LAC) referred to elsewhere in this subpart.
    (ii) The minimum concentration reported in the detergent 
registration according to the provisions of paragraph (c)(3)(i) of this 
section must also be communicated in writing by the additive 
manufacturer to each fuel manufacturer who purchases the subject 
detergent for purpose of compliance with the gasoline detergency 
requirements of this subpart, and to any additive manufacturer who 
purchases the subject additive with the intent of reselling it to a fuel 
manufacturer for this purpose.
    (iii) Pursuant to the requirements of paragraph (e) of this section, 
EPA may require the additive manufacturer to submit data to support the 
deposit control effectiveness of the detergent package at the specified 
minimum effective concentration. EPA may disqualify an additive for use 
in satisfying the requirements of this subpart upon finding that the 
supporting data is inadequate. Manufacturers may be subject to the 
liabilities and enforcement actions in Sec. Sec. 80.156 and 80.159 if 
such a finding is made.
    (iv) Once included in the registration for a detergent additive 
package, the minimum concentration recommended by the detergent 
manufacturer to detergent blenders and other users of the detergent 
additive, pursuant to paragraph (c)(3)(ii) of this section, may not be 
changed without first notifying

[[Page 804]]

EPA. The notification must be sent by certified mail to the address 
specified in Sec. 80.174(b). Changes to the minimum recommended 
concentration must be supported by available test data pursuant to 
paragraph (c)(3)(iii) of this section.
    (v) A manufacturer may use a single set of test data to demonstrate 
the deposit control effectiveness of more than one registered detergent 
additive product, provided that:
    (A) The additive products contain all of the same detergent-active 
components and no detergent-active components other than those contained 
in common; and
    (B) The minimum concentration recommended for the use of each such 
additive product is specified such that, when each additive product is 
mixed in gasoline at the recommended concentration, each of its 
detergent-active components will be present at a final concentration no 
less than the lowest concentration for that component shown to be 
effective by the data available for the tested additive product.
    (d) The rate at which a detergent blender treats gasoline with a 
detergent additive package must be no less than the minimum recommended 
concentration reported for the subject detergent additive pursuant to 
paragraph (c)(3) of this section, except under the following conditions:
    (1) If a detergent blender believes that the minimum treat rate 
recommended by the manufacturer of a detergent additive exceeds the 
amount of detergent actually required for effective deposit control, and 
possesses substantiating data consistent with the guidelines in 
paragraph (e) of this section, then, upon informing EPA in writing of 
these circumstances, the detergent blender may use the detergent at a 
lower concentration.
    (2) The notification to EPA must clearly specify the name of the 
detergent product and its manufacturer, the concentration recommended by 
the detergent manufacturer, and the lower concentration which the 
detergent blender intends to use. The notification must also attest that 
data are available to substantiate the deposit control effectiveness of 
the detergent at the intended lower concentration. The notification must 
be sent by certified mail to the address specified in Sec. 80.174(b).
    (3) At its discretion, EPA may require that the detergent blender 
submit the test data purported to substantiate the claimed effectiveness 
of the lower concentration of the detergent additive. EPA may also 
require the manufacturer of the subject detergent additive to submit 
test data substantiating the minimum recommended concentration specified 
in the detergent additive registration. In either case, EPA will send a 
letter to the appropriate party, and the supporting data will be due to 
EPA within 30 days of receipt of EPA's letter.
    (i) If the detergent blender fails to submit the required supporting 
data to EPA in the allotted time period, or if EPA judges the submitted 
data to be inadequate to support the detergent blender's claim that the 
lower concentration provides a level of deposit control consistent with 
the requirements of this section, then EPA will disapprove the use of 
the detergent at the lower concentration. Further, the detergent blender 
may be subject to applicable liabilities and penalties pursuant to 
Sec. Sec. 80.156 and 80.159 for any gasoline or PRC it has additized at 
the lower concentration.
    (ii) If the detergent manufacturer fails to submit the required test 
data to EPA within the allotted time period, EPA will proceed on the 
assumption that data are not available to substantiate the minimum 
recommended concentration specified in the detergent registration, and 
the subject additive may be disqualified for use in complying with the 
requirements of this subpart, pursuant to the procedures in paragraph 
(g) of this section. The detergent manufacturer may also be subject to 
applicable liabilities and penalties pursuant to Sec. Sec. 80.156 and 
80.159.
    (iii) If both parties submit the required information, EPA will 
evaluate the quality and results of both sets of test data in relation 
to each other and to industry-consensus test practices and standards, in 
a manner consistent with the guidelines described in paragraph (e) of 
this section. EPA will approve or disapprove the use of the detergent at 
the lower concentration, and will inform both the detergent blender

[[Page 805]]

and the detergent manufacturer of the results of its analysis within 60 
days of receipt of both sets of data.
    (e) Demonstration of deposit control efficiency. At its discretion, 
EPA may require a detergent additive registrant to provide test data to 
support the deposit control effectiveness of a detergent at the minimum 
concentration recommended, pursuant to paragraph (c)(3) of this section 
and Sec. 79.21(d) of this chapter. The required supporting data must be 
submitted to EPA within 30 days of receipt of EPA's request. EPA will 
notify the submitter, within 60 days after receiving the supporting 
data, whether the data is adequate to support the deposit control 
efficiency claimed. Subject to the procedures specified in paragraph (g) 
of this section, if the supporting data are not submitted or if EPA 
finds the data insufficient, the detergent may be disqualified for use 
by fuel manufacturers in complying with the requirements of this 
subpart. EPA will use the following guidelines in determining the 
adequacy of the supporting data:
    (1) CARB-based supporting test data. For detergent additives which 
are certified by the California Air Resources Board (CARB) for use in 
the State of California (pursuant to Title 13, section 2257 of the 
California Code of Regulations), the CARB certification data constitutes 
adequate support of the detergent's effectiveness under this section, 
with the exception that CARB detergent certification data specific to 
California Phase II reformulated gasoline (pursuant to Title 13, Chapter 
5, Article 1, Subarticle 2, California Code of Regulations, Standards 
for Gasoline Sold Beginning March 1, 1996) will not be considered 
adequate support for detergent effectiveness in gasolines that do not 
conform to the compositional specifications for California's Phase II 
reformulated gasoline. For CARB-based supporting data to be used to 
demonstrate detergent performance, the minimum recommended concentration 
reported in the detergent additive registration must be no less than the 
concentration of the detergent-active components reported in the subject 
CARB detergent certification.
    (2) EPA will evaluate the adequacy of other supporting data 
according to the following guidelines:
    (i) Test fuel guidelines.
    (A) The gasoline used in the supporting tests must contain the 
detergent-active components of the subject detergent additive package in 
an amount which corresponds to the minimum recommended concentrations 
recorded in the respective detergent registration, or less than this 
amount.
    (B) The test fuels must not contain any detergent-active components 
other than those recorded in the subject detergent registration.
    (C) The test fuels used must be reasonably typical of in-use fuels 
in their tendency to form deposits. Test fuel taken directly from 
commercial refinery production stock is acceptable. Specially refined 
low-deposit-forming fuels such as indolene are not acceptable. Other 
specially blended test fuels will be evaluated by EPA for acceptability 
based on the extent to which such fuels adequately represent the 
deposit-forming tendency of typical (average) in-use fuels, as reflected 
in the levels of the following fuel parameters: sulfur content, aromatic 
content, olefin content, T-90, and oxygenate content.
    (D) The composition of the blended test fuel(s) used in carburetor 
deposit control testing, conducted to support the claimed effectiveness 
of detergents used in leaded gasoline, should be reasonably typical of 
in-use gasoline in its tendency to form carburetor deposits (or more 
severe than typical in-use fuels) as defined by the olefin and sulfur 
content. Test data using leaded fuels is preferred for this purpose, but 
data collected using unleaded fuels may also be acceptable provided that 
some correlation with additive performance in leaded fuels is available.
    (ii) Test procedure guidelines.
    (A) To be acceptable, test data submitted to support the deposit 
control effectiveness of a detergent additive must derive from testing 
conducted in conformity with good engineering practices.
    (B) For demonstration of fuel injector and intake valve deposit 
control performance, the tests specified in Sec. Sec. 80.165, or other 
vehicle-based tests

[[Page 806]]

using generally accepted industry procedures and standards, are 
preferred. Engine-based tests may also be acceptable, assuming a 
reasonable correlation with vehicle-based tests and standards can be 
demonstrated. Bench test data may be acceptable to demonstrate fuel 
injector deposit control performance, assuming the results can be 
correlated with vehicle- or engine-based tests and standards. Bench 
testing will not be considered acceptable for demonstration of IVD 
control performance. Examples of acceptable test procedures are 
contained in the following references:
    (1) Intake Valve Deposit Test Procedures:
    (i) ``Intake Valve Deposits--Fuel Detergency Requirements 
Revisited'', Bill Bitting et al., Society of Automotive Engineers, SAE 
Technical Paper No. 872117, 1987.\1\
---------------------------------------------------------------------------

    \1\ Society of Automotive Engineers (SAE), 400 Commonwealth Drive, 
Warrendale, PA 15096-0001.
---------------------------------------------------------------------------

    (ii) ``BMW--10,000 Miles Intake Valve Test Procedure'', March 1, 
1991, Section 2257, Title 13, California Code of Regulations.
---------------------------------------------------------------------------

    \2\ [Reserved]
---------------------------------------------------------------------------

    (iii)
    (iv) ``Effect on Intake Valve Deposits of Ethanol and Additives 
Common to the Available Ethanol Supply'', Clifford Shilbolm et al., SAE 
Technical Paper Series No. 902109, 1990.
    (2) Fuel Injector Deposit Test Procedures:
    (i) ``Test Method for Evaluating Port Fuel Injector (PFI) Deposits 
in Vehicle Engines'', March 1, 1991, Section 2257, Title 13, California 
Code of Regulations.
    (ii) ``A Vehicle Test Technique for Studying Port Fuel Injector 
Deposits--A Coordinating Research Council Program'', Robert Tupa et al., 
SAE Technical paper No. 890213, 1989.
    (iii) ``The Effects of Fuel Composition and Additives on Multiport 
Fuel Injector Deposits'', Jack Benson et al., SAE Technical Paper Series 
No. 861533, 1986.
    (iv) ``Injector Deposits--The Tip of Intake System Deposit 
Problems'', Brian Taneguchi, et al., SAE Technical Paper Series No. 
861534, 1986.
    (C) For demonstration of carburetor deposit control performance, any 
generally accepted vehicle, engine, or bench test procedure for 
carburetor deposit control will be considered adequate. Port and 
throttle body fuel injector deposit control test data will also be 
considered to be adequate demonstration of an additive's ability to 
control carburetor deposits. Examples of acceptable test procedures for 
demonstration of carburetor deposit control, in addition to the fuel 
injector test procedures listed above in paragraph (e)(2)(ii)(B)(2) of 
this section, are contained in the following references:
    (1) ``Fuel Injector, Intake Valve, and Carburetor Detergency 
Performance of Gasoline Additives'', C.H. Jewitt et al., SAE Technical 
Paper No. 872114, 1987.
    (2) ``Carburetor Cleanliness Test Procedure, State-of-the-Art 
Summary, Report: 1973-1981'', Coordinating Research Council, CRC Report 
No. 529.\3\
---------------------------------------------------------------------------

    \3\ Coordinating Research Council Inc. (CRC), 219 perimeter Center 
Parking, Atlanta, Georgia, 30346.
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    (f) Detergent identification test procedure. (1) At its discretion, 
EPA may require the additive registrant to submit an analytical 
procedure capable of identifying the detergent additive in its pure 
state. The test procedure will be due to EPA within 30 days of the 
registrant's receipt of the request. Subject to the provisions in 
paragraph (g) of this section, if the registrant fails to submit an 
analytical procedure, or if EPA judges a submitted procedure to be 
inadequate, EPA may deny or withdraw the detergent's eligibility to be 
used to satisfy the detergency requirements in this section.
    (2) The analytical procedure submitted by the registrant must be 
able to both qualitatively and quantitatively identify each component of 
the detergent additive package. To be acceptable, the procedure must 
provide results that conform to reasonable and customary standards of 
repeatability and reproducibility, and reasonable and customary limits 
of detection and accuracy, for the type of test in question.
    (3) A fourier transform infrared spectroscopy (FTIR)-based 
procedure, including an actual infrared spectrum of the detergent 
additive package and each component part of the detergent

[[Page 807]]

package obtained from this test method, is preferred.
    (g) Disqualification of a detergent additive package. (1) When EPA 
makes a preliminary determination that a detergent additive registrant 
has failed to comply with the requirements of paragraph (c), (d)(3)(ii), 
(e), or (f) of this section, either by failing to submit required 
information for a subject detergent additive or by submitting 
information which EPA deems inadequate, EPA shall notify the additive 
registrant by certified mail, return receipt requested, setting forth 
the basis for that determination and informing the registrant that the 
detergent may lose its eligibility to be used to comply with the 
detergency requirements of this section.
    (2) If EPA determines that the detergent registration was created by 
fraud or other misconduct, such as a negligent disregard for the 
truthfulness or accuracy of the required information or of the 
application, the detergent registration will be considered void ab 
initio and the revocation of qualification will be retroactive to 
January 1, 1995 or the date on which the additive product was first 
registered, whichever is later.
    (3) The registrant will be afforded 60 days from the date of receipt 
of the notice of intent of detergent disqualification 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 disqualification. If the registrant does not respond in writing 
within 60 days from the date of receipt of the notice of intent of 
disqualification, the detergent disqualification shall become final by 
operation of law and the Administrator shall notify the registrant of 
such disqualification. If the registrant responds in writing within 60 
days from the date of receipt of the notice of intent to disqualify, the 
Administrator shall review and consider all comments submitted by the 
registrant before taking final action concerning the proposed 
disqualification. All correspondence regarding a disqualification must 
be sent to the address specified in Sec. 80.174(b).
    (4) As part of a written response to a notice of intent to 
disqualify, 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 90 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 disqualification. 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.
    (5) If a registrant who has received a notice of intent to 
disqualify submits a timely written response, and the Administrator 
decides after reviewing the response and the transcript of any informal 
hearing to disqualify the detergent for use in complying with the 
requirements of this subpart, the Administrator shall issue a final 
disqualification order, forward a copy of the disqualification order to 
the registrant by certified mail, and promptly publish the 
disqualification order in the Federal Register. Any disqualification 
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.
    (6) Upon making a final decision to disqualify a detergent additive 
package pursuant to this paragraph (g), EPA shall inform all fuel 
manufacturers and secondary additive manufacturers whose product 
registrations report the potential use of the disqualified detergent 
that such detergent is no longer eligible for compliance with the 
requirements of this subpart. Such fuel manufacturers and secondary 
additive manufacturers shall have 45 days in

[[Page 808]]

which to stop using the ineligible detergent additive package and 
substitute an eligible detergent additive. When applicable, EPA shall 
also notify such parties that the detergent registration had been 
created by fraud or other misconduct, pursuant to paragraph (g)(2) of 
this section.

[59 FR 54706, Nov. 1, 1994, as amended at 61 FR 35356, July 5, 1996; 61 
FR 58747, Nov. 18, 1996]



Sec. Sec. 80.142-80.154  [Reserved]



Sec. 80.155  Interim detergent program controls and prohibitions.

    (a)(1) No person shall sell, offer for sale, dispense, supply, offer 
for supply, transport, or cause the transportation of gasoline to the 
ultimate consumer for use in motor vehicles or in any off-road engines 
(except as provided in Sec. 80.160), or to a gasoline retailer or 
wholesale purchaser-consumer, and no person shall detergent-additize 
gasoline, unless such gasoline is additized in conformity with the 
requirements of Sec. 80.141. No person shall cause the presence of any 
gasoline in the gasoline distribution system unless such gasoline is 
additized in conformity with the requirements of Sec. 80.141.
    (2) Gasoline has been additized in conformity with the requirements 
of Sec. 80.141 when the detergent component satisfies the requirements 
of Sec. 80.141 and when:
    (i) The gasoline has been additized in conformity with the detergent 
composition and purpose-in-use specifications of an applicable detergent 
registered under 40 CFR part 79, and in accordance with at least the 
minimum concentration specifications of that detergent as registered 
under 40 CFR part 79 or as otherwise provided under Sec. 80.141(d); or
    (ii) The gasoline is composed of two or more commingled gasolines 
and each component gasoline has been additized in conformity with the 
detergent composition and purpose-in-use specifications of a detergent 
registered under 40 CFR part 79, and in accordance with at least the 
minimum concentration specifications of that detergent as registered 
under 40 CFR part 79 or as otherwise provided under Sec. 80.141(d); or
    (iii) The gasoline is composed of a gasoline commingled with a post-
refinery component (PRC), and both of these components have been 
additized in conformity with the detergent composition and use 
specifications of a detergent registered under 40 CFR part 79, and in 
accordance with at least the minimum concentration specifications of 
that detergent as registered under 40 CFR part 79 or as otherwise 
provided under Sec. 80.141(d).
    (b) No person shall blend detergent into gasoline or PRC unless such 
person complies with the volumetric additive reconciliation requirements 
of Sec. 80.157.
    (c) No person shall sell, offer for sale, dispense, supply, offer 
for supply, store, transport, or cause the transportation of any 
gasoline, detergent, or detergent-additized PRC unless the product 
transfer document for the gasoline, detergent or detergent-additized PRC 
complies with the requirements of Sec. 80.158.
    (d) No person shall refine, import, manufacture, sell, offer for 
sale, dispense, supply, offer for supply, store, transport, or cause the 
transportation of any detergent that is to be used as a component of 
detergent-additized gasoline or detergent-additized PRC, unless such 
detergent conforms with the composition specifications of a detergent 
registered under 40 CFR part 79 and the detergent otherwise complies 
with the requirements of Sec. 80.141. No person shall cause the 
presence of any detergent in the detergent, PRC, or gasoline 
distribution systems unless such detergent complies with the 
requirements of Sec. 80.141.
    (e)(1) No person shall sell, offer for sale, dispense, supply, offer 
for supply, transport, or cause the transportation of detergent-
additized PRC, unless the PRC has been additized in conformity with the 
requirements of Sec. 80.141. No person shall cause the presence in the 
PRC or gasoline distribution systems of any detergent-additized PRC that 
fails to conform to the requirements of Sec. 80.141.
    (2) PRC has been additized in conformity with the requirements of 
Sec. 80.141 when the detergent component satisfies the requirements of 
Sec. 80.141 and:

[[Page 809]]

    (i) The PRC has been additized in accordance with the detergent 
composition and use specifications of a detergent registered under 40 
CFR part 79, and in accordance with at least the minimum concentration 
specifications of that detergent as registered under 40 CFR part 79 or 
as otherwise provided under Sec. 80.141(d); or
    (ii) The PRC is composed of two or more commingled PRCs, and each 
component has been additized in accordance with the detergent 
composition and use specifications of a detergent registered under 49 
CFR part 79, and in accordance with at least the minimum concentration 
specifications of that detergent as registered under 40 CFR part 79 or 
as otherwise provided under Sec. 80.141(d).

[61 FR 35358, July 5, 1996]



Sec. 80.156  Liability for violations of the interim detergent 
program controls and prohibitions.

    (a) Persons liable--(1) Gasoline non-conformity. Where gasoline 
contained in any storage tank at any facility owned, leased, operated, 
controlled or supervised by any gasoline refiner, importer, carrier, 
distributor, reseller, retailer, wholesale purchaser-consumer, oxygenate 
blender, or detergent blender, is found in violation of any of the 
prohibitions specified in Sec. 80.155(a), the following persons shall 
be deemed in violation:
    (i) Each gasoline refiner, importer, carrier, distributor, reseller, 
retailer, wholesale purchaser-consumer, oxygenate blender, or detergent 
blender, who owns, leases, operates, controls or supervises the facility 
(including, but not limited to, a truck or individual storage tank) 
where the violation is found;
    (ii) Each gasoline refiner, importer, distributor, reseller, 
retailer, wholesale purchaser-consumer, oxygenate blender, detergent 
manufacturer, distributor, or blender, who refined, imported, 
manufactured, sold, offered for sale, dispensed, supplied, offered for 
supply, stored, detergent additized, transported, or caused the 
transportation of the detergent-additized gasoline (or the base gasoline 
component, the detergent component, or the detergent-additized post-
refinery component of the gasoline) that is in violation, and each such 
party that caused the gasoline that is in violation to be present in the 
gasoline distribution system; and
    (iii) Each gasoline carrier who dispensed, supplied, stored, or 
transported any gasoline in the storage tank containing gasoline found 
to be in violation, and each detergent carrier who dispensed, supplied, 
stored, or transported the detergent component of any post-refinery 
component or gasoline in the storage tank containing gasoline found to 
be in violation, provided that the EPA demonstrates, by reasonably 
specific showings by direct or circumstantial evidence, that the 
gasoline or detergent carrier caused the violation.
    (2) Post-refinery component non-conformity. Where detergent-
additized PRC contained in any storage tank at any facility owned, 
leased, operated, controlled or supervised by any gasoline refiner, 
importer, carrier, distributor, reseller, retailer, wholesale purchaser-
consumer, oxygenate blender, detergent manufacturer, carrier, 
distributor, or blender, is found in violation of the prohibitions 
specified in Sec. 80.155(e), the following persons shall be deemed in 
violation:
    (i) Each gasoline refiner, importer, carrier, distributor, reseller, 
retailer, wholesale-purchaser consumer, oxygenate blender, detergent 
manufacturer, carrier, distributor, or blender, who owns, leases, 
operates, controls or supervises the facility (including, but not 
limited to, a truck or individual storage tank) where the violation is 
found;
    (ii) Each gasoline refiner, importer, distributor, reseller, 
retailer, wholesale-purchaser consumer, oxygenate blender, detergent 
manufacturer, distributor, or blender, who sold, offered for sale, 
dispensed, supplied, offered for supply, stored, detergent additized, 
transported, or caused the transportation of the detergent-additized PRC 
(or the detergent component of the PRC) that is in violation, and each 
such party that caused the PRC that is in violation to be present in the 
PRC or gasoline distribution systems; and
    (iii) Each carrier who dispensed, supplied, stored, or transported 
any detergent-additized post-refinery component

[[Page 810]]

in the storage tank containing post-refinery component in violation, and 
each detergent carrier who dispensed, supplied, stored, or transported 
the detergent component of any detergent-additized post-refinery 
component which is in the storage tank containing detergent-additized 
post-refinery component found to be in violation, provided that the EPA 
demonstrates by reasonably specific showings by direct or circumstantial 
evidence, that the gasoline or detergent carrier caused the violation.
    (3) Detergent non-conformity. Where the detergent (prior to 
additization) contained in any storage tank or container found at any 
facility owned, leased, operated, controlled or supervised by any 
gasoline refiner, importer, carrier, distributor, reseller, retailer, 
wholesale purchaser-consumer, oxygenate blender, detergent manufacturer, 
carrier, distributor, or blender, is found in violation of the 
prohibitions specified in Sec. 80.155(d), the following persons shall 
be deemed in violation:
    (i) Each gasoline refiner, importer, carrier, distributor, reseller, 
retailer, wholesale-purchaser consumer, oxygenate blender, detergent 
manufacturer, carrier, distributor, or blender, who owns, leases, 
operates, controls or supervises the facility (including, but not 
limited to, a truck or individual storage tank) where the violation is 
found;
    (ii) Each gasoline refiner, importer, distributor, reseller, 
retailer, wholesale purchaser-consumer, oxygenate blender, detergent 
manufacturer, distributor, or blender, who sold, offered for sale, 
dispensed, supplied, offered for supply, stored, transported, or caused 
the transportation of the detergent that is in violation, and each such 
party that caused the detergent that is in violation to be present in 
the detergent, gasoline, or PRC distribution systems; and
    (iii) Each gasoline or detergent carrier who dispensed, supplied, 
stored, or transported any detergent which is in the storage tank or 
container containing detergent found to be in violation, providing that 
EPA demonstrates, by reasonably specific showings by direct or 
circumstantial evidence, that the gasoline or detergent carrier caused 
the violation.
    (4) Volumetric additive reconciliation. Where a violation of the 
volumetric additive reconciliation requirements established by Sec. 
80.155(b) has occurred, the following persons shall be deemed in 
violation:
    (i) Each detergent blender who owns, leases, operates, controls or 
supervises the facility (including, but not limited to, a truck or 
individual storage tank) where the violation has occurred; and
    (ii) Each gasoline refiner, importer, carrier, distributor, 
reseller, retailer, wholesale purchaser-consumer, or oxygenate blender, 
and each detergent manufacturer, carrier, distributor, or blender, who 
refined, imported, manufactured, sold, offered for sale, dispensed, 
supplied, offered for supply, stored, transported, or caused the 
transportation of the detergent-additized gasoline, the base gasoline 
component, the detergent component, or the detergent-additized post-
refinery component, of the gasoline that is in violation, provided that 
the EPA demonstrates, by reasonably specific showings by direct or 
circumstantial evidence, that such person caused the violation.
    (5) Product transfer document. Where a violation of Sec. 80.155(c) 
is found at a facility owned, leased, operated, controlled, or 
supervised by any gasoline refiner, importer, carrier, distributor, 
reseller, retailer, wholesale purchaser-consumer, oxygenate blender, 
detergent manufacturer, carrier, distributor, or blender, the following 
persons shall be deemed in violation: each gasoline refiner, importer, 
carrier, distributor, reseller, retailer, wholesale-purchaser consumer, 
oxygenate blender, detergent manufacturer, carrier, distributor, or 
blender, who owns, leases, operates, control or supervises the facility 
(including, but not limited to, a truck or individual storage tank) 
where the violation is found.
    (b) Branded refiner vicarious liability. Where any violation of the 
prohibitions specified in Sec. 80.155 has occurred, with the exception 
of violations of Sec. 80.155(c), a refiner will also be deemed liable 
for violations occurring at a facility operating under such refiner's 
corporate, trade, or brand name or that of any of its marketing 
subsidiaries. For purposes of this section, the word facility

[[Page 811]]

includes, but is not limited to, a truck or individual storage tank.
    (c) Defenses. (1) In any case in which a gasoline refiner, importer, 
distributor, carrier, reseller, retailer, wholesale-purchaser consumer, 
oxygenate blender, detergent distributor, carrier, or blender, is in 
violation of any of the prohibitions of Sec. 80.155, pursuant to 
paragraphs (a) or (b) of this section as applicable, the regulated party 
shall be deemed not in violation if it can demonstrate:
    (i) That the violation was not caused by the regulated party or its 
employee or agent (unless otherwise provided in this paragraph (c));
    (ii) That product transfer documents account for the gasoline, 
detergent, or detergent-additized post-refinery component in violation 
and indicate that the gasoline, detergent, or detergent-additized post-
refinery component satisfied relevant requirements when it left their 
control; and
    (iii) That the party has fulfilled the requirements of paragraphs 
(c) (2) or (3) of this section, as applicable.
    (2) Branded refiner. (i) Where a branded refiner, pursuant to 
paragraph (b) of this section, is in violation of any of the 
prohibitions of Sec. 80.155 as a result of violations occurring at a 
facility (including, but not limited to, a truck or individual storage 
tank) which is operating under the corporate, trade or brand name of a 
refiner or that of any of its marketing subsidiaries, the refiner shall 
be deemed not in violation if it can demonstrate, in addition to the 
defense requirements stated in paragraph (c)(1) of this section, that 
the violation was caused by:
    (A) An act in violation of law (other than these regulations), or an 
act of sabotage or vandalism, whether or not such acts are violations of 
law in the jurisdiction where the violation of the prohibitions of Sec. 
80.155 occurred; or
    (B) The action of any gasoline refiner, importer, reseller, 
distributor, oxygenate blender, detergent manufacturer, distributor, 
blender, or retailer or wholesale purchaser-consumer supplied by any of 
these persons, in violation of a contractual undertaking imposed by the 
refiner designed to prevent such action, and despite the implementation 
of an oversight program, including, but not limited to, periodic review 
of product transfer documents by the refiner to ensure compliance with 
such contractual obligation; or
    (C) The action of any gasoline or detergent carrier, or other 
gasoline or detergent distributor not subject to a contract with the 
refiner but engaged by the refiner for transportation of gasoline, post-
refinery component, or detergent, to a gasoline or detergent 
distributor, oxygenate blender, detergent blender, gasoline retailer or 
wholesale purchaser consumer, despite specification or inspection of 
procedures or equipment by the refiner which are reasonably calculated 
to prevent such action.
    (ii) In this paragraph (c)(2), to show that the violation ``was 
caused'' by any of the specified actions, the party must demonstrate by 
reasonably specific showings, by direct or circumstantial evidence, that 
the violation was caused or must have been caused by another.
    (3) Detergent blender. In any case in which a detergent blender is 
liable for violating any of the prohibitions of Sec. 80.155, the 
detergent blender shall not be deemed in violation if it can 
demonstrate, in addition to the defense requirements stated in paragraph 
(c)(1) of this section, the following:
    (i) That it obtained or supplied, as appropriate, prior to the 
detergent blending, accurate written instructions from the detergent 
manufacturer or other party with knowledge of such instructions, 
specifying the detergent's minimum recommended concentration (lowest 
additive concentration) pursuant to Sec. 80.141(c)(3) and, if 
applicable, the limitations of this concentration for use in leaded 
product.
    (ii) That it has implemented a quality assurance program that 
includes, but is not limited to, a periodic review of its supporting 
product transfer and volume measurement documents to confirm the 
correctness of its product transfer and volumetric additive 
reconciliation documents created for all products it additized.
    (4) Detergent manufacturer--(i) Presumptive liability affirmative 
defense. Notwithstanding the provisions of paragraph (c)(1) of this 
section, in any case in which a detergent manufacturer is liable for 
violating any of the

[[Page 812]]

prohibitions of Sec. 80.155, the detergent manufacturer shall be deemed 
not in violation if it can demonstrate each of the following:
    (A) Product transfer documents which account for the detergent 
component of the product in violation and which indicate that such 
detergent satisfied all relevant requirements when it left the detergent 
manufacturer's control; and
    (B) Written blending instructions which, pursuant to Sec. 
80.141(c)(3)(ii), were supplied by the detergent manufacturer to its 
customer who purchased or obtained from the manufacturer the detergent 
component of the product determined to be in violation. The written 
blending instructions must have been supplied by the manufacturer prior 
to the customer's use or sale of the detergent. The instructions must 
accurately identify the minimum recommended concentration (lowest 
additive concentration) specified in the detergent's 40 CFR part 79 
registration, and must also accurately identify if the detergent, at 
that concentration, is only registered as effective for use in leaded 
gasoline.
    (C) If the detergent batch used in the noncomplying product was 
produced less than one year before the manufacturer was notified by EPA 
of the possible violation, then the manufacturer must provide FTIR or 
other test results for the batch of detergent used in the noncomplying 
product, performed in accordance with the detergent testing procedure 
submitted by the manufacturer, or available for submission, pursuant to 
Sec. 80.141(f).
    (1) The analysis may have been conducted on the subject detergent 
batch at the time it was manufactured, or may be conducted on a sample 
of that batch which the manufacturer retained for such purpose at the 
time the batch was manufactured.
    (2) The test results must accurately establish that, when it left 
the manufacturer's control, the detergent component of the product 
determined to be in violation was in conformity with the chemical 
composition and concentration specifications reported pursuant to Sec. 
80.141(c)(1);
    (D) If the detergent batch used in the noncomplying product was 
produced more than one year prior to the manufacturer's notification by 
EPA of the possible violation, then the manufacturer must provide 
either:
    (1) Test results for the batch in question as specified in the 
paragraph (c)(4)(i)(C) of this section; or
    (2) The following materials:
    (i) Documentation of the measured viscosity, density, and basic 
nitrogen content of the detergent batch in question, or any other such 
physical parameters which the manufacturer normally uses to ensure 
production quality control, which establishes conformity with the 
manufacturer's quality control standards for such parameters; and
    (ii) If the detergent registration identifies polymeric component(s) 
of the detergent package as the product(s) of other chemical reactants, 
documentation that the reagents used to synthesize the detergent batch 
in question were the same as those specified in the registration and 
that they met the manufacturer's normal acceptance criteria for such 
reagents, reported pursuant to Sec. 80.162(b)(1).
    (ii) Detergent manufacturer causation liability. In any case in 
which a detergent manufacturer is liable for a violation of Sec. 
80.155, and the manufacturer establishes an affirmative defense to such 
liability pursuant to paragraph (c)(4)(i) of this section, the detergent 
manufacturer will nonetheless be deemed liable for the violation of 
Sec. 80.155 if EPA can demonstrate, by reasonably specific showings by 
direct or circumstantial evidence, that the detergent manufacturer 
caused the violation.
    (5) Defense against liability where more than one party may be 
liable for VAR violations. In any case in which a party is presumptively 
or vicariously liable for a violation of Sec. 80.155 due to a failure 
to meet the VAR requirements Sec. 80.157, except for the VAR record 
requirements pursuant to Sec. 80.157(g), such party shall not be deemed 
liable if it can establish the following:
    (i) Prior to the violation it had entered into a written contract 
with another potentially liable detergent blender party (``the assuming 
party''), under which that other party assumed legal responsibility for 
fulfilling the

[[Page 813]]

VAR requirement that had been violated;
    (ii) The contract included reasonable oversight provisions to ensure 
that the assuming party fulfilled its VAR responsibilities (including, 
but not limited to, periodic review of VAR records) and the oversight 
provision was actually implemented by the party raising the defense;
    (iii) The assuming party is fiscally sound and able to pay its 
penalty for the VAR violation; and
    (iv) The employees or agents of the party raising the defense did 
not cause the violation.
    (6) Defense to liability for gasoline non-conformity violations 
caused solely by the addition of misadditized ethanol or other PRC to 
the gasoline. In any case in which a party is presumptively or 
vicariously liable for a gasoline non-conformity violation of Sec. 
80.155(a) caused solely by another party's addition of misadditized 
ethanol or other PRC to the gasoline, the former party shall not be 
deemed liable for the violation provided that it can establish that is 
has fulfilled the requirements of paragraphs (c)(1)(i) and (ii) of this 
section.
    (7) Detergent tank transitioning defenses. The commingling of two 
detergents in the same detergent storage tank will not be deemed to 
violate or cause violations of any of the provisions of this subpart, 
provided the following conditions are met:
    (i) The commingling must occur during a legitimate detergent 
transitioning event, i.e., a shift from the use of one detergent to 
another through the delivery of the new detergent into the same tank 
that contains the original detergent; and
    (ii) If the new detergent is restricted to use in leaded gasoline, 
then such restriction must be applied to the combined detergents; and
    (iii) The commingling event must be documented, either on the VAR 
formula record or on attached supporting records; and
    (iv) Notwithstanding any contrary provisions in Sec. 80.157, a VAR 
formula record must be created for the combined detergents. The VAR 
compliance period must begin no later than the time of the commingling 
event. However, at the blender's option, the compliance period may begin 
earlier, thus including use of the uncombined original detergent within 
the same period, provided that the 31-day limitation pursuant to Sec. 
80.157(a)(6) is not exceeded; and
    (v) The VAR formula record must also satisfy the requirements in one 
of the following paragraphs (c)(7)(v)(A) through (C) of this section, 
whichever applies to the commingling event. If neither paragraph 
(c)(7)(v)(A) nor (B) of this section initially applies, then the blender 
may drain and subsequently redeliver the original detergent into the 
tank in restricted amounts, in order to meet the conditions of paragraph 
(c)(7)(v)(A) or (B) of this section. Otherwise, the blender must comply 
with paragraph (c)(7)(v)(C) of this section.
    (A) If both detergents have the same LAC, and the original detergent 
accounts for no more than 20 percent of the tank's total delivered 
volume after addition of the new detergent, then the VAR formula record 
is required to identify only the use of the new detergent.
    (B) If the two detergents have different LACs and the original 
detergent accounts for 10 percent or less of the tank's total delivered 
volume after addition of the new detergent, then the VAR formula record 
is required to identify only the use of the new detergent, and must 
attain the LAC of the new detergent. If the original detergent's LAC is 
greater than that of the new detergent, then the compliance period may 
begin earlier than the date of the commingling event (pursuant to 
paragraph (c)(7)(iv) of this section) only if the original detergent 
does not exceed 10 percent of the total detergent used during the 
compliance period.
    (C) If neither of the preceding paragraphs (c)(7)(v)(A) or (B) of 
this section applies, then the VAR formula record must identify both of 
the commingled detergents, and must use and attain the higher LAC of the 
two detergents. Once the commingled detergent has been depleted by an 
amount equal to the volume of the original detergent in the tank at the 
time the new detergent was added, subsequent VAR formula records must 
identify and use the LAC of only the new detergent.

[[Page 814]]

    (8) Defense to liability for noncompliance with leaded-only use 
restrictions. A party shall not be deemed liable for violations of Sec. 
80.155(a) or (e) caused solely by the additization or use of gasoline or 
PRC in violation of leaded-only use restrictions, provided that the 
conditions specified in Sec. 80.169(c)(9) are met.
    (d) Detergent manufacturer causation liability. In any case in which 
a detergent manufacturer is liable for a violation of Sec. 80.155 
pursuant to paragraph (a) of this section, and the manufacturer 
establishes affirmative defense to such liability pursuant to paragraph 
(c) of this section, the detergent manufacturer will be liable for the 
violation of Sec. 80.155 pursuant to this paragraph (d) of this 
section, provided that EPA can demonstrate, by reasonably specific 
showings by direct or circumstantial evidence, that the detergent 
manufacturer caused the violation.

[59 FR 54706, Nov. 1, 1994, as amended at 61 FR 35358, July 5, 1996]



Sec. 80.157  Volumetric additive reconciliation (``VAR''), equipment
calibration, and recordkeeping requirements.

    This section contains requirements for automated detergent blending 
facilities and hand-blending detergent facilities. All gasolines and all 
PRC intended for use in gasoline must be additized, unless otherwise 
noted in supporting VAR records, and must be accounted for in VAR 
records. The VAR reconciliation standard is attained under this section 
when the actual concentration of detergent used per VAR formula record 
equals or exceeds the lowest additive concentration (LAC) specified for 
that detergent pursuant to Sec. 80.141(c)(3), or, if appropriate, under 
Sec. 80.141(d). A separate VAR formula record must be created for 
leaded gasoline additized with a detergent registered for use only with 
leaded gasoline, or used at a concentration that is registered as 
effective for leaded gasoline only. Detergent so used must be accurately 
and separately measured, either through the use of a separate storage 
tank, a separate meter, or some other measurement system that is able to 
accurately distinguish its use. Recorded volumes of gasoline, detergent, 
and PRC must be expressed to the nearest gallon (or smaller units), 
except that detergent volumes of five gallons or less must be expressed 
to the nearest tenth of a gallon (or smaller units). However, if the 
blender's equipment cannot accurately measure to the nearest tenth of a 
gallon, then such volumes must be rounded downward to the next lower 
gallon. PRC included in the reconciliation must be identified. Each VAR 
formula record must also contain the following information:
    (a) Automated blending facilities. In the case of an automated 
detergent blending facility, for each VAR period, for each detergent 
storage system and each detergent in that storage system, the following 
must be recorded:
    (1) The manufacturer and commercial identifying name of the 
detergent additive package being reconciled, and the LAC specified in 
the detergent registration for use with the applicable type of gasoline 
(i.e., unleaded or leaded). The LAC must be expressed in terms of 
gallons of detergent per thousand gallons of gasoline or PRC, and 
expressed to four digits. If the specified LAC is only effective for use 
with leaded gasoline, the record must so indicate. If the detergent 
storage system which is the subject of the VAR formula record is a 
proprietary system under the control of a customer, this fact must be 
indicated on the record.
    (2) The total volume of detergent blended into gasoline and PRC, in 
accordance with one of the following paragraphs, as applicable.
    (i) For a facility which uses in-line meters to measure detergent 
usage, the total volume of detergent measured, together with supporting 
data which includes one of the following: the beginning and ending meter 
readings for each meter being measured, the metered batch volume 
measurements for each meter being measured, or other comparable metered 
measurements. The supporting data may be supplied on the VAR formula 
record or in the form of computer printouts or other comparable VAR 
supporting documentation.
    (ii) For a facility which uses a gauge to measure the inventory of 
the detergent storage tank, the total volume of

[[Page 815]]

detergent shall be calculated from the following equation:

Detergent Volume = (A) - (B) + (C) - (D)

where:

A = Initial detergent inventory of the tank
B = Final detergent inventory of the tank
C = Sum of any additions to detergent inventory
D = Sum of any withdrawals from detergent inventory for purposes other 
than the additization of gasoline or PRC.


The value of each variable in this equation must be separately recorded 
on the VAR formula record. In addition, a list of each detergent 
addition included in variable C and a list of each detergent withdrawal 
included in variable D must be provided, either on the formula record or 
as VAR supporting documentation.
    (3) The total volume of gasoline plus PRC to which detergent has 
been added, together with supporting data which includes one of the 
following: The beginning and ending meter measurements for each meter 
being measured, the metered batch volume measurements for each meter 
being measured, or other comparable metered measurements. The supporting 
data may be supplied on the VAR formula record or in the form of 
computer printouts or other comparable VAR supporting documentation. If 
gasoline has intentionally been overadditized in anticipation of the 
later addition of unadditized PRC, then the total volume of gasoline 
plus PRC recorded must include the expected amount of unadditized PRC to 
be added later. In addition, the amount of gasoline which was 
overadditized for this purpose must be specified.
    (4) The actual detergent concentration, calculated as the total 
volume of detergent added (pursuant to paragraph (a)(2) of this 
section), divided by the total volume of gasoline plus PRC (pursuant to 
paragraph (a)(3) of this section). The concentration must be calculated 
and recorded to four digits.
    (5) A list of each detergent concentration rate initially set for 
the detergent that is the subject of the VAR record, together with the 
date and description of each adjustment to any initially set 
concentration. The concentration adjustment information may be supplied 
on the VAR formula record or in the form of computer printouts or other 
comparable VAR supporting documentation. No concentration setting is 
permitted below the applicable LAC, except as may be modified pursuant 
to Sec. 80.141(d) or as described in paragraph (a)(7) of this section.
    (6) The dates of the VAR period, which shall be no longer than 
thirty-one days. If the VAR period is contemporaneous with a calendar 
month, then specifying the month will fulfill this requirement; if not, 
then the beginning and ending dates and times of the VAR period must be 
listed. The times may be supplied on the VAR formula record or in 
supporting documentation. Any adjustment to any detergent concentration 
rate more than 10 percent over the concentration rate initially set in 
the VAR period shall terminate that VAR period and initiate a new VAR 
period, except as provided in paragraph (a)(7) of this section.
    (7) The concentration setting for a detergent injector may be set 
below the applicable LAC, or it may be adjusted more than 10 percent 
above the concentration initially set in the VAR period without 
terminating that VAR period, provided that:
    (i) The purpose of the change is to correct a batch misadditization 
prior to the end of the VAR period and prior to the transfer of the 
batch to another party, or to correct an equipment malfunction; and
    (ii) The concentration is immediately returned after the correction 
to a concentration that fulfills the requirements of paragraphs (a)(5) 
and (6) of this section; and
    (iii) The blender creates and maintains documentation establishing 
the date and adjustments of the correction; and
    (iv) If the correction is initiated only to rectify an equipment 
malfunction, and the amount of detergent used in this procedure is not 
added to gasoline in the compliance period, then this amount is 
subtracted from the detergent volume listed on the VAR formula record.
    (8) If unadditized gasoline has been transferred from the facility, 
other

[[Page 816]]

than bulk transfers from refineries or pipelines to non-retail outlets 
or non-WPC facilities, the total amount of such gasoline must be 
specified.
    (b) Non-automated facilities. In the case of a facility in which 
hand blending or any other non-automated method is used to blend 
detergent, for each detergent and for each batch of gasoline and each 
batch of PRC to which the detergent is being added, the following shall 
be recorded:
    (1) The manufacturer and commercial identifying name of the 
detergent additive package being reconciled, and the LAC specified in 
the detergent registration for use with the applicable type of gasoline 
(i.e., unleaded or leaded). The LAC must be expressed in terms of 
gallons of detergent per thousand gallons of gasoline or PRC, and 
expressed to four digits. If the specified LAC is only effective for use 
with leaded gasoline, the record must so indicate.
    (2) The date of the additization that is the subject of the VAR 
formula record.
    (3) The volume of added detergent.
    (4) The volume of the gasoline and/or PRC to which the detergent has 
been added. If gasoline has intentionally been overadditized in 
anticipation of the later addition of unadditized PRC, then the total 
volume of gasoline plus PRC recorded must include the expected amount of 
unadditized PRC to be added later. In addition, the amount of gasoline 
which was overadditized for this purpose must be specified.
    (5) The brand (if known), grade, and leaded/unleaded status of 
gasoline, and/or the type of PRC.
    (6) The actual detergent concentration, calculated as the volume of 
added detergent (pursuant to paragraph (b)(3) of this section), divided 
by the volume of gasoline and/or PRC (pursuant to paragraph (b)(4) of 
this section). The concentration must be calculated and recorded to four 
digits.
    (c) Every VAR formula record created pursuant to paragraphs (a) and 
(b) of this section shall contain the following:
    (1) The signature of the creator of the VAR record;
    (2) The date of the creation of the VAR record; and
    (3) A certification of correctness by the creator of the VAR record.
    (d) Electronically-generated VAR formula and supporting records. (1) 
Electronically-generated records are acceptable for VAR formula records 
and supporting documentation (including PTDs), provided that they are 
complete, accessible, and easily readable. VAR formula records must also 
be stored with access and audit security, which must restrict to a 
limited number of specified people those who have the ability to alter 
or delete the records. In addition, parties maintaining records 
electronically must make available for EPA use the hardware and software 
necessary to review the records.
    (2) Electronically-generated VAR formula records may use an 
electronic user identification code to satisfy the signature 
requirements of paragraph (c)(1) of this section, provided that:
    (i) The use of the ID is limited to the record creator; and
    (ii) A paper record is maintained, which is signed and dated by the 
VAR formula record creator, acknowledging that the use of that 
particular user ID on a VAR formula record is equivalent to his/her 
signature on the document.
    (e) Automated detergent blenders must calibrate their detergent 
equipment once in each calendar half year, with the acceptable 
calibrations being no less than one hundred twenty days apart. Equipment 
recalibration is also required each time the detergent package is 
changed, unless written documentation indicates that the new detergent 
package has the same viscosity as the previous detergent package. 
Detergent package change calibrations may be used to satisfy the 
semiannual requirement provided that the calibrations occur in the 
appropriate half calendar year and are no less than one hundred twenty 
days apart.
    (f) The following VAR supporting documentation must also be created 
and maintained:
    (1) For all automated detergent blending facilities, documentation 
reflecting performance of the calibrations required by paragraph (e) of 
this section, and any associated adjustments of the automated detergent 
equipment;

[[Page 817]]

    (2) For all hand-blending facilities which are terminals, a record 
specifying, for each calendar month, the total volume in gallons of 
transfers from the facility of unadditized base gasoline;
    (3) For all detergent blending facilities, product transfer 
documents for all gasoline, detergent and detergent-additized PRC 
transferred into or out of the facility; in addition, bills of lading, 
transfer, or sale for all unadditized PRC transferred into the facility;
    (4) For all automated detergent blending facilities, documentation 
establishing the brands (if known) and grades of the gasoline which is 
the subject of the VAR formula record;
    (5) For all hand blending detergent blenders, the documentation, if 
in the party's possession, supporting the volumes of gasoline, PRC, and 
detergent reported on the VAR formula record; and
    (6) For all detergent blending facilities, documentation 
establishing the curing of a batch or amount of misadditized gasoline or 
PRC, or the curing of a use restriction on the additized gasoline or 
PRC, and providing at least the following information: the date of the 
curing procedure; the problem that was corrected; the amount, name, and 
LAC of the original detergent used; the amount, name, and LAC of the 
added curing detergent; and the actual detergent concentration attained 
in, and the volume of, the total cured product.
    (g) Document retention and availability. All detergent blenders 
shall retain the documents required under this section for a period of 
five years from the date the VAR formula records and supporting 
documentation were created, and shall deliver them upon request to the 
EPA Administrator or the Administrator's authorized representative.
    (1) Except as provided in paragraph (g)(3) of this section, 
automated detergent blender facilities and hand-blender facilities which 
are terminals, which physically blend detergent into gasoline, must make 
immediately available to EPA, upon request, the preceding twelve months 
of VAR formula records plus the preceding two months of VAR supporting 
documentation.
    (2) Except as provided in paragraph (g)(3) of this section, other 
hand-blending detergent facilities which physically blend detergent into 
gasoline must make immediately available to EPA, upon request, the 
preceding two months of VAR formula records and VAR supporting 
documentation.
    (3) Facilities which have centrally maintained records at other 
locations, or have customers who maintain their own records at other 
locations for their proprietary detergent systems, and which can 
document this fact to the Agency, may have until the start of the next 
business day after the request to supply VAR supporting documentation, 
or longer if approved by the Agency.
    (4) In this paragraph (g) of this section, the term immediately 
available means that the records must be provided, electronically or 
otherwise, within approximately one hour of EPA's request, or within a 
longer time frame as approved by EPA.

[59 FR 54706, Nov. 1, 1994, as amended at 61 FR 35360, July 5, 1996]



Sec. 80.158  Product transfer documents (PTDs).

    (a) Contents. For each occasion when any gasoline refiner, importer, 
reseller, distributor, carrier, retailer, wholesale purchaser-consumer, 
oxygenate blender, detergent manufacturer, distributor, carrier, or 
blender, transfers custody or title to any gasoline, detergent, or 
detergent-additized PRC other than when detergent-additized gasoline is 
sold or dispensed at a retail outlet or wholesale purchaser-consumer 
facility to the ultimate consumer, the transferor shall provide to the 
transferee, and the transferee shall acquire from the transferor, 
documents which accurately include the following information:
    (1) The names and addresses of the transferee and transferor; the 
address requirement may be fulfilled, in the alternative, through 
separate documentation which establishes said addresses and is 
maintained by the parties and made available to EPA for the same length 
of time as required for the PTDs, provided that the normal business 
procedure of these parties is not to identify addresses on PTDs.

[[Page 818]]

    (2) The date of the transfer.
    (3) The volume of product transferred.
    (4)(i) The identity of the product being transferred (i.e., its 
identity as base gasoline, detergent, detergent-additized gasoline, or 
specified detergent-additized oxygenate or detergent-additized gasoline 
blending stock that comprises a detergent-additized PRC). PTDs for 
detergent-additized gasoline or PRC are not required to identify the 
particular detergent used to additize the product.
    (ii) If the product being transferred consists of two or more 
different types of product subject to this regulation, i.e., base 
gasoline, detergent-additized gasoline, or specified detergent-additized 
PRC, then the PTD for the commingled product must identify each such 
type of component contained in the commingled product.
    (5) If the product being transferred is base gasoline, then in 
addition to the base gasoline identification, the following warning must 
be stated on the PTD: ``Not for sale to the ultimate consumer''. If, 
pursuant to Sec. 80.160(a), the product being transferred is exempt 
base gasoline to be used for research, development, or test purposes 
only, the following warning must also be stated on the PTD: ``For use in 
research, development, and test programs only.''
    (6) The name of the detergent additive as reported in its 
registration must be used to identify the detergent package on its PTD.
    (7) If the product being transferred is leaded gasoline, then the 
PTD must disclose that the product contains lead and/or phosphorous, as 
applicable.
    (8) If the product being transferred is detergent that is only 
authorized for the control of carburetor deposits, then the following 
must be stated on the detergent's transfer document: ``For use with 
leaded gasoline only.''
    (9) If the product being transferred is detergent-additized gasoline 
that has been overadditized in anticipation of the later (or earlier) 
addition of PRC, then the PTD must include a statement that the product 
has been overadditized to account for a specified volume in gallons, or 
a specified percentage of the product's total volume, of additional, 
specified PRC.
    (b) Gasoline may not be additized with a detergent authorized only 
for the control of carburetor deposits and whose product transfer 
document states ``For use with leaded gasoline only'', and gasoline may 
not be additized at the lower concentration specified for a detergent 
authorized at a lower concentration for the control of carburetor 
deposits only, unless the product transfer document for the gasoline to 
be additized identifies it as leaded gasoline.
    (c) Use of product codes and other non-regulatory language. (1) 
Product codes and other non-regulatory language may not be used as a 
substitute for the specified PTD warning language specified in paragraph 
(a)(6) of this section for base gasoline, except that:
    (i) The specified warning language may be omitted for bulk transfers 
of base gasoline from a refinery to a pipeline if there is a prior 
written agreement between the parties specifying that all such gasoline 
is unadditized and will not be transferred to the ultimate consumer;
    (ii) Product codes may be used as a substitute for the specified 
warning language provided that the PTD is an electronic data interchange 
(EDI) document being used solely for the transfer of title to the base 
gasoline, and provided that the product codes otherwise comply with the 
requirements of this section.
    (2) Product codes and other language not specified in this section 
may otherwise be used to comply with PTD information requirements, 
provided that they are clear, accurate, and not misleading.
    (3) If product codes are used, they must be standardized throughout 
the distribution system in which they are used, and downstream parties 
must be informed of their full meaning.
    (d) PTD exemption for small transfers of additized gasoline. 
Transfers of additized gasoline are exempt from the PTD requirements of 
this section provided all the following conditions are followed:
    (1) The product is being transferred by a distributor who is not the 
product's detergent blender; and

[[Page 819]]

    (2) The recipient is a wholesale purchaser-consumer (WPC) or other 
ultimate consumer of gasoline, for its own use only or for that of its 
agents or employees; and
    (3) The volume of additized gasoline being transferred is not 
greater than 550 gallons.
    (e) Recordkeeping period. Any person creating, providing or 
acquiring product transfer documentation for gasoline, detergent, or 
detergent-additized PRC, except as provided in paragraph (d) of this 
section, shall retain the documents required by this section for a 
period of five years from the date the product transfer documentation 
was created, received or transferred, as applicable, and shall deliver 
such documents to EPA upon request. WPCs are not required to retain PTDs 
of additized gasoline received by them.

[61 FR 35362, July 5, 1996, as amended at 62 FR 60001, Nov. 6, 1997]



Sec. 80.159  Penalties.

    (a) General. Any person who violates any prohibition or affirmative 
requirement of Sec. 80.155 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.
    (b) Gasoline non-conformity. Any violation of Sec. 80.155(a) shall 
constitute a separate day of violation for each and every day the 
gasoline in violation remains at any place in the gasoline distribution 
system, beginning on the day that the gasoline is in violation of the 
respective prohibition and ending on the last day that such gasoline is 
offered for sale or is dispensed to any ultimate consumer.
    (c) Detergent non-conformity. Any violation of Sec. 80.155(d) shall 
constitute a separate day of violation for each and every day the 
detergent in violation remains at any place in the gasoline or detergent 
distribution system, beginning on the day that the detergent is in 
violation of the prohibition and ending on the last day that detergent-
additized gasoline, containing the subject detergent as a component 
thereof, is offered for sale or is dispensed to any ultimate consumer.
    (d) Post-refinery component non-conformity. Any violation of Sec. 
80.155(e) shall constitute a separate day of violation for each and 
every day the post-refinery component in violation remains at any place 
in the post-refinery component or gasoline distribution system, 
beginning on the day that the post-refinery component is in violation of 
the respective prohibition and ending on the last day that detergent-
additized gasoline containing the post-refinery component is offered for 
sale or is dispensed to any ultimate consumer.
    (e) Product transfer document non-conformity. Any violation of Sec. 
80.155(c) shall constitute a separate day of violation for every day the 
product transfer document is not fully in compliance. This is to begin 
on the day that the product transfer document is created or should have 
been created and to end at the later of the following dates: Either the 
day that the document is corrected and comes into compliance, or the day 
that gasoline not additized in conformity with interim detergent program 
requirements, as a result of the product transfer document non-
conformity, is offered for sale or is dispensed to the ultimate 
consumer.
    (f) Volumetric additive reconciliation (VAR) record keeping non-
conformity. Any VAR recordkeeping violation of Sec. 80.155(b) shall 
constitute a separate day of violation for every day that VAR 
recordkeeping is not fully in compliance. Each element of the VAR record 
keeping program that is not in compliance shall constitute a separate 
violation for purposes of this section.
    (g) Volumetric additive reconciliation (VAR) compliance standard 
non-conformity. Any violation of the VAR compliance standard established 
in Sec. 80.157 shall constitute a separate day of violation for each 
and every day of the VAR compliance period in which the standard was 
violated.
    (h) Volumetric additive reconciliation (VAR) equipment calibration 
non-conformity. Any VAR equipment calibration violation of Sec. 
80.155(b) shall constitute a separate day of violation for every day a 
VAR equipment calibration requirement is not met.

[[Page 820]]



Sec. 80.160  Exemptions.

    (a) Research, development, and testing exemptions. Any detergent 
that is either in a research, development, or test status, or is sold to 
petroleum, automobile, engine, or component manufacturers for research, 
development, or test purposes, or any gasoline to be used by, or under 
the control of, petroleum, additive, automobile, engine, or component 
manufacturers for research, development, or test purposes, is exempted 
from the provisions of the interim detergent program, provided that:
    (1) The detergent (or fuel containing the detergent), or the 
gasoline, is kept segregated from non-exempt product, and the party 
possessing the product maintains documentation identifying the product 
as research, development, or testing detergent or fuel, as applicable, 
and stating that it is to be used only for research, development, or 
testing purposes; and
    (2) The detergent (or fuel containing the detergent), or the 
gasoline, is not sold, dispensed, or transferred, or offered for sale, 
dispensing, or transfer from a retail outlet. It shall also not be sold, 
dispensed, or transferred, or offered for sale, dispensing, or transfer 
from a wholesale purchaser-consumer facility, unless such facility is 
associated with detergent, fuel, automotive, or engine research, 
development or testing; and
    (3) The party using the product for research, development, or 
testing purposes, or the party sponsoring this usage, notifies the EPA, 
on at least an annual basis and prior to the use of the product, of the 
purpose(s) of the program(s) in which the product will be used and the 
anticipated volume of the product to be used. The information must be 
submitted to the address or fax number provided in Sec. 80.174(c).
    (b) Racing fuel and aviation fuel exemptions. Any fuel that is 
refined, sold, dispensed, transferred, or offered for sale, dispensing, 
or transfer as automotive racing fuel or as aircraft engine fuel, is 
exempted from the provisions of this subpart, provided that:
    (1) The fuel is kept segregated from non-exempt fuel, and the party 
possessing the fuel for the purposes of refining, selling, dispensing, 
transferring, or offering for sale, dispensing, or transfer as 
automotive racing fuel or as aircraft engine fuel, maintains 
documentation identifying the product as racing fuel, restricted for 
non-highway use in racing motor vehicles, or as aviation fuel, 
restricted for use in aircraft, as applicable;
    (2) Each pump stand at a regulated party's facility, from which such 
fuel is dispensed, is labeled with the applicable fuel identification 
and use restrictions described in paragraph (b)(1) of this section; and
    (3) The fuel is not sold, dispensed, transferred, or offered for 
sale, dispensing, or transfer for highway use in a motor vehicle.
    (c) California gasoline exemptions. (1) Gasoline or PRC which is 
additized in the State of California is exempt from the VAR provisions 
in Sec. Sec. 80.155(b) and (e) and 80.157, provided that:
    (i) For all such gasoline or PRC, whether intended for sale within 
or outside of California, records of the type required for California 
gasoline (specified in title 13, California Code of Regulations, section 
2257) are maintained; and
    (ii) Such records, with the exception of daily additization records, 
are maintained for a period of five years from the date they were 
created and are delivered to EPA upon request.
    (2) Gasoline or PRC that is transferred and/or sold solely within 
the State of California is exempt from the PTD provisions of the interim 
detergent program, specified in Sec. Sec. 80.155(c) and 80.158.
    (3) Nothing in this paragraph (c) exempts such gasoline or PRC from 
the requirements of Sec. 80.155(a) and (e), as applicable. EPA will 
base its determination of California gasoline's conformity with the 
detergent's LAC on the additization records required by CARB, or records 
of the same type.

[61 FR 35363, July 5, 1996]



Sec. 80.161  Detergent additive certification program.

    (a) Effective dates and applicability of requirements. (1) As of 
July 1, 1997:
    (i) Detergent additives for the control of port fuel injector 
deposits (PFID) and/or intake valve deposits (IVD) in gasoline engines 
may not be

[[Page 821]]

transferred or sold for use in compliance with this subpart unless such 
additives have been certified according to the requirements of this 
section.
    (ii) Except as provided in Sec. 80.169(c)(8), PFID and IVD control 
additives may not be added to gasoline or post-refinery component (PRC) 
for compliance with this subpart unless such additives have been 
certified according to the requirements of this section.
    (iii) Gasoline may not be sold or transferred to a party who sells 
or transfers gasoline to the ultimate consumer unless such gasoline 
contains detergent additives which have been certified according to the 
requirements of this section.
    (2) Beginning August 1, 1997, all gasoline sold or transferred to 
the ultimate consumer must contain detergent additive(s) which have been 
certified, according to the requirements of this section, to be 
effective for the control of PFID and IVD in gasoline engines.
    (3) Except as specifically exempted in Sec. 80.173, these 
detergency requirements apply to all gasoline, whether intended for on-
highway or nonroad use, including conventional, oxygenated, 
reformulated, and leaded gasolines, as well as the gasoline component in 
mixtures of petroleum and alcohol fuels, gasoline used as marine fuel, 
gasoline service accumulation fuel (as described in Sec. 86.113-
94(a)(1) of this chapter), the gasoline component of fuel mixtures of 
petroleum and methanol used for service accumulation in flexible fuel 
vehicles (as described in Sec. 86.113-94(d) of this chapter), the 
gasoline used for factory fill purposes, and all additized PRC.
    (4) The specific controls and prohibitions applicable to persons 
subject to these regulations are set forth in Sec. 80.168.
    (b) Detergent additive certification requirements. For a detergent 
additive package to be certified as eligible for use by detergent 
blenders in complying with the gasoline detergency requirements of this 
subpart, the requirements listed in this paragraph (b) must be satisfied 
for such detergent. Subject to the provisions of paragraph (e) of this 
section, if the certifier fails to conduct the specified tests or to 
submit the specified materials, or if EPA judges the testing or 
materials to be inadequate, or if the detergent fails EPA confirmatory 
deposit control performance testing pursuant to Sec. 80.167, the 
Administrator may deny or withdraw the detergent's eligibility to be 
used to satisfy the detergency requirements of this subpart.
    (1) The detergent additive manufacturer must properly register the 
detergent additive under 40 CFR part 79. For this purpose:
    (i) The compositional data required under Sec. 79.21(a) of this 
chapter shall include the information specified in Sec. 80.162.
    (ii) The minimum recommended additive concentration required under 
Sec. 79.21(d) of this chapter shall be reported to EPA in units of 
gallons of detergent additive package per 1000 gallons of gasoline or 
PRC, provided to four digits. This concentration is the lowest additive 
concentration (LAC) referred to in Sec. 80.170, and shall be reported 
as follows:
    (A) For a detergent additive registered for use in unleaded 
gasoline, the minimum concentration must be determined and reported for 
each certification option under which the manufacturer wishes to certify 
the additive pursuant to Sec. 80.163.
    (1) In the case of a detergent certified for use in California 
gasoline based on an existing certification granted by the California 
Air Resources Board (CARB), pursuant to Sec. 80.163(d), the minimum 
recommended concentration must equal or exceed the amount specified in 
the CARB certification.
    (2) In the case of any other detergent certification option, the 
minimum recommended concentration must equal or exceed the amount mixed 
into the associated test fuel specified in Sec. 80.164, which was shown 
to satisfy the PFID and IVD deposit control performance tests and 
standards specified in Sec. 80.165.
    (B) For a detergent registered for use in leaded gasoline, the 
minimum recommended concentration must be no less than the amount shown 
to be needed for control of carburetor deposits, pursuant to the test 
procedure and test fuel guidelines in Sec. 80.166.
    (C) Once it has been registered by EPA, the minimum recommended 
concentration specified by a detergent

[[Page 822]]

manufacturer to detergent blenders and other users of the additive, 
pursuant to paragraph (c) of this section, may not be changed without 
first notifying EPA. Such notification should be sent by certified mail 
to the address specified in Sec. 80.174(b). The change in minimum 
concentration must be supported by existing certification data or else 
the notification to EPA must be accompanied by new certification 
information which demonstrates that the modification is consistent with 
the requirements of paragraphs (b)(1)(ii)(A) and (B) of this section.
    (D) A manufacturer may use a single set of certification test data 
to demonstrate the deposit control effectiveness of more than one 
registered detergent additive product, provided that:
    (1) The additive products contain all of the same detergent-active 
components and no detergent-active components other than those contained 
in common; and
    (2) The minimum concentration recommended for the use of each such 
additive product is specified such that, when each additive product is 
mixed in gasoline at the recommended concentration, each of its 
detergent-active components will be present at a final concentration no 
less than the lowest concentration of that component which was present 
when the tested additive product met the PFID and IVD performance 
standards specified in Sec. 80.165.
    (2) The detergent additive manufacturer (or other certifying party) 
must submit to EPA a sample of the actual detergent additive package 
which was used in the certification testing specified in Sec. 80.164 
or, if such sample is not available, then a sample which has the same 
composition as the package used in certification testing.
    (i) The sample volume shall be between 250 ml and 500 ml.
    (ii) The sample shall be packaged in a container which has a 
resealable closure and which will maintain sample integrity for at least 
one year. The container shall be labeled with the name and address of 
the manufacturer and the name of the detergent additive package.
    (iii) Any known shelf life limitations, and any available 
information on optimal temperature, light exposure, or other conditions 
to prolong sample shelf life, shall be provided.
    (iv) If the certifying party wishes to claim that the sample or any 
accompanying documents are entitled to special handling for reasons of 
business confidentiality, the party must clearly identify the sample or 
documents as such. EPA will handle any samples or documents with such 
claims according to the regulations at 40 CFR part 2.
    (v) The sample shall be submitted to EPA, at the address provided in 
Sec. 80.174(a), within seven days of the date on which the 
certification letter for the detergent package is sent to EPA as 
required by paragraph (b)(3) of this section.
    (3) The detergent additive manufacturer (or other certifying party) 
shall submit a certification letter for the detergent additive package 
to the address in Sec. 80.174(b). The party must use certified or 
express mail with return receipt service. The letter shall be signed by 
a person legally authorized to represent the certifying party and shall 
contain the following information:
    (i) Identifying information.
    (A) The name and address of the detergent additive manufacturer.
    (B) In any case where the certifier is not the detergent additive 
manufacturer, such as in the case of a fuel-specific certification 
pursuant to Sec. 80.163(c), the name and address of the certifier.
    (C) The commercial identifying name of the detergent additive 
product as registered under the requirements of Sec. 79.21 of this 
chapter.
    (ii) A statement attesting that:
    (A) The detergent package which is the subject of this certification 
has been tested according to applicable procedural and test fuel 
requirements in this subpart and has met the applicable performance 
standards; and
    (B) The testing was conducted in a manner consistent with good 
engineering practices; and
    (C) Complete documentation of the test fuel formulation and IVD 
demonstration procedures, detergent performance test procedures, and 
test results are available for EPA's inspection upon request.

[[Page 823]]

    (iii) The name and location of the laboratory(ies) at which the 
certification testing was conducted and the dates during which the 
testing was conducted.
    (iv) For each option under which certification is sought pursuant to 
Sec. 80.163, specifications of the test fuel(s) in which the detergent 
underwent performance testing. These fuel specifications must include:
    (A) The sulfur content in weight percent.
    (B) The T-90 distillation point in degrees Fahrenheit.
    (C) The olefin content in volume percent.
    (D) The aromatic content in volume percent.
    (E) The identity and volume percent of any oxygenate compound.
    (F) The source of the test fuel(s) and/or fuel blend stocks used to 
formulate the test fuel(s).
    (v) In the case of a national or PADD certification (pursuant to 
Sec. 80.163 (a) or (b)) for which the test fuel was specially 
formulated from refinery blend stocks, the results of the IVD 
demonstration test, pursuant to Sec. 80.164(b)(3).
    (vi) In the case of a fuel-specific detergent certification, 
pursuant to Sec. 80.163(c), the definition of the segregated gasoline 
pool, including any permitted PRC, for which the certification is 
sought, and the fuel parameter percentile distributions determined for 
the subject gasoline pool, as specified in Sec. 80.164(c). The 
percentile distributions must include all of the fuel parameters listed 
in paragraph (b)(3)(iv) (A) through (D) of this section, along with any 
other fuel parameter(s) which the certifier wishes to use to define the 
certification fuel. As specified in Sec. 80.164(c)(1)(iv), the 
procedures used to measure the additional parameters must be identified, 
as well as the levels of these additional parameters present in the test 
fuel(s).
    (vii) In the case of a certification for California gasoline based 
on an existing certification granted by CARB, pursuant to Sec. 
80.163(d), a copy of the CARB certificate.
    (viii) The test concentration(s) of the subject detergent additive 
in each test fuel, and the corresponding test results (percent flow 
restriction demonstrated in the PFID test and milligrams of deposit per 
valve demonstrated in the IVD test).
    (ix) For each option under which certification of the detergent is 
sought, the minimum recommended concentration which the certifying party 
seeks to establish for the detergent additive package, pursuant to 
paragraph (b)(1)(ii) of this section.
    (4) EPA will acknowledge receipt of the detergent certification 
letter. The effective date of certification will be the sooner of 60 
days from the date on which EPA receives the certification letter, or 
the certifier's receipt of EPA's acknowledgement of the certification 
letter. However, neither the passage of 60 days nor EPA's 
acknowledgement will signify acceptance by EPA of the validity of the 
information in the certification letter or the adequacy or potency of 
the detergent sample submitted pursuant to paragraph (b)(2) of this 
section. EPA may elect at any time to review the detergent certification 
data, analyze the submitted detergent additive sample, or subject the 
detergent additive package to confirmatory testing as described in Sec. 
80.167 and, where appropriate, may disqualify a detergent certification 
according to the provisions in paragraph (e) of this section.
    (c) The minimum concentration reported in the detergent registration 
according to the provisions of paragraph (b)(1)(ii) of this section, 
plus any restrictions in use associated with that concentration, must be 
accurately communicated in writing by the additive manufacturer to each 
fuel manufacturer or detergent blender who purchases the subject 
detergent for purpose of compliance with the gasoline detergency 
requirements of this subpart, and to any additive manufacturer who 
purchases the subject additive with the intent of reselling it to a fuel 
manufacturer for this purpose.
    (d) The rate at which a detergent blender treats gasoline with a 
detergent additive package must be no less than the minimum recommended 
concentration reported for the subject detergent additive pursuant to 
paragraph (b)(1)(ii) of this section, except under the following 
conditions:

[[Page 824]]

    (1) If a detergent blender possesses deposit control performance 
test results as specified in Sec. 80.165 or Sec. 80.166 which show 
that the minimum treat rate recommended by the manufacturer of a 
detergent additive product exceeds the amount of that detergent actually 
required for effective deposit control, then, upon informing EPA in 
writing of these circumstances, the detergent blender may use the 
detergent at the lower concentration substantiated by these test 
results.
    (2) The notification to EPA must clearly specify the name of the 
detergent product and its manufacturer, the concentration recommended by 
the detergent manufacturer, and the lower concentration which the 
detergent blender intends to use. The notification must also attest that 
the required data are available to substantiate the deposit control 
effectiveness of the detergent at the intended lower concentration. The 
notification must be sent by certified mail to the address specified in 
Sec. 80.174(b).
    (3) At its discretion, EPA may require that the detergent blender 
submit the test data purported to substantiate the claimed effectiveness 
of the lower concentration of the detergent additive. In addition, EPA 
may require the manufacturer of the subject detergent additive to submit 
test data substantiating the minimum recommended concentration specified 
in the detergent additive registration. In either case, EPA will send a 
letter to the appropriate party; the supporting data will be due to EPA 
within 30 days of receipt of EPA's letter.
    (i) If the detergent blender fails to submit the required supporting 
data to EPA in the allotted time period, or if EPA judges the submitted 
data to be inadequate to support the detergent blender's claim that the 
lower concentration provides a level of deposit control consistent with 
the requirements of this section, then EPA will disapprove the use of 
the detergent at the lower concentration. Further, the detergent blender 
may be subject to applicable liabilities and penalties pursuant to 
Sec. Sec. 80.169 and 80.172 for any gasoline or PRC it has additized at 
the lower concentration.
    (ii) If the detergent manufacturer fails to submit the required test 
data to EPA within the allotted time period, EPA will proceed on the 
assumption that data are not available to substantiate the minimum 
recommended concentration specified in the detergent registration, and 
the subject additive may be disqualified for use in complying with the 
requirements of this subpart, pursuant to the procedures in paragraph 
(e) of this section. The detergent manufacturer may also be subject to 
applicable liabilities and penalties in Sec. Sec. 80.169 and 80.172.
    (iii) If both parties submit the required information, EPA will 
evaluate the quality and results of both sets of test data, and will 
either approve or disapprove the use of the lower treat rate submitted 
by the detergent blender. EPA will inform both parties of the results of 
its analysis.
    (e) Disqualification of a detergent additive package. (1) When EPA 
makes a preliminary determination that a detergent additive certifier 
has failed to comply with the detergent certification requirements of 
this section, including a failure to submit required materials for a 
detergent additive or submission of materials which EPA deems 
inadequate, or if a detergent additive fails confirmatory testing 
conducted pursuant to Sec. 80.167, EPA shall notify the additive 
certifier by certified mail, return receipt requested, setting forth the 
basis for that determination and informing the certifier that the 
detergent may lose its eligibility to be used to comply with the 
detergency requirements of this section.
    (2) If EPA determines that the detergent certification was created 
by fraud or other misconduct, such as a negligent disregard for the 
truthfulness or accuracy of the required information, the detergent 
certification will be considered void ab initio and the disqualification 
will be retroactive to July 1, 1997 or the date on which the additive 
product was first certified, whichever is later.
    (3) The certifier will be afforded 60 days from the date of receipt 
of the notice of intent of detergent disqualification to submit written 
comments concerning the notice, and to demonstrate or achieve compliance 
with the specific

[[Page 825]]

requirements which provide the basis for the proposed disqualification. 
If the certifier does not respond in writing within 60 days from the 
date of receipt of the notice of intent of disqualification, the 
detergent disqualification shall become final and the Administrator 
shall notify the certifier of such final disqualification order. If the 
certifier responds in writing within 60 days from the date of receipt of 
the notice of intent to disqualify, the Administrator shall review and 
consider all comments submitted by the certifier before taking final 
action concerning the proposed disqualification. All correspondence 
regarding a disqualification must be sent to the address provided in 
Sec. 80.174(b).
    (4) As part of a written response to a notice of intent to 
disqualify, a certifier may request an informal hearing concerning the 
notice. Any such request shall state with specificity the information 
the certifier wishes to present at such a hearing. If an informal 
hearing is requested, EPA shall schedule such a hearing within 90 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 certifier has complied with the specific requirements which 
provide the basis for the proposed disqualification. 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 (or designee) shall consider all relevant 
evidence and arguments presented at the hearing in making a final 
decision concerning a proposed disqualification.
    (5) If a certifier who has received a notice of intent to disqualify 
submits a timely written response, and the Administrator (or designee) 
decides after reviewing the response and the transcript of any informal 
hearing to disqualify the detergent for use in complying with the 
requirements of this subpart, the Administrator (or designee) shall 
issue a final disqualification order and forward a copy of the 
disqualification order to the certifier by certified mail. Notice of the 
disqualification order will also be published in the Federal Register. 
The disqualification will become effective as of the date on which the 
copy of the order is received by the certifier. If the certifier is also 
a blender of the disqualified additive, then the certifier must stop 
using the ineligible detergent upon receipt of the disqualification 
order.
    (6) Within 10 days of receipt of EPA's notification of the final 
decision to disqualify a detergent additive package pursuant to this 
paragraph (e), the detergent certifier must submit to EPA, at the 
address specified in Sec. 80.174(b), a list of its customers who use 
the disqualified detergent. Failure to do so may subject the certifier 
to liabilities for violations of Sec. 80.168 that result from the use 
of the uncertified detergent. EPA shall inform the certifier's customers 
by certified mail that the detergent is no longer eligible for 
compliance with the requirements of this subpart. These parties must 
stop using the ineligible detergent additive package and substitute an 
eligible detergent additive within 45 days of receiving the 
notification, or within 45 days of publication of the disqualification 
notice in the Federal Register, whichever occurs sooner.

[61 FR 35364, July 5, 1996, as amended at 61 FR 58747, Nov. 18, 1996]



Sec. 80.162  Additive compositional data.

    For a detergent additive product to be eligible for use by detergent 
blenders in complying with the gasoline detergency requirements of this 
subpart, the compositional data to be supplied to EPA by the additive 
manufacturer for the purpose of registering a detergent additive package 
under Sec. 79.21(a) of this chapter must include the items listed in 
this section. In the case of items requiring measurement or other 
technical analysis, and for which a specific test procedure is not 
stipulated herein, the procedure must conform to reasonable and 
customary standards of repeatability and reproducibility, and reasonable 
and customary limits of detection and accuracy for the type of test 
procedure or analytic procedure in question. At EPA's request, detailed

[[Page 826]]

documentation of any such test procedure must be submitted within 10 
days of the registrant's receipt of EPA's request.
    (a) A complete listing of the components of the detergent additive 
package and the weight and/or volume percent (as applicable) of each 
component of the package.
    (1) When possible, standard chemical nomenclature shall be used or 
the chemical structure of the component shall be given. Polymeric 
components may be reported as the product of other chemical reactants, 
provided that the supporting data specified in paragraph (b) of this 
section is also reported.
    (2) Each detergent-active component of the package shall be 
classified into one of the following designations:
    (i) Polyalkyl amine;
    (ii) Polyether amine;
    (iii) Polyalkylsuccinimide;
    (iv) Polyalkylaminophenol;
    (v) Detergent-active petroleum-based carrier oil;
    (vi) Detergent-active synthetic carrier oil; and
    (vii) Other detergent-active component (identify category, if 
feasible.)
    (3) Composition variability.
    (i) The composition of a detergent additive reported in a single 
additive registration (and the detergent additive product sold under a 
single additive registration) may not:
    (A) Include detergent-active components which differ in identity 
from those contained in the detergent additive package at the time of 
certification testing; or
    (B) Include a range of concentration for any detergent-active 
component such that, if the component were present in the detergent 
additive package at the lower bound of the reported range, the deposit 
control effectiveness of the additive package would be reduced as 
compared with the level of effectiveness demonstrated during 
certification testing. Subject to the foregoing constraint, a detergent 
additive product sold under a particular additive registration may 
contain a higher concentration of the detergent-active component(s) than 
the concentration(s) of such component(s) reported in the registration 
for the additive.
    (ii) The identity or concentration of non-detergent-active 
components of the detergent additive package may vary under a single 
registration provided that such variability does not reduce the deposit 
control effectiveness of the additive package as compared with the level 
of effectiveness demonstrated during certification testing.
    (A) Unless the additive manufacturer (or other certifying party) 
provides EPA with data to substantiate that a carrier oil does not act 
to enhance the detergent additive package's ability to control deposits, 
any carrier oil contained in the detergent additive package, whether 
petroleum-based or synthetic, must be treated as a detergent-active 
component in accordance with the additive compositional reporting 
requirements in Sec. 80.162(a)(2). Such data should be sent by 
certified mail to the address specified in Sec. 80.174(b).
    (B) [Reserved]
    (iii) Except as provided in paragraph (a)(3)(iv) of this section, 
detergent additive packages which do not satisfy the restrictions in 
this paragraph (a)(3) must be separately registered. EPA may disqualify 
an additive for use in satisfying the requirements of this subpart if 
EPA determines that the variability included within a given detergent 
additive registration may reduce the deposit control effectiveness of 
the detergent package such that it may invalidate the minimum 
recommended concentration reported in accordance with the applicable 
requirements of Sec. 80.161(b)(1)(ii).
    (iv) A change in minimum concentration requirements resulting from a 
modification of detergent additive composition shall not require a new 
detergent additive registration or a change in existing registration if:
    (A) The modification is effected by a detergent blender only for its 
own use or for the use of parties which are subsidiaries of, or share 
common ownership with, the blender, and the modified detergent is not 
sold or transferred to other parties; and
    (B) The modification is a dilution of the additive for the purpose 
of ensuring proper detergent flow in cold weather; and
    (C) Gasoline is the only diluting agent used; and

[[Page 827]]

    (D) The diluted detergent is subsequently added to gasoline at a 
rate that attains the detergent's registered minimum recommended 
concentration, taking into account the dilution; and
    (E) EPA is notified, either before or within seven days after the 
dilution action, of the identity of the detergent, the identity of the 
diluting material, the amount or percentage of the dilution, the change 
in treat rate necessitated by the dilution, and the locations and time 
period of diluted detergent usage. The notification shall be sent or 
faxed to the address in Sec. 80.174(c).
    (b) For detergent-active polymers and detergent-active carrier oils 
which are reported as the product of other chemical reactants:
    (1) Identification of the reactant materials and the manufacturer's 
acceptance criteria for determining that these materials are suitable 
for use in synthesizing detergent components. The manufacturer must 
maintain documentation, and submit it to EPA upon request, demonstrating 
that the acceptance criteria reported to EPA are the same criteria which 
the manufacturer specifies to the suppliers of the reactant materials.
    (2) A Gel Permeation Chromatograph (GPC), providing the molecular 
weight distribution of the polymer or detergent-active carrier oil 
components and the concentration of each chromatographic peak 
representing more than one percent of the total mass. For these results 
to be acceptable, the GPC test procedure must include equipment 
calibration with a polystyrene standard or other readily attainable and 
generally accepted calibration standard. The identity of the calibration 
standard must be provided, together with the GPC characterization of the 
standard.
    (c) For non-detergent-active carrier oils, the following parameters:
    (1) T10, T50, and T90 distillation points, and end boiling point, 
measured according to applicable test procedures cited in Sec. 80.46.
    (2) API gravity and viscosity
    (3) Concentration of oxygen, sulfur, and nitrogen, if greater than 
or equal to 0.5 percent (by weight) of the carrier oil
    (d) Description of an FTIR-based method appropriate for identifying 
the detergent additive package and its detergent-active components 
(polymers, carrier oils, and others) both qualitatively and 
quantitatively, together with the actual infrared spectra of the 
detergent additive package and each detergent-active component obtained 
by this test method. The FTIR infrared spectra submitted in connection 
with the registration of a detergent additive package must reflect the 
results of a test conducted on a sample of the additive containing the 
detergent-active component(s) at a concentration no lower than the 
concentration(s) (or the lower bound of a range of concentration) 
reported in the registration pursuant to paragraph (a)(3)(i)(B) of this 
section.
    (e) To provide a basis for establishing an affirmative defense to 
presumptive liability pursuant to Sec. 80.169(c)(4)(i)(D)(2)(i), 
specific physical parameters must be identified which the manufacturer 
considers adequate and appropriate, in combination with other 
information and sampling requirements under this subpart, for 
identifying the detergent additive package and monitoring its production 
quality control.
    (1) Such parameters shall include (but need not be limited to) 
viscosity, density, and basic nitrogen content, unless the additive 
manufacturer specifically requests, and EPA approves, the substitution 
of other parameter(s) which the manufacturer considers to be more 
appropriate for a particular additive package. The request must be made 
in writing and must include an explanation of how the requested physical 
parameter(s) are helpful as indicator(s) of detergent production quality 
control. EPA will respond to such requests in writing; the additional 
parameters are not approved until the certifier receives EPA's written 
approval.
    (2) The manufacturer shall identify a standardized measurement 
method, consistent with the chemical and physical nature of the 
detergent product, which will be used to measure each parameter. The 
documented ASTM repeatability for the method shall also be cited. The 
manufacturer's target value

[[Page 828]]

for each parameter in the detergent package, and the expected range of 
production values for each parameter, shall be specified.
    (3) EPA will consider the parameter measurements to be an acceptable 
basis for establishing an affirmative defense to presumptive liability, 
if the expected range of variability differs from the target value by an 
amount no greater than five times the standard repeatability of the test 
procedure, or by no more than 10 percent of the target value, whichever 
is less. However, in the case of nitrogen analysis or other procedures 
for measuring concentrations of specific chemical compounds or elements, 
when the target value is less than 10 parts per million, a range of 
variability up to 50 percent of the target value will be considered 
acceptable.
    (4) If a manufacturer wishes to rely on measurement methods or 
production variability ranges which do not conform to the above 
limitations, then the manufacturer must receive prior written approval 
from EPA in order to be assured that any related parameter measurements 
will be considered an acceptable basis for establishing an affirmative 
defense. A request for such allowance must be made in writing. It must 
fully justify the adequacy of the test procedure, explain why a broader 
range of variability is required, and provide evidence that the 
production detergent will perform adequately throughout the requested 
range of variability.

[61 FR 35366, July 5, 1996, as amended at 66 FR 55889, Nov. 5, 2001; 70 
FR 69245, Nov. 14, 2005]



Sec. 80.163  Detergent certification options.

    To be used to satisfy the detergency requirements under Sec. 
80.161(a), a detergent additive must be certified in accordance with the 
requirements of one or more of the options and suboptions described in 
this section. Where a certification option makes an additive eligible 
for use in a particular gasoline, that additive is also eligible for use 
in PRC which will be added to the particular gasoline. Under each 
option, the lowest additive concentration (LAC) or minimum recommended 
concentration registered for a detergent additive package, pursuant to 
Sec. 80.161(b)(1)(ii), must equal or exceed the lowest detergent treat 
rate shown to be needed in the designated test fuel in order to meet the 
deposit control performance requirements specified in Sec. 80.165.
    (a) National certification. A detergent certified under a national 
certification option is eligible for use in gasoline which can be sold 
or dispensed anywhere within the United States or its territories 
(subject to approved State programs).
    (1) National generic certification option. To be certified under 
this option, a candidate detergent must meet the deposit control 
performance test requirements and standards specified in Sec. 80.165 
using test fuels that conform to the requirements in Sec. 80.164(b)(1), 
Table 1, Line 1. A detergent certified under this option is eligible to 
be used at a conforming LAC in any grade of gasoline, with or without an 
oxygenate component.
    (i) National nonoxygenate suboption. The requirements for 
certification under this suboption are the same as those in paragraph 
(a)(1) of this section, except that, pursuant to Sec. 80.164(a)(2)(ii), 
the certification test fuel shall contain no ethanol or other oxygenate. 
A detergent certified under this suboption is eligible to be used at a 
conforming LAC only in gasoline that does not contain an oxygenate 
component.
    (ii) National oxygenate-specific suboption. The requirements for 
certification under this suboption are the same as those in paragraph 
(a)(1) of this section, except that, pursuant to Sec. 
80.164(a)(2)(iii), the certification test fuel shall contain an 
oxygenate compound other than ethanol. A detergent certified under this 
suboption is eligible to be used at a conforming LAC only in gasoline 
that contains no oxygenate component other than the one present in the 
test fuel.
    (2) National premium certification option. To be certified under 
this option, a candidate detergent must meet the deposit control 
performance test requirements and standards specified in Sec. 80.165 
using test fuels that conform to the requirements in Sec. 80.164(b)(1), 
Table

[[Page 829]]

1, Line 2. A detergent certified under this option is eligible to be 
used at a conforming LAC only in premium grade gasoline, with or without 
an oxygenate component.
    (i) National premium nonoxygenate suboption. The requirements for 
certification under this suboption are the same as those in paragraph 
(a)(2) of this section, except that, pursuant to Sec. 80.164(a)(2)(ii), 
the certification test fuel shall contain no ethanol or other oxygenate. 
A detergent certified under this suboption is eligible to be used at a 
conforming LAC only in premium grade gasoline that does not contain an 
oxygenate component.
    (ii) National premium oxygenate-specific suboption. The requirements 
for certification under this suboption are the same as those in 
paragraph (a)(2) of this section, except that, pursuant to Sec. 
80.164(a)(2)(iii), the certification test fuel shall contain an 
oxygenate compound other than ethanol. A detergent certified under this 
suboption is eligible to be used at a conforming LAC only in gasoline 
that is premium grade and contains no oxygenate component other than the 
one present in the test fuel.
    (b) Petroleum Administrative Defense District (PADD) Certification. 
A detergent certified under a PADD certification option is eligible for 
use in gasoline which can be sold or dispensed to the ultimate 
purchaser, or to those parties who sell or dispense to the ultimate 
consumer, only within the PADD for which the certification was granted. 
The States and jurisdictions included within each PADD are specified in 
Sec. 79.59(b)(3)(i) through (v), except that, for purposes of PADD 
certification, the State of California is excluded from PADD V.
    (1) PADD generic certification option. To be certified under this 
option, a candidate detergent must meet the deposit control performance 
test requirements and standards specified in Sec. 80.165 using test 
fuels that conform to the requirements in Sec. 80.164(b)(1), Table 2, 
for a selected PADD. A detergent certified under this option is eligible 
to be used at a conforming LAC in any grade of gasoline, with or without 
an oxygenate component, provided that the gasoline is ultimately 
dispensed in the selected PADD.
    (i) PADD nonoxygenate suboption. The requirements for certification 
under this suboption are the same as those in paragraph (b)(1) of this 
section, except that, pursuant to Sec. 80.164(a)(2)(ii), the 
certification test fuel shall contain no ethanol or other oxygenate. A 
detergent certified under this suboption is eligible to be used at a 
conforming LAC only in gasoline that is nonoxygenated and is ultimately 
dispensed in the selected PADD.
    (ii) PADD oxygenate-specific suboption. The requirements for 
certification under this suboption are the same as those in paragraph 
(b)(1) of this section, except that, pursuant to Sec. 
80.164(a)(2)(iii), the certification test fuel shall contain an 
oxygenate compound other than ethanol. A detergent certified under this 
suboption is eligible to be used at a conforming LAC only in gasoline 
that contains no oxygenate component other than the one present in the 
test fuel and is ultimately dispensed in the selected PADD.
    (2) PADD premium certification option. To be certified under this 
option, a candidate detergent must meet the deposit control performance 
test requirements and standards specified in Sec. 80.165 using test 
fuels that conform to the requirements in Sec. 80.164(b)(1), Table 2, 
for a selected PADD. A detergent certified under this option is eligible 
to be used at a conforming LAC only in gasoline that is premium grade 
(with or without an oxygenate component) and is ultimately dispensed in 
the selected PADD.
    (i) PADD premium nonoxygenate suboption. The requirements for 
certification under this suboption are the same as those in paragraph 
(b)(2) of this section, except that, pursuant to Sec. 80.164(a)(2)(ii), 
the certification test fuel shall contain no ethanol or other oxygenate. 
A detergent certified under this suboption is eligible to be used at a 
conforming LAC only in gasoline that is premium grade, contains no 
oxygenate component, and is ultimately dispensed in the selected PADD.
    (ii) PADD premium oxygenate-specific suboption. The requirements for 
certification under this suboption are the

[[Page 830]]

same as those in paragraph (b)(2) of this section, except that, pursuant 
to Sec. 80.164(a)(2)(iii), the certification test fuel shall contain an 
oxygenate compound other than ethanol. A detergent certified under this 
suboption is eligible to be used at a conforming LAC only in gasoline 
that is premium grade, contains no oxygenate component other than the 
one present in the test fuel, and is ultimately dispensed in the 
selected PADD.
    (c) Fuel-specific certification. Except as provided in paragraph 
(c)(3) of this section, to be certified under the fuel-specific 
certification option, a candidate detergent must meet the deposit 
control performance test requirements and standards specified in Sec. 
80.165 using test fuels that conform to the requirements of Sec. 
80.164(c).
    (1) A detergent certified under this option is eligible to be used 
at a conforming LAC only in the defined gasoline pool reported in the 
certification letter pursuant to Sec. 80.161(b)(3).
    (i) The gasoline pool may only include gasoline produced or 
distributed from the facilities covered by the fuel survey which was 
used to define the fuel-specific certification test fuels, pursuant to 
Sec. 80.164(c)(1).
    (ii) The gasoline pool must be kept segregated from any other 
gasoline prior to blending with the detergent additive.
    (iii) Depending on the oxygenate components added to the test fuel 
pursuant to Sec. 80.164(a)(2), the gasoline pool may be inclusive of 
all grades and all oxygenate blending characteristics (i.e., generic), 
or may be restricted to non-oxygenated gasoline, or to gasoline 
containing a specific oxygenate compound. The certification may also be 
restricted to premium grade gasoline. Any such use restrictions must be 
specified in the certification letter. Provisions in Sec. Sec. 80.168 
and 80.171(a)(9) through (12) related to such use restrictions also 
apply.
    (2) Detergent certification under this option entails special 
initial and annual reporting requirements, specified under Sec. Sec. 
80.161(b)(3)(vi) and 80.164(c)(3), which necessitate that the 
responsible party have control over and access to the segregated 
gasoline pool for which the detergent is certified. For this reason, the 
certifying party under this option is likely to be (but is not required 
to be) a fuel manufacturer or detergent blender, rather than the 
additive manufacturer.
    (3) If a certifier demonstrates that the required test fuel 
representing a segregated pool of gasoline meets the deposit control 
performance standards specified in Sec. 80.165 in the absence of a 
detergent additive, or using a detergent additive which has only PFID-
control activity, then this gasoline pool (and PFID detergent, if 
applicable) can be certified accordingly under the fuel-specific option.
    (4) Gasoline properly additized with a detergent certified under the 
fuel-specific option may be transferred or sold anywhere within the 
United States and its territories (subject to approved State programs).
    (d) CARB-Based Certification. A valid certification under section 
2257 of Title 13, California Code of Regulations (CARB certification) 
may be the basis for a certification under the following restrictions 
and conditions:
    (1) A detergent certified under this option may be used at the LAC 
specified in the CARB certification only in gasoline that meets the 
requirements of California Phase II reformulated gasoline (pursuant to 
Title 13, Chapter 5, Article 1, Subarticle 2, California Code of 
Regulations, Standards for Gasoline Sold Beginning March 1, 1996). The 
grade(s) of California gasoline which may be so additized, and the 
oxygenate(s) which may be present, are as specified in the CARB 
certification for the detergent in question.
    (2) The gasoline must be either: Additized in California; or sold or 
dispensed to the ultimate consumer in California (or to parties who sell 
or dispense to the ultimate consumer in California); or both additized 
and ultimately dispensed in California.
    (3) A certification under this option will continue to be valid only 
as long as the CARB certification remains valid. The certifier must 
cease selling or using a detergent immediately upon being notified by 
CARB that the CARB certification for this detergent has been 
invalidated, and must notify EPA

[[Page 831]]

within 7 days of receipt of this notification.

[61 FR 35368, July 5, 1996]



Sec. 80.164  Certification test fuels.

    (a) General requirements. This section provides specifications for 
the test fuels required in conjunction with the certification options 
described in Sec. 80.163. For each such certification option, the 
associated test fuel must meet or exceed the levels of four basic fuel 
parameters (aromatics, fuel sulfur, olefins, and T-90) prescribed here 
and may also contain specified oxygenate compounds. In addition, 
pursuant to paragraph (b)(3) of this section, some fuels must undergo an 
IVD demonstration test before they are eligible to be used as test fuels 
under this certification program. Test fuel characteristics must be 
reported to EPA in the detergent certification letter required pursuant 
to Sec. 80.161(b)(3).
    (1) Quantitative specifications for the four basic fuel parameters, 
provided in paragraphs (b) and (c) of this section, refer to the levels 
of these parameters in the base gasoline prior to the addition of any 
oxygenate. The levels of the basic fuel parameters must be measured in 
accordance with applicable procedures in Sec. 80.46.
    (2) Oxygenate components of certification test fuels must be of fuel 
grade quality. The type and amount of oxygenate to be blended into the 
test fuel (if any) shall be as follows:
    (i) To certify a detergent for generic use (i.e., for use in 
gasoline containing any oxygenate compound, as well as for use in 
nonoxygenated gasoline), the finished test fuel shall contain ethanol at 
10 volume percent.
    (ii) To certify a detergent specifically for use in nonoxygenated 
gasoline, no oxygenate compounds shall be added to the test fuel.
    (iii) To certify a detergent specifically for use in gasoline 
blended with a specified oxygenate compound other than ethanol, the 
specified oxygenate must be added to the test fuel in an amount such 
that the finished fuel contains the oxygenate at the highest 
concentration at which the specific oxygenate may be used in in-use 
gasoline.
    (3) No detergent-active substance other than the detergent additive 
package undergoing testing may be added to a certification test fuel. 
Typical nondetergent additives, such as antioxidants, corrosion 
inhibitors, and metal deactivators, may be present in the test fuel at 
the discretion of the additive certifier. In addition, any nondetergent 
additives (other than oxygenate compounds) which are commonly blended 
into gasoline and which are known or suspected to affect IVD or PFID 
formation, or to reduce the ability of the detergent in question to 
control such deposits, should be added to the test fuel for 
certification testing.
    (4) Certification test requirements may be satisfied for a detergent 
additive using more than one batch of test fuel, provided that each 
batch satisfies all applicable test fuel requirements under this 
section.
    (5) Unless otherwise required by this section, finished test fuels 
must conform to the requirements for commercial gasoline described in 
ASTM D 4814-95c, ``Standard Specification for Automotive Spark-Ignition 
Engine Fuel'', which is incorporated by reference. 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 
inspected at U.S. EPA, OAR, 401 M St., 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. Copies of this material may be obtained 
from ASTM, 1916 Race St., Philadelphia, PA 19103.
    (b) National and PADD certification test fuels. (1) Test fuels for 
the national generic and premium certification options must contain 
levels of the designated fuel parameters which meet or exceed the 
applicable values in Table 1. Test fuels for the PADD generic 
certification options must contain levels of the designated fuel 
parameters which meet or exceed the applicable values in Table 2. Test 
fuels for the PADD premium certification options must contain levels of 
the designated fuel parameters which meet or exceed the applicable 
values in Table 3. Oxygenate

[[Page 832]]

requirements for the respective nonoxygenate and oxygenate-specific 
suboptions are specified in paragraph (a)(2) of this section.

                                   Table 1--National Certification Test Fuels
----------------------------------------------------------------------------------------------------------------
                                                       Required minimum fuel parameter values
                                  ------------------------------------------------------------------------------
       Certification option           Sulfur                   Olefins     Aromatics
                                    (weight %)    T-90 (F)    (volume %)   (volume %)     Oxygenate (volume %)
----------------------------------------------------------------------------------------------------------------
 1. National Generic.............        0.034          339         11.4         31.1  10% Ethanol.
2. National Premium..............        0.016          332          6.5         35.9
----------------------------------------------------------------------------------------------------------------


                             Table 2--PADD-Specific Generic Certification Test Fuels
----------------------------------------------------------------------------------------------------------------
                                                       Required minimum fuel parameter values
                                  ------------------------------------------------------------------------------
       Certification option           Sulfur                   Olefins     Aromatics
                                    (weight %)    T-90 (F)    (volume %)   (volume %)     Oxygenate (volume %)
----------------------------------------------------------------------------------------------------------------
PADD 1 Generic...................        0.039          343         15.4         32.1
PADD 2 Generic...................        0.034          338         10.3         29.3
PADD 3 Generic...................        0.032          343         12.9         29.8  10% Ethanol.
PADD 4 Generic...................        0.050          326         10.0         27.1
PADD 5 Generic...................        0.021          337          7.6         34.5
----------------------------------------------------------------------------------------------------------------


                          Table 3--PADD-Specific Premium-Grade Certification Test Fuels
----------------------------------------------------------------------------------------------------------------
                                                       Required minimum fuel parameter values
                                  ------------------------------------------------------------------------------
       Certification option           Sulfur                   Olefins     Aromatics
                                    (weight %)    T-90 (F)    (volume %)   (volume %)     Oxygenate (volume %)
----------------------------------------------------------------------------------------------------------------
PADD 1 Premium...................        0.018          332          9.2         38.6
PADD 2 Premium...................        0.014          333          6.0         34.3
PADD 3 Premium...................        0.015          334          6.0         34.6  10% Ethanol.
PADD 4 Premium...................        0.040          319          6.0         22.3
PADD 5 Premium...................        0.011          332          4.3         36.7
----------------------------------------------------------------------------------------------------------------

    (2) National and PADD certification test fuels must either be 
formulated to specification from normal refinery blend stocks, or drawn 
from finished gasoline supplies. The source of such samples must be 
normally-operating gasoline production or distribution facilities 
located in the U.S. Samples must not be drawn from a segregated gasoline 
pool that is or will be covered by a fuel-specific certification under 
Sec. 80.163(c) on the date when the certification information under 
this option is submitted to EPA.
    (3) To be eligible for use in detergent additive certification 
testing, in addition to the specifications above, national and PADD test 
fuels which are specially formulated from refinery blend stocks must 
themselves undergo testing to demonstrate their deposit-forming 
tendency. For this purpose, the unadditized, nonoxygenated test fuel 
must be subjected to the IVD control test procedure described in Sec. 
80.165(b). At the discretion of the tester, the duration of the 
demonstration test may be less than 10,000 miles, provided the results 
satisfy the standard of this paragraph. In order to qualify for use in 
certification testing, the formulated fuel's test results must meet or 
exceed the values shown in Table 4 for the relevant certification 
option. If the demonstration test results do not meet these criteria, 
then the formulated fuel may not be used for detergent certification 
testing.

                                    Table 4--IVD Demonstration Test Criteria
----------------------------------------------------------------------------------------------------------------
                                        Minimum required deposit level in IVD demonstration test  (mg/valve,
                                                                      average)
       Certification option        -----------------------------------------------------------------------------
                                      National      PADD 1       PADD 2       PADD 3       PADD 4       PADD 5
----------------------------------------------------------------------------------------------------------------
Generic...........................          290          290          260          290          260          260

[[Page 833]]

 
Premium...........................          260          260          235          260          235          235
----------------------------------------------------------------------------------------------------------------

    (c) Fuel-specific certification test fuels. (1) Test fuels required 
for fuel-specific certification must contain levels of each of the four 
basic fuel parameters (aromatics, olefins, T-90, and fuel sulfur) at no 
less than their respective 65th percentile values in the segregated 
gasoline pool for which the detergent certification is sought in 
accordance with Sec. 80.163(c). These values must be determined by the 
certifier as follows:
    (i) At least once monthly for at least one complete year prior to 
the certification, the certifier must measure the levels of the required 
parameters in representative fuel samples contributed to the segregated 
gasoline pool by each participating refinery, terminal, or other fuel 
production or distribution facility. The fuel parameters must be 
measured in accordance with the test procedures in Sec. 80.46. If the 
applicability of the fuel-specific certification is to be limited to 
premium gasoline, then the required fuel compositional data must be 
collected only from samples of premium gasoline.
    (ii) The fuel composition survey results, weighted according to the 
percentage of gasoline contributed to the segregated gasoline pool from 
each participating facility, shall be used to construct a percentile 
distribution of the measured values for each of the fuel parameters.
    (iii) Data from more than one year may be used to construct the 
required statistical distribution provided that only the total data from 
complete consecutive years is used and that all survey data must have 
been collected within three years of the date the certification 
information is submitted to EPA.
    (iv) At the discretion of the certifier, other fuel parameters may 
be used to define the certification test fuels in addition to the four 
required parameters. To be taken into account by EPA in case of 
confirmatory testing pursuant to Sec. 80.167, such additional 
parameters must be surveyed and analyzed according to the same 
requirements applicable to the four standard parameters. In addition, 
any optional parameters must be measured using test procedures which 
conform to reasonable and customary standards of repeatability and 
reproducibility, and reasonable and customary limits of detection and 
accuracy for the type of test procedure or analytic procedure in 
question.
    (v) Using the percentile distributions calculated from the survey 
data for the four required parameters and any additional discretionary 
parameters, the 65th percentile value for each such parameter shall be 
determined. Prior to the addition of any oxygenate compound, the fuel-
specific certification test fuel shall contain each specified parameter 
at a level or concentration no less than this 65th percentile value. 
Test fuel oxygenate requirements for generic, nonoxygenate, and 
oxygenate-specific certification suboptions are specified in paragraph 
(a)(2) of this section.
    (2) Fuel-specific certification test fuels must either be formulated 
to specification from the same refinery blend stocks which are normally 
used to blend the gasolines included in the subject gasoline pool, or 
drawn from the finished fuel supplies which contribute to this pool of 
gasoline. Fuel-specific certification test fuels need not undergo an IVD 
demonstration test prior to use in certification testing.
    (3) The certifier must submit an annual report to EPA within 30 days 
of the anniversary of the initial certification effective date. Failure 
to submit the annual report by the required date will invalidate the 
fuel-specific certification and may subject the certifier to liability 
and penalties under Sec. Sec. 80.169 and 80.172. The purpose of the 
annual report is to update the information on the composition of the 
segregated gasoline pool that was characterized by the initial fuel 
survey.

[[Page 834]]

    (i) For this purpose, the same fuel survey and statistical analysis 
requirements that were conducted pursuant to paragraphs (c)(1)(i),(ii), 
and (iv) of this section must be repeated, using data for the most 
current twelve-month period from each of the production/distribution 
facilities that contributed to the original fuel survey.
    (ii) The annual report must present the percentile distributions for 
each fuel parameter as determined from the new survey data and, for each 
measured fuel parameter, must compare the newly determined 50th 
percentile value with the 60th percentile value for that parameter as 
determined in the original fuel survey.
    (iii) If the new 50th percentile level for any fuel parameter is 
greater than or equal to the 60th percentile level reported in the 
initial certification, then the fuel-specific certification is no longer 
valid. In such instance, the certifier must immediately discontinue the 
sale and use of the subject detergent under the conditions of the fuel-
specific certification and must immediately notify any downstream 
customers/recipients of the subject detergent that the certification is 
no longer valid and that their use of the detergent must discontinue 
within seven days. To avoid liability and penalties under Sec. Sec. 
80.169 and 80.172, the certifier must take these remedial steps within 
45 days of the anniversary of the original fuel-specific certification. 
Downstream customers/recipients must discontinue usage of the detergent 
within seven days of receipt of notification of the detergent's 
invalidity to avoid such liability.
    (4) The fuel composition survey results which support the original 
test fuel specifications and the annual statistical analyses, along with 
related documentation on test methods and statistical procedures, shall 
be retained by the certifier for a period of at least five years, and 
shall be made available to EPA upon request.

[61 FR 35369, July 5, 1996]



Sec. 80.165  Certification test procedures and standards.

    This section specifies the deposit control test requirements and 
performance standards which must be met in order to certify detergent 
additives for use in unleaded gasoline, pursuant to Sec. 
80.161(b)(1)(ii)(A)(2). These standards must be met in the context of 
the specific test procedures identified in paragraphs (a) and (b) of 
this section, except as provided in paragraph (c) of this section. In 
any case, the testing must be conducted and the performance standards 
met when the subject detergent additive is mixed in a test fuel meeting 
all relevant requirements of Sec. 80.164, including the deposit-forming 
tendency demonstration specified in Sec. 80.164(b)(3), if applicable. 
Complete test documentation must be submitted by the certifying party 
within 30 days of receipt of a written request from EPA for such 
records.
    (a) Fuel injector deposit control testing. (1) The required test 
fuel must produce no more than 5% flow restriction in any one injector 
when tested in accordance with ASTM D 5598-94, ``Standard Test Method 
for Evaluating Unleaded Automotive Spark-Ignition Engine Fuel for 
Electronic Port Fuel Injector Fouling,'' 1994, which is incorporated by 
reference. 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 inspected at U.S. EPA, OAR, 401 M St., 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. 
Copies of this material may be obtained from ASTM, 1916 Race St., 
Philadelphia, PA 19103.
    (2) At the option of the certifier, fuel injector flow may be 
measured at intervals during the 10,000 mile test cycle described in 
ASTM D 5598-94, in addition to the flow measurements required at the 
completion of the test cycle, but not more than every 1,000 miles.
    (b) Intake valve deposit control testing. The required test fuel 
must produce the accumulation of less than 100 mg of intake valve 
deposits on average when tested in accordance with ASTM D 5500-94, 
``Standard Test Method for Vehicle Evaluation of Unleaded Automotive 
Spark-Ignition Engine Fuel for

[[Page 835]]

Intake Valve Deposit Formation,'' 1994, which is incorporated by 
reference. 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 inspected at U.S. EPA, OAR, 401 M St., 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. 
Copies of this material may be obtained from ASTM, 1916 Race St., 
Philadelphia, PA 19103.
    (c) If conducted using test fuels meeting all relevant requirements 
of Sec. 80.164, and completed prior to September 3, 1996, then the PFID 
and IVD control test procedures required for detergent certification in 
California (specified in section 2257 of Title 13, California Code of 
Regulations) will also be considered acceptable. California Air 
Resources Board, ``Test Method for Evaluating Port Fuel Injector (PFI) 
Deposits in Vehicle Engines'', March 1, 1991, and California Air 
Resources Board, ``BMW--10,000 Miles Intake Valve Test Procedure'', 
March 1, 1991, are incorporated by reference. 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 
inspected at U.S. EPA, OAR, 401 M St., 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. Copies of this material may be obtained 
from the California Air Resource Board, Stationary Source Division, 2020 
L Street, PO Box 2815, Sacramento, CA, 95814.

[61 FR 35371, July 5, 1996]



Sec. 80.166  Carburetor deposit control performance test and test
fuel guidelines.

    EPA will use the guidelines in this section to evaluate the adequacy 
of carburetor deposit control test data, used to support the minimum 
concentration recommended for detergents used in leaded gasoline 
pursuant to Sec. 80.161(b)(1)(ii)(B).
    (a) Carburetor Deposit Control Test Procedure and Performance 
Standard Guidelines. For demonstration of carburetor deposit control 
performance, any generally accepted vehicle, engine, or bench test 
procedure and associated performance standard for carburetor deposit 
control will be considered adequate. Port and throttle body fuel 
injector deposit control test data will also be considered to be 
adequate demonstration of an additive's ability to control carburetor 
deposits. Examples of acceptable test procedures for demonstration of 
carburetor deposit control, in addition to the fuel injector test 
procedure listed in Sec. 80.165(a), are contained in the following 
references:
    (1) ``Test Method for Evaluating Port Fuel Injector (PFI) Deposits 
in Vehicle Engines'', March 1, 1991, Section 2257, Title 13, California 
Code of Regulations.
    (2) ``A Vehicle Test Technique for Studying Port Fuel Injector 
Deposits--A Coordinating Research Council Program'', Robert Tupa et al., 
SAE Technical paper No. 890213, 1989.
    (3) ``The Effects of Fuel Composition and Additives on Multiport 
Fuel Injector Deposits'', Jack Benson et al., SAE Technical Paper Series 
No. 861533, 1986.
    (4) ``Injector Deposits--The Tip of Intake System Deposit 
Problems'', Brian Taneguchi, et al., SAE Technical Paper Series No. 
861534, 1986.
    (5) ``Fuel Injector, Intake Valve, and Carburetor Detergency 
Performance of Gasoline Additives'', C.H. Jewitt et al., SAE Technical 
Paper No. 872114, 1987.
    (6) ``Carburetor Cleanliness Test Procedure, State-of-the-Art 
Summary, Report: 1973-1981'', Coordinating Research Council, CRC Report 
No. 529, Coordinating Research Council Inc. (CRC), 219 perimeter Center 
Parking, Atlanta, Georgia, 30346.
    (b) Carburetor Deposit Control Test Fuel Guidelines. (1) The 
gasoline used in the tests described in paragraph (a) of this section 
must contain the detergent-active components of the subject detergent 
additive package in an

[[Page 836]]

amount which corresponds to the minimum recommended concentration 
recorded in the respective detergent registration, or less than this 
amount.
    (2) The test fuel must not contain any detergent-active components 
other than those recorded in the subject detergent certification.
    (3) The composition of the test fuel used in carburetor deposit 
control testing, conducted to support the claimed effectiveness of 
detergents used in leaded gasoline, should be reasonably typical of in-
use gasoline in its tendency to form carburetor deposits (or more severe 
than typical in-use fuels) as defined by the olefin and sulfur content. 
A test fuel conforming to these compositional guidelines may be sampled 
directly from finished gasolines or may be blended to specification 
using typical refinery blend stocks. Test data using leaded fuels is 
preferred for this purpose, but data collected using unleaded fuels may 
also be acceptable provided that some correlation with additive 
performance in leaded fuels is available.

[61 FR 35372, July 5, 1996]



Sec. 80.167  Confirmatory testing.

    EPA may test a detergent to confirm that the required performance 
levels are met. Based on the findings of this confirmatory testing, a 
detergent certification may be denied or revoked under the provisions of 
Sec. 80.161(e).
    (a) Confirmatory testing conducted to evaluate the validity of 
detergent certifications under the national, PADD, or fuel-specific 
options will generally entail a single vehicle test using the procedures 
detailed in Sec. 80.165. The test fuel(s) used in conducting 
confirmatory certification testing will contain the specified fuel 
parameters at or below the minimum levels specified in Sec. 80.164, and 
will otherwise conform to the applicable certification test fuel 
specifications therein.
    (b) Confirmatory certification testing conducted to evaluate the 
validity of CARB-based detergent certifications will use the subject 
detergent in test fuel(s) containing the relevant fuel parameters at 
levels no greater than the maximum levels for which the CARB 
certification was granted. The test procedures will be conducted 
pursuant to the procedures specified under section 2257 of Title 13, 
California Code of Regulations.
    (c) Confirmatory testing conducted to evaluate the validity of 
registration and certification information specific to detergent use in 
leaded gasoline will use the subject detergent in a test fuel containing 
the test fuel parameters at levels no greater than those prescribed in 
Sec. 80.164. EPA will make all reasonable efforts to use the same test 
procedure for confirmatory testing purposes as was used by the certifier 
in conducting deposit control performance testing.
    (d) When EPA decides to conduct confirmatory testing on a fuel or 
additive which is not readily available in the open market, EPA may 
request that the detergent certifier and/or manufacturer of such fuel or 
additive furnish a sample in the needed quantity. If testing is 
conducted to evaluate the validity of a detergent certification under 
the fuel-specific option, the detergent blender must supply EPA with 
test fuel, or with blend stocks with which to formulate such test fuel, 
in sufficient quantity to conduct the specified deposit control 
performance testing. The fuel or additive manufacturer shall comply with 
a sample request made pursuant to this paragraph within 30 days of 
receipt of the request.

[61 FR 35372, July 5, 1996]



Sec. 80.168  Detergent certification program controls and prohibitions.

    (a)(1) No person shall sell, offer for sale, dispense, supply, offer 
for supply, transport, or cause the transportation of gasoline to the 
ultimate consumer for use in motor vehicles or in any off-road engines 
(except as provided in Sec. 80.173), or to a gasoline retailer or 
wholesale purchaser-consumer, and no person shall detergent-additize 
gasoline, unless such gasoline is additized in conformity with the 
requirements of Sec. 80.161. No person shall cause the presence of any 
gasoline in the gasoline distribution system unless such gasoline is 
additized in conformity with the requirements of Sec. 80.161.
    (2) Gasoline has been additized in conformity with the requirements 
of Sec. 80.161 when the detergent component

[[Page 837]]

satisfies the requirements of Sec. 80.161 and when:
    (i) The gasoline has been additized in conformity with the detergent 
composition and purpose-in-use specifications of a detergent certified 
in accordance with this subpart, and in accordance with at least the 
minimum concentration specifications of that detergent as certified or 
as otherwise provided under Sec. 80.161(d); or
    (ii) The gasoline is composed of two or more commingled gasolines 
and each component gasoline has been additized in conformity with the 
detergent composition and purpose-in-use specifications of a detergent 
certified in accordance with this subpart, and in accordance with at 
least the minimum concentration specifications of that detergent as 
certified or as otherwise provided under Sec. 80.161(d); or
    (iii) The gasoline is composed of a gasoline commingled with a post-
refinery component (PRC), and both of these components have been 
additized in conformity with the detergent composition and use 
specifications of a detergent certified in accordance with this subpart, 
and in accordance with at least the minimum concentration specifications 
of that detergent as certified or as otherwise provided under Sec. 
80.161(d).
    (b) No person shall blend detergent into gasoline or PRC unless such 
person complies with the volumetric additive reconciliation requirements 
of Sec. 80.170.
    (c) No person shall sell, offer for sale, dispense, supply, offer 
for supply, store, transport, or cause the transportation of any 
gasoline, detergent, or detergent-additized PRC, unless the product 
transfer document for the gasoline, detergent or detergent-additized PRC 
complies with the requirements of Sec. 80.171.
    (d) No person shall refine, import, manufacture, sell, offer for 
sale, dispense, supply, offer for supply, store, transport, or cause the 
transportation of any detergent that is to be used as a component of 
detergent-additized gasoline or detergent-additized PRC unless such 
detergent conforms with the composition specifications of a detergent 
certified in accordance with this subpart and the detergent otherwise 
complies with the requirements of Sec. 80.161. No person shall cause 
the presence of any detergent in the detergent, PRC, or gasoline 
distribution systems unless such detergent complies with the 
requirements of Sec. 80.161.
    (e)(1) No person shall sell, offer for sale, dispense, supply, offer 
for supply, transport, or cause the transportation of detergent-
additized PRC unless the PRC has been additized in conformity with the 
requirements of Sec. 80.161. No person shall cause the presence in the 
PRC or gasoline distribution systems of any detergent-additized PRC that 
fails to conform to the requirements of Sec. 80.161.
    (2) PRC has been additized in conformity with the requirements of 
Sec. 80.161 when the detergent component satisfies the requirements of 
Sec. 80.161 and when:
    (i) The PRC has been additized in accordance with the detergent 
composition and use specifications of a detergent certified in 
accordance with this subpart and in conformity with at least the minimum 
concentration specifications of that detergent as certified or as 
otherwise provided under Sec. 80.161(d), or
    (ii) The PRC is composed of two or more commingled PRCs, and each 
component has been additized in accordance with the detergent 
composition and use specifications of a detergent certified in 
accordance with this subpart, and in conformity with at least the 
minimum concentration specifications of that detergent as certified or 
as otherwise provided under Sec. 80.161(d).

[61 FR 35373, July 5, 1996]



Sec. 80.169  Liability for violations of the detergent certification
program controls and prohibitions.

    (a) Persons Liable--(1) Gasoline non-conformity. Where gasoline 
contained in any storage tank at any facility owned, leased, operated, 
controlled or supervised by any gasoline refiner, importer, carrier, 
distributor, reseller, retailer, wholesale purchaser-consumer, oxygenate 
blender, or detergent blender, is found in violation of any of the 
prohibitions specified in Sec. 80.168(a), the following persons shall 
be deemed in violation:

[[Page 838]]

    (i) Each gasoline refiner, importer, carrier, distributor, reseller, 
retailer, wholesale purchaser-consumer, oxygenate blender, or detergent 
blender, who owns, leases, operates, controls or supervises the facility 
(including, but not limited to, a truck or individual storage tank) 
where the violation is found;
    (ii) Each gasoline refiner, importer, distributor, reseller, 
retailer, wholesale purchaser-consumer, oxygenate blender, detergent 
manufacturer, distributor, or blender, who refined, imported, 
manufactured, sold, offered for sale, dispensed, supplied, offered for 
supply, stored, detergent additized, transported, or caused the 
transportation of the detergent-additized gasoline (or the base gasoline 
component, the detergent component, or the detergent-additized post-
refinery component of the gasoline) that is in violation, and each such 
party that caused the gasoline that is in violation to be present in the 
gasoline distribution system; and
    (iii) Each gasoline carrier who dispensed, supplied, stored, or 
transported any gasoline in the storage tank containing gasoline found 
to be in violation, and each detergent carrier who dispensed, supplied, 
stored, or transported the detergent component of any PRC or gasoline in 
the storage tank containing gasoline found to be in violation, provided 
that EPA demonstrates, by reasonably specific showings by direct or 
circumstantial evidence, that the gasoline or detergent carrier caused 
the violation.
    (2) Post-refinery component non-conformity. Where detergent-
additized PRC contained in any storage tank at any facility owned, 
leased, operated, controlled or supervised by any gasoline refiner, 
importer, carrier, distributor, reseller, retailer, wholesale purchaser-
consumer, oxygenate blender, detergent manufacturer, carrier, 
distributor, or blender, is found in violation of the prohibitions 
specified in Sec. 80.168(e), the following persons shall be deemed in 
violation:
    (i) Each gasoline refiner, importer, carrier, distributor, reseller, 
retailer, wholesale-purchaser consumer, oxygenate blender, detergent 
manufacturer, carrier, distributor, or blender, who owns, leases, 
operates, controls or supervises the facility (including, but not 
limited to, a truck or individual storage tank) where the violation is 
found;
    (ii) Each gasoline refiner, importer, distributor, reseller, 
retailer, wholesale purchaser-consumer, oxygenate blender, detergent 
manufacturer, distributor, or blender, who sold, offered for sale, 
dispensed, supplied, offered for supply, stored, detergent additized, 
transported, or caused the transportation of the detergent-additized PRC 
(or the detergent component of the PRC) that is in violation, and each 
such party that caused the PRC that is in violation to be present in the 
PRC or gasoline distribution systems; and
    (iii) Each carrier who dispensed, supplied, stored, or transported 
any detergent-additized PRC in the storage tank containing PRC that is 
in violation, and each detergent carrier who dispensed, supplied, 
stored, or transported the detergent component of any detergent-
additized PRC which is in the storage tank containing detergent-
additized PRC found to be in violation, provided that EPA demonstrates 
by reasonably specific showings by direct or circumstantial evidence, 
that the gasoline or detergent carrier caused the violation.
    (3) Detergent non-conformity. Where the detergent (prior to 
additization) contained in any storage tank or container found at any 
facility owned, leased, operated, controlled or supervised by any 
gasoline refiner, importer, carrier, distributor, reseller, retailer, 
wholesale purchaser-consumer, oxygenate blender, detergent manufacturer, 
carrier, distributor, or blender, is found in violation of the 
prohibitions specified in Sec. 80.168(d), the following persons shall 
be deemed in violation:
    (i) Each gasoline refiner, importer, carrier, distributor, reseller, 
retailer, wholesale purchaser-consumer, oxygenate blender, detergent 
manufacturer, carrier, distributor, or blender, who owns, leases, 
operates, controls or supervises the facility (including, but not 
limited to, a truck or individual storage tank) where the violation is 
found;
    (ii) Each gasoline refiner, importer, distributor, reseller, 
retailer, wholesale purchaser-consumer, oxygenate blender, detergent 
manufacturer, distributor, or blender, who sold, offered

[[Page 839]]

for sale, dispensed, supplied, offered for supply, stored, transported, 
or caused the transportation of the detergent that is in violation, and 
each such party that caused the detergent that is in violation to be 
present in the detergent, gasoline, or PRC distribution systems; and
    (iii) Each gasoline or detergent carrier who dispensed, supplied, 
stored, or transported any detergent which is in the storage tank or 
container containing detergent found to be in violation, provided that 
EPA demonstrates, by reasonably specific showings by direct or 
circumstantial evidence, that the gasoline or detergent carrier caused 
the violation.
    (4) Volumetric additive reconciliation. Where a violation of the 
volumetric additive reconciliation requirements established by Sec. 
80.168(b) has occurred, the following persons shall be deemed in 
violation:
    (i) Each detergent blender who owns, leases, operates, controls or 
supervises the facility (including, but not limited to, a truck or 
individual storage tank) where the violation has occurred; and
    (ii) Each gasoline refiner, importer, carrier, distributor, 
reseller, retailer, wholesale purchaser-consumer, or oxygenate blender, 
and each detergent manufacturer, carrier, distributor, or blender, who 
refined, imported, manufactured, sold, offered for sale, dispensed, 
supplied, offered for supply, stored, transported, or caused the 
transportation of the detergent-additized gasoline, the base gasoline 
component, the detergent component, or the detergent-additized PRC of 
the gasoline that is in violation, provided that EPA demonstrates, by 
reasonably specific showings by direct or circumstantial evidence, that 
such person caused the violation.
    (5) Product transfer document. Where a violation of Sec. 80.168(c) 
is found at a facility owned, leased, operated, controlled, or 
supervised by any gasoline refiner, importer, carrier, distributor, 
reseller, retailer, wholesale purchaser-consumer, oxygenate blender, 
detergent manufacturer, carrier, distributor, or blender, the following 
persons shall be deemed in violation: each gasoline refiner, importer, 
carrier, distributor, reseller, retailer, wholesale purchaser-consumer, 
oxygenate blender, detergent manufacturer, carrier, distributor, or 
blender, who owns, leases, operates, control or supervises the facility 
(including, but not limited to, a truck or individual storage tank) 
where the violation is found.
    (b) Branded Refiner Vicarious Liability. Where any violation of the 
prohibitions specified in Sec. 80.168 has occurred, with the exception 
of violations of Sec. 80.168(c), a refiner will also be deemed liable 
for violations occurring at a facility operating under such refiner's 
corporate, trade, or brand name or that of any of its marketing 
subsidiaries. For purposes of this section, the word facility includes, 
but is not limited to, a truck or individual storage tank.
    (c) Defenses. (1) In any case in which a gasoline refiner, importer, 
distributor, carrier, reseller, retailer, wholesale purchaser-consumer, 
oxygenate blender, detergent distributor, carrier, or blender, is in 
violation of any of the prohibitions of Sec. 80.168, pursuant to 
paragraph (a) or (b) of this section as applicable, the regulated party 
shall be deemed not in violation if it can demonstrate:
    (i) That the violation was not caused by the regulated party or its 
employee or agent (unless otherwise provided in this paragraph (c));
    (ii) That product transfer documents account for the gasoline, 
detergent, or detergent-additized PRC in violation and indicate that the 
gasoline, detergent, or detergent-additized PRC satisfied relevant 
requirements when it left the party's control; and
    (iii) That the party has fulfilled the requirements of paragraphs 
(c) (2) or (3) of this section, as applicable.
    (2) Branded refiner. Where a branded refiner is in violation of any 
of the prohibitions of Sec. 80.168 as a result of violations occurring 
at a facility (including, but not limited to, a truck or individual 
storage tank) which is operating under the corporate, trade or brand 
name of a refiner or that of any of its marketing subsidiaries, the 
refiner shall be deemed not in violation if it can demonstrate, in 
addition to the defense requirements stated in paragraph (c)(1) of this 
section, that the violation was caused by:

[[Page 840]]

    (i) An act in violation of law (other than these regulations), or an 
act of sabotage or vandalism, whether or not such acts are violations of 
law in the jurisdiction where the violation of the prohibitions of Sec. 
80.168 occurred; or
    (ii) The action of any gasoline refiner, importer, reseller, 
distributor, oxygenate blender, detergent manufacturer, distributor, 
blender, or retailer or wholesale purchaser-consumer supplied by any of 
these persons, in violation of a contractual undertaking imposed by the 
refiner designed to prevent such action, and despite the implementation 
of an oversight program, including, but not limited to, periodic review 
of product transfer documents by the refiner to ensure compliance with 
such contractual obligation; or
    (iii) The action of any gasoline or detergent carrier, or other 
gasoline or detergent distributor not subject to a contract with the 
refiner but engaged by the refiner for transportation of gasoline, PRC, 
or detergent, to a gasoline or detergent distributor, oxygenate blender, 
detergent blender, gasoline retailer or wholesale purchaser consumer, 
despite specification or inspection of procedures or equipment by the 
refiner which are reasonably calculated to prevent such action.
    (iv) In this paragraph (c)(2), to show that the violation ``was 
caused'' by any of the specified actions, the party must demonstrate by 
reasonably specific showings, by direct or circumstantial evidence, that 
the violation was caused or must have been caused by another.
    (3) Detergent blender. In any case in which a detergent blender is 
liable for violating any of the prohibitions of Sec. 80.168, the 
detergent blender shall not be deemed in violation if it can 
demonstrate, in addition to the defense requirements stated in paragraph 
(c)(1) of this section, the following:
    (i) That it obtained or supplied, as appropriate, prior to the 
detergent blending, accurate written instructions from the detergent 
manufacturer or other party with knowledge of such instructions, 
specifying the appropriate LAC for the detergent, as specified in Sec. 
80.161(b)(1)(ii), together with any use restrictions which pertain to 
this LAC pursuant to the detergent's certification; and
    (ii) That it has implemented a quality assurance program that 
includes, but is not limited to, a periodic review of its supporting 
product transfer and volume measurement documents to confirm the 
correctness of its product transfer and volumetric additive 
reconciliation documents created for all products it additized.
    (4) Detergent manufacturer. (i) Presumptive Liability Affirmative 
Defense. Notwithstanding the provisions of paragraph (c)(1) of this 
section, in any case in which a detergent manufacturer is liable for 
violating any of the prohibitions of Sec. 80.168, the detergent 
manufacturer shall be deemed not in violation if it can demonstrate each 
of the following:
    (A) Product transfer documents which account for the detergent 
component of the product in violation and which indicate that such 
detergent satisfied all relevant requirements when it left the detergent 
manufacturer's control.
    (B) Written blending instructions which, pursuant to Sec. 
80.161(c), were supplied by the detergent manufacturer to its customer 
who purchased or obtained from the manufacturer the detergent component 
of the product determined to be in violation. The written blending 
instructions must have been supplied by the manufacturer prior to the 
customer's use or sale of the detergent. The instructions must 
accurately specify both the appropriate LAC for the detergent, pursuant 
to Sec. 80.161(b)(1)(ii), plus any use restrictions which may pertain 
to this LAC pursuant to the detergent's certification.
    (C) If the detergent batch used in the noncomplying product was 
produced less than one year before the manufacturer was notified by EPA 
of the possible violation, then the manufacturer must provide FTIR test 
results for the batch in question.
    (1) The FTIR analysis may have been conducted on the subject 
detergent batch at the time it was manufactured, or may be conducted on 
a sample of that batch which the manufacturer retained for such purpose 
at the time the batch was manufactured.
    (2) To establish that, when it left the manufacturer's control, the 
detergent

[[Page 841]]

component of the noncomplying product was in conformity with the 
chemical composition and concentration specifications reported pursuant 
to Sec. 80.161(b), the FTIR test results for the detergent batch used 
in the noncomplying product must be consistent with the FTIR results 
submitted at the time of registration pursuant to Sec. 80.162(d).
    (D) If the detergent batch used in the noncomplying product was 
produced more than one year prior to the manufacturer's notification by 
EPA of the possible violation, then the manufacturer must provide 
either:
    (1) FTIR test results for the batch in question as specified in the 
preceding paragraph (c)(4)(i)(C) of this Sec. 80.169(c); or
    (2) The following materials:
    (i) Documentation for the batch in question, showing that its 
measured viscosity, density, and basic nitrogen content, or any other 
such physical parameter(s) which EPA may have approved for monitoring 
production quality control, were within the acceptable range of 
production values specified in the certification pursuant to Sec. 
80.162(e); and
    (ii) If the detergent registration identifies polymeric component(s) 
of the detergent package as the product(s) of other chemical reactants, 
documentation that the reagents used to synthesize the detergent batch 
in question were the same as those specified in the registration and 
that they met the manufacturer's normal acceptance criteria reported 
pursuant to Sec. 80.162(b)(1).
    (ii) Detergent manufacturer causation liability. In any case in 
which a detergent manufacturer is liable for a violation of Sec. 
80.168, and the manufacturer establishes an affirmative defense to such 
liability pursuant to Sec. 80.169(c)(4)(i), the detergent manufacturer 
will nonetheless be deemed liable for the violation of Sec. 80.168 if 
EPA can demonstrate, by reasonably specific showings by direct or 
circumstantial evidence, that the detergent manufacturer caused the 
violation.
    (5) Defense against liability where more than one party may be 
liable for VAR violations. In any case in which a party is presumptively 
or vicariously liable for a violation of Sec. 80.170, except for the 
VAR record requirements pursuant to Sec. 80.170(g), such party shall 
not be deemed liable if it can establish the following:
    (i) Prior to the violation it had entered into a written contract 
with another potentially liable detergent blender party (``the assuming 
party''), under which that other party assumed legal responsibility for 
fulfilling the VAR requirement that had been violated;
    (ii) The contract included reasonable oversight provision to ensure 
that the assuming party fulfilled its VAR responsibilities (including, 
but not limited to, periodic review of VAR records) and the oversight 
provision was actually implemented by the party raising the defense;
    (iii) The assuming party is fiscally sound and able to pay its 
penalty for the VAR violation; and
    (iv) The employees or agents of the party raising the defense did 
not cause the violation.
    (6) Defense to liability for gasoline non-conformity violations 
caused solely by the addition of misadditized ethanol or other PRC to 
the gasoline. In any case in which a party is presumptively or 
vicariously liable for a gasoline non-conformity violation of Sec. 
80.168(a) caused solely by another party's addition of misadditized 
ethanol or other PRC to the gasoline, the former party shall not be 
deemed liable for the violation, provided that it can establish that it 
has fulfilled the defense requirements of paragraphs (c)(1) (i) and (ii) 
of this section.
    (7) Detergent tank transitioning defenses. The commingling of two 
detergents in the same detergent storage tank will not be deemed to 
violate or cause violations of any of the provisions of this subpart, 
provided the following conditions are met:
    (i) The commingling must occur during a legitimate detergent 
transitioning event, i.e., a shift from the use of one detergent to 
another through the delivery of the new detergent into the same tank 
that contains the original detergent; and
    (ii) Any use restrictions applicable to the new detergent's 
certification also apply to the combined detergents; and

[[Page 842]]

    (iii) The commingling event must be documented, either on the VAR 
formula record or on attached supporting records; and
    (iv) Notwithstanding any contrary provisions in Sec. 80.170, a VAR 
formula record must be created for the combined detergents. The VAR 
compliance period must begin no later than the time of the commingling 
event. However, at the blender's option, the compliance period may begin 
earlier, thus including use of the uncombined original detergent within 
the same period, provided that the 31-day limitation pursuant to Sec. 
80.170(a)(6) is not exceeded; and
    (v) The VAR formula record must also satisfy the requirements in one 
of the following paragraphs (c)(7)(v) (A) through (C) of this section, 
whichever applies to the commingling event. If neither paragraph 
(c)(7)(v) (A) nor (B) of this section initially applies, then the 
blender may drain and subsequently redeliver the original detergent into 
the tank in restricted amounts, in order to meet the conditions of 
paragraph (c)(7)(v) (A) or (B) of this section. Otherwise, the blender 
must comply with paragraph (c)(7)(v)(C) of this section.
    (A) If both detergents have the same LAC, and the original detergent 
accounts for no more than 20 percent of the tank's total delivered 
volume after addition of the new detergent, then the VAR formula record 
is required to identify only the use of the new detergent.
    (B) If the two detergents have different LACs and the original 
detergent accounts for 10 percent or less of the tank's total delivered 
volume after addition of the new detergent, then the VAR formula record 
is required to identify only the use of the new detergent, and must 
attain the LAC of the new detergent. If the original detergent's LAC is 
greater than that of the new detergent, then the compliance period may 
begin earlier than the date of the commingling event (pursuant to 
paragraph (c)(7)(iv) of this section) only if the original detergent 
does not exceed 10 percent of the total detergent used during the 
compliance period.
    (C) If neither of the preceding paragraphs (c)(7)(v) (A) or (B) of 
this section applies, then the VAR formula record must identify both of 
the commingled detergents, and must use and attain the higher LAC of the 
two detergents. Once the commingled detergent has been depleted by an 
amount equal to the volume of the original detergent in the tank at the 
time the new detergent was added, subsequent VAR formula records must 
identify and use the LAC of only the new detergent.
    (8) Transition from noncertified to certified detergent. 
Notwithstanding the prohibitions in Sec. Sec. 80.161(a)(3) and 80.168, 
after June 30, 1997, the addition to gasoline or PRC of a detergent 
which has not been certified pursuant to Sec. 80.161 shall not be 
deemed to violate or cause violations of provisions of this subpart, 
provided that all of the following conditions are met:
    (i) The detergent was received by the detergent blender prior to 
July 1, 1997 and is used prior to January 1, 1998. Documentation which 
supports these dates must be maintained for at least five years and must 
be available for EPA's inspection upon request;
    (ii) The detergent is added to gasoline or PRC only in combination 
with a certified detergent and, at any one time, accounts for no more 
than 10 percent of the detergent tank's delivered volume;
    (iii) The total volume of detergent added to the gasoline or PRC is 
sufficient to attain the LAC of the certified detergent; and
    (iv) Use restrictions associated with the certified detergent are 
adhered to.
    (9) Procedures for curing use restrictions. In the case of a fuel 
product which has been additized with a detergent under the conditions 
of a use-restricted certification (pursuant to Sec. 80.163), the use 
restriction can be negated (``cured'') by application of the procedures 
in this paragraph (c)(9). A party shall not be liable for violations of 
Sec. 80.168(a) or (e) caused solely by the additization or subsequent 
use of gasoline or PRC in violation of such use restriction, provided 
that the following steps and conditions are applied before EPA has 
identified the nonconformity and prior to the sale or transfer of 
nonconforming product to the ultimate consumer:

[[Page 843]]

    (i) Additional detergent must be added in sufficient quantity to 
provide effective deposit control, taking into account both the amount 
of detergent previously added and the final anticipated volume and 
composition of the subject fuel product.
    (ii) The additional detergent may be either the original detergent 
or a different detergent, so long as the additional detergent has been 
separately certified both for use with the subject fuel product and for 
use with the type of fuel product associated with the restriction which 
the party wishes to negate by the curing procedure. Detergents which 
have not been separately certified for both types of fuel products are 
not eligible to be used for this curing procedure.
    (iii) If a fuel product has been detergent additized under the 
conditions of a use-restricted certification which would preclude the 
addition of an oxygenate or other PRC, then such oxygenate or other PRC 
may nevertheless be added to that fuel product under this curing 
procedure, provided that additional eligible detergent is added, in an 
amount which equals or exceeds the number of gallons (DA) 
derived from the following equation:

Additional Detergent Volume = DA = Vp(LAC2 - 
    LAC1) + V(1 - p)LAC2

where:

V = Final volume of fuel product (in gallons)
p = Fraction of final fuel product composed of the original (uncombined) 
fuel product
LAC2 = Detergent's LAC certified for the final combined fuel 
product (in gallons of detergent per 1,000 gallons of fuel product)
LAC1 = Detergent's LAC certified for the original 
(uncombined) fuel product (in gallons of detergent per 1,000 gallons of 
fuel product)

    (iv) In other instances in which gasoline or PRC has been additized 
in violation of a detergent use restriction, and no additional fuel 
components are to be added, such use restriction can be cured by the 
addition of eligible detergent in an amount which equals or exceeds the 
number of gallons (DA) derived from the following equation, which is a 
simplified version of the previous equation:

Additional Detergent Volume = DA = V(LAC2 - 
    LAC1)

where:

V = Volume of fuel product (in gallons) to be cured of the use 
restriction
LAC2 = Detergent's LAC certified for the fuel product without 
the use restriction (in gallons of detergent per 1,000 gallons of fuel 
product)
LAC1 = Detergent's LAC certified for the fuel product with 
the use restriction to be cured (in gallons of detergent per 1,000 
gallons of fuel product)

    (v) In all such instances, a curing VAR must be created and 
maintained, which documents the use of the appropriate equation as 
specified above, and otherwise complies with the requirements of Sec. 
80.170(f)(6).

[61 FR 35373, July 5, 1996, as amended at 61 FR 58747, Nov. 18, 1996; 66 
FR 55890, Nov. 5, 2001]



Sec. 80.170  Volumetric additive reconciliation (VAR), equipment
calibration, and recordkeeping requirements.

    This section contains requirements for automated detergent blending 
facilities and hand-blending detergent facilities. All gasoline and all 
PRC intended for use in gasoline must be additized unless otherwise 
noted in supporting VAR records, and must be accounted for in VAR 
records. The VAR reconciliation standard is attained under this section 
when the actual concentration of detergent used per VAR formula record 
equals or exceeds the applicable LAC certified for that detergent 
pursuant to Sec. 80.161(b)(3)(ix) or, if appropriate, Sec. 80.161(d). 
If a given detergent package has been certified under more than one 
certification option pursuant to Sec. 80.163, then a separate VAR 
formula record must be created for gasoline or PRC additized on the 
basis of each certification and its respective LAC. In such cases, the 
amount of the detergent used under different certification options must 
be accurately and separately measured, either through the use of a 
separate storage tank, a separate meter, or some other measurement 
system that is able to accurately distinguish its use. Recorded volumes 
of gasoline, detergent, and PRC must be expressed to the nearest gallon 
(or smaller units), except that detergent volumes of five gallons or 
less must be expressed to the nearest tenth of a gallon (or smaller 
units). However, if the

[[Page 844]]

blender's equipment cannot accurately measure to the nearest tenth of a 
gallon, then such volumes must be rounded downward to the next lower 
gallon. PRC included in the reconciliation must be identified. Each VAR 
formula record must also contain the following information:
    (a) Automated blending facilities. In the case of an automated 
detergent blending facility, for each VAR period, for each detergent 
storage system and each detergent in that storage system, the following 
must be recorded:
    (1) The manufacturer and commercial identifying name of the 
detergent additive package being reconciled, the LAC, and any use 
restriction applicable to the LAC. The LAC must be expressed in terms of 
gallons of detergent per thousand gallons of gasoline or PRC, and 
expressed to four digits. If the detergent storage system which is the 
subject of the VAR formula record is a proprietary system under the 
control of a customer, this fact must be indicated on the record.
    (2) The total volume of detergent blended into gasoline and PRC, in 
accordance with one of the following paragraphs (a)(2)(i) or (ii) of 
this section, as applicable.
    (i) For a facility which uses in-line meters to measure detergent 
usage, the total volume of detergent measured, together with supporting 
data which includes one of the following: the beginning and ending meter 
readings for each meter being measured, the metered batch volume 
measurements for each meter being measured, or other comparable metered 
measurements. The supporting data may be supplied on the VAR formula 
record or in the form of computer printouts or other comparable VAR 
supporting documentation.
    (ii) For a facility which uses a gauge to measure the inventory of 
the detergent storage tank, the total volume of detergent shall be 
calculated from the following equation:

Detergent Volume = (A) - (B) + (C) - (D)

where:

A = Initial detergent inventory of the tank
B = Final detergent inventory of the tank
C = Sum of any additions to detergent inventory
D = Sum of any withdrawals from detergent inventory for purposes other 
than the additization of gasoline or PRC.


The value of each variable in this equation must be separately recorded 
on the VAR formula record. In addition, a list of each detergent 
addition included in variable C and a list of each detergent withdrawal 
included in variable D must be provided, either on the formula record or 
as VAR supporting documentation.
    (3) The total volume of gasoline plus PRC to which detergent has 
been added, together with supporting data which includes one of the 
following: the beginning and ending meter measurements for each meter 
being measured, the metered batch volume measurements for each meter 
being measured, or other comparable metered measurements. The supporting 
data may be supplied on the VAR formula record or in the form of 
computer printouts or other comparable VAR supporting documentation. If 
gasoline has intentionally been overadditized in anticipation of the 
later addition of unadditized PRC, then the total volume of gasoline 
plus PRC recorded must include the expected amount of unadditized PRC to 
be added later. In addition, the amount of gasoline which was 
overadditized for this purpose must be specified.
    (4) The actual detergent concentration, calculated as the total 
volume of detergent added (pursuant to paragraph (a)(2) of this 
section), divided by the total volume of gasoline plus PRC (pursuant to 
paragraph (a)(3) of this section). The concentration must be calculated 
and recorded to four digits.
    (5) A list of each detergent concentration rate initially set for 
the detergent that is the subject of the VAR record, together with the 
date and description of each adjustment to any initially set 
concentration. The concentration adjustment information may be supplied 
on the VAR formula record or in the form of computer printouts or other 
comparable VAR supporting documentation. No concentration setting is 
permitted below the applicable certified LAC, except as may be modified 
pursuant to Sec. 80.161(d) or as described in paragraph (a)(7) of this 
section.

[[Page 845]]

    (6) The dates of the VAR period, which shall be no longer than 
thirty-one days. If the VAR period is contemporaneous with a calendar 
month, then specifying the month will fulfill this requirement; if not, 
then the beginning and ending dates and times of the VAR period must be 
listed. The times may be supplied on the VAR formula record or in 
supporting documentation. Any adjustment to any detergent concentration 
rate more than 10 percent over the concentration rate initially set in 
the VAR period shall terminate that VAR period and initiate a new VAR 
period, except as provided in paragraph (a)(7) of this section.
    (7) The concentration setting for a detergent injector may be set 
below the applicable LAC, or it may be adjusted more than 10 percent 
above the concentration initially set in the VAR period without 
terminating that VAR period, provided that:
    (i) The purpose of the change is to correct a batch misadditization 
prior to the end of the VAR period and prior to the transfer of the 
batch to another party, or to correct an equipment malfunction; and
    (ii) The concentration is immediately returned after the correction 
to a concentration that fulfills the requirements of paragraphs (a) (5) 
and (6) of this section; and
    (iii) The blender creates and maintains documentation establishing 
the date and adjustments of the correction; and
    (iv) If the correction is initiated only to rectify an equipment 
malfunction, and the amount of detergent used in this procedure is not 
added to gasoline within the compliance period, then this amount is 
subtracted from the detergent volume listed on the VAR formula record.
    (8) If unadditized gasoline has been transferred from the facility, 
other than bulk transfers from refineries or pipelines to non-retail 
outlets or non-WPC facilities, the total amount of such gasoline must be 
specified.
    (b) Non-automated facilities. In the case of a facility in which 
hand blending or any other non-automated method is used to blend 
detergent, for each detergent and for each batch of gasoline and each 
batch of PRC to which the detergent is being added, the following shall 
be recorded:
    (1) The manufacturer and commercial identifying name of the 
detergent additive package being reconciled, the LAC, and any use 
restriction applicable to the LAC. The LAC must be expressed in terms of 
gallons of detergent per thousand gallons of gasoline or PRC, and 
expressed to four digits.
    (2) The date of the additization that is the subject of the VAR 
formula record.
    (3) The volume of added detergent.
    (4) The volume of the gasoline and/or PRC to which the detergent has 
been added. If gasoline has intentionally been overadditized in 
anticipation of the later addition of unadditized PRC, then the total 
volume of gasoline plus PRC recorded must include the expected amount of 
unadditized PRC to be added later. In addition, the amount of gasoline 
which was overadditized for this purpose must be specified.
    (5) The brand (if known), grade, and leaded/unleaded status of 
gasoline, and/or the type of PRC.
    (6) The actual detergent concentration, calculated as the volume of 
added detergent (pursuant to paragraph (b)(3) of this section), divided 
by the volume of gasoline and/or PRC (pursuant to paragraph (b)(4) of 
this section). The concentration must be calculated and recorded to four 
digits.
    (c) Every VAR formula record created pursuant to paragraphs (a) and 
(b) of this section shall contain the following:
    (1) The signature of the creator of the VAR record;
    (2) The date of the creation of the VAR record; and
    (3) A certification of correctness by the creator of the VAR record.
    (d) Electronically-generated VAR formula and supporting records.
    (1) Electronically-generated records are acceptable for VAR formula 
records and supporting documentation (including PTDs), provided that 
they are complete, accessible, and easily readable. VAR formula records 
must also be stored with access and audit security, which must restrict 
to a limited number of specified people those who have the ability to 
alter or delete the

[[Page 846]]

records. In addition, parties maintaining records electronically must 
make available to EPA the hardware and software necessary to review the 
records.
    (2) Electronically-generated VAR formula records may use an 
electronic user identification code to satisfy the signature 
requirements of paragraph (c)(1) of this section, provided that:
    (i) The use of the ID is limited to the record creator; and
    (ii) A paper record is maintained, which is signed and dated by the 
VAR formula record creator, acknowledging that the use of that 
particular user ID on a VAR formula record is equivalent to his/her 
signature on the document.
    (e) Automated detergent blenders must calibrate their detergent 
equipment once in each calendar half year, with the acceptable 
calibrations being no less than one hundred twenty days apart. Equipment 
recalibration is also required each time the detergent package is 
changed, unless written documentation indicates that the new detergent 
package has the same viscosity as the previous detergent package. 
Detergent package change calibrations may be used to satisfy the 
semiannual requirement provided that the calibrations occur in the 
appropriate half calendar year and are no less than one hundred twenty 
days apart.
    (f) The following VAR supporting documentation must also be created 
and maintained:
    (1) For all automated detergent blending facilities, documentation 
reflecting performance of the calibrations required by paragraph (e) of 
this section, and any associated adjustments of the automated detergent 
equipment;
    (2) For all hand-blending facilities which are terminals, a record 
specifying, for each VAR period, the total volume in gallons of 
transfers from the facility of unadditized base gasoline;
    (3) For all detergent blending facilities, product transfer 
documents for all gasoline, detergent and detergent-additized PRC 
transferred into or out of the facility; in addition, bills of lading, 
transfer, or sale for all unadditized PRC transferred into the facility;
    (4) For all automated detergent blending facilities, documentation 
establishing the brands (if known) and grades of the gasoline which is 
the subject of the VAR formula record; and
    (5) For all hand blending detergent blenders, the documentation, if 
in the party's possession, supporting the volumes of gasoline, PRC, and 
detergent reported on the VAR formula record.
    (6) For all detergent blending facilities, documentation 
establishing the curing of a batch or amount of misadditized gasoline or 
PRC, or the curing of a use restriction on the additized gasoline or 
PRC, and providing at least the following information: the date of the 
curing procedure; the problem that was corrected; the amount, name, and 
LAC of the original detergent used; the amount, name, and LAC of the 
added curing detergent; and the actual detergent concentration attained 
in, and the volume of, the total cured product.
    (g) Document retention and availability. All detergent blenders 
shall retain the documents required under this section for a period of 
five years from the date the VAR formula records and supporting 
documentation are created, and shall deliver them upon request to the 
EPA Administrator or the Administrator's authorized representative.
    (1) Except as provided in paragraph (g)(3) of this section, 
automated detergent blender facilities and hand-blender facilities which 
are terminals, which physically blend detergent into gasoline, must make 
immediately available to EPA, upon request, the preceding twelve months 
of VAR formula records plus the preceding two months of VAR supporting 
documentation.
    (2) Except as provided in paragraph (g)(3) of this section, other 
hand-blending detergent facilities which physically blend detergent into 
gasoline must make immediately available to EPA, upon request, the 
preceding two months of VAR formula records and VAR supporting 
documentation.
    (3) Facilities which have centrally maintained records at other 
locations, or have customers who maintain their own records at other 
locations for their proprietary detergent systems, and which can 
document this fact to the Agency, may have until the start of

[[Page 847]]

the next business day after the EPA request to supply VAR supporting 
documentation, or longer if approved by the Agency.
    (4) In this paragraph (g) of this section, the term immediately 
available means that the records must be provided, electronically or 
otherwise, within approximately one hour of EPA's request, or within a 
longer time frame as approved by EPA.

[61 FR 35377, July 5, 1996]



Sec. 80.171  Product transfer documents (PTDs).

    (a) Contents. For each occasion when any gasoline refiner, importer, 
reseller, distributor, carrier, retailer, wholesale purchaser-consumer, 
oxygenate blender, detergent manufacturer, distributor, carrier, or 
blender, transfers custody or title to any gasoline, detergent, or 
detergent-additized PRC other than when detergent-additized gasoline is 
sold or dispensed at a retail outlet or wholesale purchaser-consumer 
facility to the ultimate consumer, the transferor shall provide to the 
transferee, and the transferee shall acquire from the transferor, 
documents which accurately include the following information:
    (1) The name and address of the transferee and transferor; the 
address requirement may be fulfilled, in the alternative, through 
separate documentation which establishes said addresses and is 
maintained by the parties and made available to EPA for the same length 
of time as required for the PTDs, provided that the normal business 
procedure of these parties is not to identify addresses on PTDs.
    (2) The date of the transfer.
    (3) The volume of product transferred.
    (4)(i) The identity of the product being transferred (i.e., its 
identity as base gasoline, detergent, detergent-additized gasoline, or 
specified detergent-additized oxygenate or detergent-additized gasoline 
blending stock that comprises a detergent-additized PRC). PTDs for 
detergent-additized gasoline or PRC are not required to identify the 
particular detergent used to additize the product.
    (ii) If the product being transferred consists of two or more 
different types of product subject to this regulation, i.e., base 
gasoline, detergent-additized gasoline, or specified detergent-additized 
PRC, component, then the PTD for the commingled product must identify 
each such type of component contained in the commingled product.
    (5) If the product being transferred is base gasoline, then in 
addition to the base gasoline identification, the following warning must 
be stated on the PTD: ``Not for sale to the ultimate consumer''. If, 
pursuant to Sec. 80.173(a), the product being transferred is exempt 
base gasoline to be used for research, development, or test purposes 
only, the following warning must also be stated on the PTD: ``For use in 
research, development, and test programs only''.
    (6) The name of the detergent additive as reported in its 
registration must be used to identify the detergent package on its PTD.
    (7) If the product being transferred is leaded gasoline, then the 
PTD must disclose that the product contains lead and/or phosphorous, as 
applicable.
    (8) If the product being transferred is gasoline or PRC that has 
been additized with detergent under a PADD-specific or CARB-based 
certification, or under a certification option which creates an 
oxygenate or PRC use restriction, then the PTD for the additized product 
must identify the applicable use restriction. The PTD for commingled 
additized gasolines or PRCs containing such restrictions must indicate 
the applicable restriction(s) from each component.
    (9) If the product being transferred is detergent-additized gasoline 
or PRC that has been overadditized in anticipation of the later (or 
earlier) addition of PRC, then the PTD must include a statement that the 
product has been overadditized to account for a specified volume in 
gallons, or a specified percentage of the product's total volume, of 
additional, specified PRC.
    (10) If a detergent package has been certified under only one 
certification option, and that option places a use restriction on the 
respective LAC, then the PTD must identify the detergent as use-
restricted; the PTD for a detergent package certified with more than one 
LAC must identify that the detergent has special use options available.

[[Page 848]]

    (11) Base gasoline designated for fuel-specific certification.
    (i) The PTD for segregated base gasoline intended for additization 
with a specific fuel-specific detergent pursuant to Sec. 80.163(c) must 
indicate that it is for use with the designated, fuel-specific 
detergent.
    (ii) A PTD for base gasoline may not indicate that the product is 
for use with a designated, fuel-specific detergent, unless the entire 
quantity of base gasoline is from the segregated fuel supply specified 
in the detergent's certification and the gasoline contains only those 
oxygenates or PRCs, if any, specified and approved in the detergent's 
certification.
    (iii) If, pursuant to Sec. 80.163(c)(3), the fuel-specific 
certification for the segregated pool of gasoline has established that 
no detergent additives are necessary for such gasoline to comply with 
this subpart, then the PTD must identify this gasoline as detergent-
equivalent gasoline.
    (b) Use of product codes and other non-regulatory language. (1) 
Product codes and other non-regulatory language may not be used as a 
substitute for the specified PTD warning language specified in paragraph 
(a)(6) of this section for base gasoline, except that:
    (i) The specified warning language may be omitted for bulk transfers 
of base gasoline from a refinery to a pipeline if there is a prior 
written agreement between the parties specifying that all such gasoline 
is unadditized and will not be transferred to the ultimate consumer;
    (ii) Product codes may be used as a substitute for the specified 
warning language provided that the PTD is an electronic data interchange 
(EDI) document being used solely for the transfer of title to the base 
gasoline, and provided that the product codes otherwise comply with the 
requirements of this section.
    (2) Product codes and other non-regulatory language may not be used 
in place of the PTD language specified in paragraph (a)(11) of this 
section regarding detergent package use restrictions.
    (3) Product codes and other language not specified in this section 
may otherwise be used to comply with PTD information requirements, 
provided that they are clear, accurate, and not misleading.
    (4) If product codes are used, they must be standardized throughout 
the distribution system in which they are used, and downstream parties 
must be informed of their full meaning.
    (c) PTD exemption for small transfers of additized gasoline. 
Transfers of additized gasoline are exempt from the PTD requirements of 
this section provided all the following conditions are satisfied:
    (1) The product is being transferred by a distributor who is not the 
product's detergent blender; and
    (2) The recipient is a wholesale purchaser-consumer (WPC) or other 
ultimate consumer of gasoline, for its own use only or for that of its 
agents or employees; and
    (3) The volume of additized gasoline being transferred is no greater 
than 550 gallons.
    (d) Recordkeeping Period. Any person creating, providing or 
acquiring product transfer documentation for gasoline, detergent, or 
detergent-additized PRC shall retain the documents required by this 
section for a period of five years from the date the product transfer 
documentation was created, received or transferred, as applicable, and 
shall deliver such documents to EPA upon request. WPCs are not required 
to retain PTDs of additized gasoline received by them.

[61 FR 35379, July 5, 1996, as amended at 62 FR 60001, Nov. 6, 1997]



Sec. 80.172  Penalties.

    (a) General. Any person who violates any prohibition or affirmative 
requirement of Sec. 80.168 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.
    (b) Gasoline non-conformity. Any violation of Sec. 80.168(a) shall 
constitute a separate day of violation for each and every day the 
gasoline in violation remains at any place in the gasoline distribution 
system, beginning on the day that the gasoline is in violation of the 
respective prohibition and ending on

[[Page 849]]

the last day that such gasoline is offered for sale or is dispensed to 
any ultimate consumer.
    (c) Detergent non-conformity. Any violation of Sec. 80.168(d) shall 
constitute a separate day of violation for each and every day the 
detergent in violation remains at any place in the gasoline or detergent 
distribution system, beginning on the day that the detergent is in 
violation of the prohibition and ending on the last day that detergent-
additized gasoline, containing the subject detergent as a component 
thereof, is offered for sale or is dispensed to any ultimate consumer.
    (d) Post-refinery component non-conformity. Any violation of Sec. 
80.168(e) shall constitute a separate day of violation for each and 
every day the PRC in violation remains at any place in the PRC or 
gasoline distribution system, beginning on the day that the PRC is in 
violation of the respective prohibition and ending on the last day that 
detergent-additized gasoline containing the PRC is offered for sale or 
is dispensed to any ultimate consumer.
    (e) Product transfer document non-conformity. Any violation of Sec. 
80.168(c) shall constitute a separate day of violation for every day the 
PTD is not fully in compliance. This is to begin on the day that the PTD 
is created or should have been created and to end at the later of the 
following dates:
    (1) The day that the document is corrected and comes into 
compliance; or
    (2) The day that gasoline not additized in conformity with detergent 
certification program requirements, as a result of the PTD non-
conformity, is offered for sale or is dispensed to the ultimate 
consumer.
    (f) Volumetric additive reconciliation recordkeeping non-conformity. 
Any VAR recordkeeping violation of Sec. 80.168(b) shall constitute a 
separate day of violation for every day that VAR recordkeeping is not 
fully in compliance. Each element of the VAR record keeping program that 
is not in compliance shall constitute a separate violation for purposes 
of this section.
    (g) Volumetric additive reconciliation compliance standard non-
conformity. Any violation of the VAR compliance standard established in 
Sec. 80.170 shall constitute a separate day of violation for each and 
every day of the VAR compliance period in which the standard was 
violated.
    (h) Volumetric additive reconciliation equipment calibration non-
conformity. Any VAR equipment calibration violation of Sec. 80.168(b) 
shall constitute a separate day of violation for every day a VAR 
equipment calibration requirement is not met.

[61 FR 35380, July 5, 1996, as amended at 61 FR 58747, Nov. 18, 1996]



Sec. 80.173  Exemptions.

    (a) Research, development, and testing exemptions. Any detergent 
that is either in a research, development, or test status, or is sold to 
petroleum, automobile, engine, or component manufacturers for research, 
development, or test purposes, or any gasoline to be used by, or under 
the control of, petroleum, additive, automobile, engine, or component 
manufacturers for research, development, or test purposes, is exempted 
from the provisions of the detergent certification program, provided 
that:
    (1) The detergent (or fuel containing the detergent), or the 
gasoline, is kept segregated from non-exempt product, and the party 
possessing the product maintains documentation identifying the product 
as research, development, or testing detergent or fuel, as applicable, 
and stating that it is to be used only for research, development, or 
testing purposes; and
    (2) The detergent (or fuel containing the detergent), or the 
gasoline, is not sold, dispensed, or transferred, or offered for sale, 
dispensing, or transfer, from a retail outlet. It shall also not be 
sold, dispensed, or transferred or offered for sale, dispensing, or 
transfer from a wholesale purchaser-consumer facility, unless such 
facility is associated with detergent, fuel, automotive, or engine 
research, development or testing; and
    (3) The party using the product for research, development, or 
testing purposes, or the party sponsoring this usage, notifies the EPA, 
on at least an annual basis and prior to the use of the product, of the 
purpose(s) of the program(s) in which the product will be used and the 
anticipated volume of the product to be used. The information

[[Page 850]]

must be submitted to the address or fax number specified in Sec. 
80.174(c).
    (b) Racing fuel and aviation fuel exemptions. Any fuel that is 
refined, sold, dispensed, transferred, or offered for sale, dispensing, 
or transfer as automotive racing fuel or as aircraft engine fuel, is 
exempted from the provisions of this subpart, provided that:
    (1) The fuel is kept segregated from non-exempt fuel, and the party 
possessing the fuel for the purposes of refining, selling, dispensing, 
transferring, or offering for sale, dispensing, or transfer as 
automotive racing fuel or as aircraft engine fuel, maintains 
documentation identifying the product as racing fuel, restricted for 
non-highway use in racing motor vehicles, or as aviation fuel, 
restricted for use in aircraft, as applicable;
    (2) Each pump stand at a regulated party's facility, from which such 
fuel is dispensed, is labeled with the applicable fuel identification 
and use restrictions described in paragraph (b)(1) of this section; and
    (3) The fuel is not sold, dispensed, transferred, or offered for 
sale, dispensing, or transfer for highway use in a motor vehicle.
    (c) California gasoline exemptions. (1) Gasoline or PRC which is 
additized in the State of California is exempt from the VAR provisions 
in Sec. Sec. 80.168 (b) and (e) and 80.170, provided that:
    (i) For all such gasoline or PRC, whether intended for sale within 
or outside of California, records of the type required for California 
gasoline (specified in title 13, California Code of Regulations, section 
2257) are maintained; and
    (ii) Such records, with the exception of daily additization records, 
are maintained for a period of five years from the date they were 
created and are delivered to EPA upon request.
    (2) Gasoline or PRC that is transferred and/or sold solely within 
the State of California is exempt from the PTD provisions of the 
detergent certification program, specified in Sec. Sec. 80.168(c) and 
80.171.
    (3) Nothing in this paragraph (c) exempts such gasoline or PRC from 
the requirements of Sec. 80.168 (a) and (e), as applicable. EPA will 
base its determination of California gasoline's conformity with the 
detergent's LAC on the additization records required by CARB, or records 
of the same type.

[61 FR 35380, July 5, 1996]



Sec. 80.174  Addresses.

    (a) The detergent additive sample required under Sec. 80.161(b)(2) 
shall be sent to: Manager, Fuels and Technical Analysis Group, Testing 
Services Division, U.S. Environmental Protection Agency, National 
Vehicle and Fuel Emissions Laboratory, 2565 Plymouth Road, Ann Arbor, 
Michigan 48105.
    (b) Other detergent registration and certification data, and certain 
other information which may be specified in this subpart, shall be sent 
to: Detergent Additive Certification, Director, Fuels and Energy 
Division, U.S. Environmental Protection Agency (6406J), 1200 
Pennsylvania Ave., NW., Washington, DC 20460.
    (c) Notifications to EPA regarding program exemptions, detergent 
dilution and commingling, and certain other information which may be 
specified in this subpart, shall be sent to: Detergent Enforcement 
Program, U.S. Environmental Protection Agency, Suite 214, 12345 West 
Alameda Parkway, Denver, CO 80228, (FAX 303-969-6490).

[61 FR 35381, July 5, 1996]



                        Subpart H_Gasoline Sulfur

    Source: 65 FR 6823, Feb. 10, 2000, unless otherwise noted.

                           General Information



Sec. Sec. 80.180-80.185  [Reserved]



Sec. 80.190  Who must register with EPA under the sulfur program?

    (a) Refiners and importers who are registered by EPA under Sec. 
80.76 are deemed to be registered for purposes of this subpart.
    (b) Refiners and importers subject to the standards in Sec. 80.195 
who are not registered by EPA under Sec. 80.76 must provide to EPA the 
information required by Sec. 80.76 by November 1, 2003, or not later 
than three months in advance

[[Page 851]]

of the first date that such person produces or imports gasoline, 
whichever is later.
    (c) Refiners with any refinery subject to the small refiner 
standards under Sec. 80.240, or refiners subject to the geographic 
phase-in area (GPA) standards under Sec. 80.216, who are not registered 
by EPA under Sec. 80.76 must provide to EPA the information required 
under Sec. 80.76 by December 31, 2000.
    (d) Any refiner who plans to generate credits or allotments under 
Sec. 80.305 or Sec. 80.275 in any year prior to 2004 who is not 
registered by EPA under Sec. 80.76 must register under Sec. 80.76 no 
later than September 30 of the year prior to the first year of credit 
generation. Any refiner who plans to generate credits in 2000 who is not 
registered by EPA under Sec. 80.76 must register under Sec. 80.76 no 
later than May 10, 2000.

                        Gasoline Sulfur Standards



Sec. 80.195  What are the gasoline sulfur standards for
refiners and importers?

    (a)(1) The gasoline sulfur standards for refiners and importers, 
excluding gasoline produced by small refiners subject to the standards 
at Sec. 80.240, and gasoline designated as GPA gasoline under Sec. 
80.219(a), are as follows:

------------------------------------------------------------------------
                                          Gasoline sulfur standards for
                                              the  averaging period
                                                    beginning:
                                        --------------------------------
                                                              January 1,
                                          January   January    2006 and
                                          1, 2004   1, 2005   subsequent
------------------------------------------------------------------------
Refinery or Importer Average...........     \(1)\     30.00        30.00
Corporate Pool Average.................    120.00     90.00        \(1)\
Per-Gallon Cap.........................       300       300          80
------------------------------------------------------------------------
\1\ Not applicable.

    (2) The sulfur standards and all compliance calculations for sulfur 
under this subpart are in parts per million (ppm) and volumes are in 
gallons.
    (3) The averaging period is January 1 through December 31 of each 
year.
    (4) The standards under this paragraph (a) for all imported gasoline 
shall be met by the importer.
    (b)(1) The refinery or importer annual average gasoline sulfur 
standard is the maximum average sulfur level allowed for gasoline 
produced at a refinery or imported by an importer during each calendar 
year starting January 1, 2005.
    (2) The annual average sulfur level is calculated in accordance with 
Sec. 80.205.
    (3) The refinery or importer annual average gasoline sulfur standard 
may be met using credits as provided under Sec. 80.275 or Sec. 80.315.
    (4) In 2005 only, the refinery or importer annual average sulfur 
standard may be met using allotments or credits as provided under Sec. 
80.275, or credits as provided under Sec. 80.315. The same allotments 
used to demonstrate compliance with the corporate pool average standard 
may be used by a refinery in the corporate pool toward a demonstration 
of compliance with the refinery average standard, or by an importer for 
demonstration of compliance with the importer average standard. 
Alternatively, some of the allotments may be used toward a demonstration 
of compliance with the refinery average standard by one refinery in the 
corporate pool and the remainder used by another refinery or refineries 
in the corporate pool.
    (c)(1) The corporate pool average gasoline sulfur standards 
applicable in 2004 and 2005 are the maximum average sulfur levels 
allowed for a refiner's or importer's gasoline production from all of 
the refiner's refineries or all gasoline imported by an importer in a 
calendar year. The corporate pool average standards for a party that is 
both a refiner and an importer are the maximum average sulfur levels 
allowed for all the party's combined gasoline production from all 
refineries and imported gasoline in a calendar year.
    (2) The corporate pool average is calculated in accordance with the 
provisions of Sec. 80.205.
    (3) The corporate pool average standard may be met using sulfur 
allotments under Sec. 80.275.
    (4) The corporate pool average standards do not apply to approved 
small refiners subject to the gasoline sulfur standards under Sec. 
80.240.
    (5)(i) Joint ventures, in which two or more parties collectively own 
and operate one or more refineries, will be treated as a separate 
refiner under this section.
    (ii) One partner to a joint venture may include one or more joint 
venture

[[Page 852]]

refineries in its corporate pool for purposes of complying with the 
corporate pool average standards. The joint venture will be in 
compliance for such joint venture refinery(ies) if the partner's 
corporate pool average meets the corporate pool average standards. The 
joint venture entity must demonstrate compliance with the corporate pool 
average standards for any refinery(ies) owned by the joint venture that 
are not included in one partner's corporate pool.
    (iii) In the case of a refinery that is owned by a two or more 
parties that is not a joint venture under this paragraph (c)(5), the 
business entity consisting of the joint owners is the refiner of that 
refinery. One of the owners of such a refinery may include the refinery 
in its corporate pool for purposes of complying with the corporate pool 
average standards under this section, with the same requirements and 
limitations that apply under paragraph (c)(5)(ii) of this section.
    (6)(i) A parent company is the refiner of any refinery facilities 
owned by the parent company's wholly-owned subsidiaries for purposes of 
compliance with the corporate pool average standards under this section.
    (ii) A parent company must include in its corporate pool all of the 
gasoline produced at any refineries owned by the parent company and any 
refineries owned by the parent company's wholly-owned subsidiaries; or
    (iii) A parent company may be deemed in compliance with the 
corporate pool average standards if the parent company includes in its 
corporate pool the gasoline produced by any refineries owned by the 
parent company, and each wholly-owned subsidiary of the parent company 
individually complies with the corporate pool average standards for the 
gasoline produced at the refineries owned by the wholly-owned 
subsidiary.
    (d)(1) The per-gallon cap standard is the maximum sulfur level 
allowed for each batch of gasoline produced or imported starting January 
1, 2004.
    (2) In 2004 only, a refiner or importer may produce or import 
gasoline with a per-gallon sulfur content greater than 300 ppm, to a 
maximum of 350 ppm, provided the following conditions are met:
    (i) The refinery or importer becomes subject to an adjusted per-
gallon cap standard in 2005, calculated using the following formula:

ACS=300-(Smax-300)

Where:

ACS=Adjusted cap standard.
Smax=Maximum sulfur content of any gasoline produced at a 
refinery or imported by an importer during 2004.

    (ii) The adjusted cap standard calculated under paragraph (d)(2)(i) 
of this section applies to all gasoline produced at a refinery or 
imported by an importer during 2005.
    (iii) The refinery or importer remains subject to the 30.00 average 
standard under paragraph (a) of this section for 2005.
    (iv) The provisions of this paragraph (d)(2) apply to gasoline 
designated as GPA gasoline under Sec. 80.219(a).
    (v) The provisions of this paragraph (d)(2) do not apply to small 
refiners as defined in Sec. 80.225.

[65 FR 6823, Feb. 10, 2000; 65 FR 10598, Feb. 28, 2000, as amended at 67 
FR 40181, June 12, 2002]



Sec. 80.200  What gasoline is subject to the sulfur standards and requirements?

    For the purpose of this subpart, all reformulated and conventional 
gasoline and RBOB, collectively called ``gasoline'' unless otherwise 
specified, is subject to the standards and requirements under this 
subpart, with the following exceptions:
    (a) Gasoline that is used to fuel aircraft, racing vehicles or 
racing boats that are used only in sanctioned racing events, provided 
that:
    (1) Product transfer documents associated with such gasoline, and 
any pump stand from which such gasoline is dispensed, identify the 
gasoline either as gasoline that is restricted for use in aircraft, or 
as gasoline that is restricted for use in racing motor vehicles or 
racing boats that are used only in sanctioned racing events;
    (2) The gasoline is completely segregated from all other gasoline 
throughout production, distribution and sale to the ultimate consumer; 
and
    (3) The gasoline is not made available for use as motor vehicle 
gasoline, or

[[Page 853]]

dispensed for use in motor vehicles, except for motor vehicles used only 
in sanctioned racing events.
    (b) California gasoline as defined in Sec. 80.375.
    (c) Gasoline that is exported for sale outside the U.S.



Sec. 80.205  How is the annual refinery or importer average and 
corporate pool average sulfur level determined?

    (a) The annual refinery or importer average and corporate pool 
average gasoline sulfur level is calculated as follows:
[GRAPHIC] [TIFF OMITTED] TR10FE00.007

Where:

Sa = The refinery or importer annual average sulfur level, or 
corporate pool average level, as applicable.
Vi=The volume of gasoline produced or imported in batch i.
Si=The sulfur content of batch i determined under Sec. 
80.330.
n=The number of batches of gasoline produced or imported during the 
averaging period.
i=Individual batch of gasoline produced or imported during the averaging 
period.

    (b) All annual refinery or importer average or corporate pool 
average calculations shall be conducted to two decimal places.
    (c) A refiner or importer may include oxygenate added downstream 
from the refinery or import facility when calculating the sulfur 
content, provided the following requirements are met:
    (1) For oxygenate added to conventional gasoline, the refiner or 
importer must comply with the requirements of Sec. 80.101(d)(4)(ii).
    (2) For oxygenate added to RBOB, the refiner or importer must comply 
with the requirements of Sec. 80.69(a).
    (d) Refiners and importers must exclude from compliance calculations 
all of the following:
    (1) Gasoline that was not produced at the refinery;
    (2) In the case of an importer, gasoline that was imported as 
Certified Sulfur-FRGAS;
    (3) Blending stocks transferred to others;
    (4) Gasoline that has been included in the compliance calculations 
for another refinery or importer; and
    (5) Gasoline exempted from standards under Sec. 80.200.
    (e)(1) A refiner or importer may exceed the refinery or importer 
annual average sulfur standard specified in Sec. 80.195 for a given 
averaging period for any calendar year through 2010, creating a 
compliance deficit, provided that in the calendar year following the 
year the standard is not met, the refinery or importer shall:
    (i) Achieve compliance with the refinery or importer annual average 
sulfur standard specified in Sec. 80.195; and
    (ii) Use additional sulfur credits sufficient to offset the 
compliance deficit of the previous year.
    (2) No refiner or importer may have a compliance deficit in any year 
after 2010. Any deficit that exists in 2010 must be made up in 2011.

[65 FR 6823, Feb. 10, 2000, as amended at 67 FR 40182, June 12, 2002]



Sec. 80.210  What sulfur standards apply to gasoline downstream
from refineries and importers?

    The sulfur standard for gasoline at any point in the gasoline 
distribution system downstream from refineries and import facilities, 
including gasoline at facilities of distributors, carriers, oxygenate 
blenders, retailers and wholesale purchaser-consumers (``downstream 
location''), shall be determined in accordance with the provisions of 
this section.
    (a) Definition. S-RGAS means gasoline that is subject to the 
standards under Sec. 80.240 or Sec. 80.270, including Certified 
Sulfur-FRGAS as defined in Sec. 80.410, except that no batch of 
gasoline may be classified as S-RGAS if the actual sulfur content is 
less than the applicable per-gallon refinery cap standard specified in 
Sec. 80.195.
    (b) Standards for gasoline that does not qualify for S-RGAS 
downstream standards. The following standards apply to any gasoline that 
does not qualify for S-RGAS downstream standards under in paragraph (d) 
of this section:

[[Page 854]]

    (1) Starting February 1, 2004 the sulfur content of gasoline at any 
downstream location other than at a retail outlet or wholesale 
purchaser-consumer facility, and starting March 1, 2004 the sulfur 
content of gasoline at any downstream location, shall not exceed 378 
ppm.
    (2) Except as provided in Sec. 80.220(a), starting February 1, 2005 
the sulfur content of gasoline at any downstream location other than at 
a retail outlet or wholesale purchaser-consumer facility, and starting 
March 1, 2005 the sulfur content of gasoline at any downstream location, 
shall not exceed 326 ppm.
    (3) Except as provided in Sec. 80.220(a), starting February 1, 2006 
the sulfur content of gasoline at any downstream location other than at 
a retail outlet or wholesale purchaser-consumer facility, and starting 
March 1, 2006 the sulfur content of gasoline at any downstream location, 
shall not exceed 95 ppm.
    (c) Standards for gasoline that qualifies for S-RGAS downstream 
standards. In the case of any gasoline that qualifies for S-RGAS 
downstream standards under paragraph (d) of this section, the sulfur 
standard shall be the downstream standard for the gasoline calculated 
under paragraph (f) of this section. In the case of mixtures of gasoline 
that qualify for different S-RGAS downstream standards, the sulfur 
standard shall be the highest downstream standard applicable to any of 
the S-RGAS in the mixture.
    (d) Gasoline that qualifies for S-RGAS downstream standards. 
Gasoline qualifies for S-RGAS downstream standards if all of the 
following conditions are met:
    (1) The gasoline must be comprised in whole or part of S-RGAS.
    (2) Product transfer documents applicable to the gasoline when 
received at that location must represent that the gasoline contains S-
RGAS.
    (3) Except as provided in paragraph (d)(4) of this section, the 
gasoline must have been sampled and tested at that location subsequent 
to the most recent receipt of gasoline at that location, and the test 
result must show a sulfur content greater than:
    (i) 350 ppm starting February 1, 2004;
    (ii) 300 ppm starting February 1, 2005; and
    (iii) 80 ppm (or in the GPA, 300 ppm) starting February 1, 2006.
    (4) This sampling and testing condition does not apply for gasoline 
at any retail outlet, wholesale purchaser-consumer facility, or 
contained in any transport truck.
    (e) Product transfer document information for S-RGAS. (1) On each 
occasion when any refiner or importer of S-RGAS transfers custody or 
title to such gasoline, the refiner or importer shall provide to the 
transferee documents that include the following information:
    (i) Identification of the gasoline as being S-RGAS; and
    (ii) The downstream standard applicable to the batch of gasoline 
under paragraph (f) of this section.
    (2) Where gasoline in whole or part is classified as S-RGAS when 
received by the transferor, and where the gasoline transferred meets the 
conditions under paragraph (d) of this section, the transferor shall 
provide to the transferee, on each occasion when custody or title to 
gasoline is transferred, documents that include the following 
information:
    (i) Identification of the gasoline as S-RGAS; and
    (ii) The applicable downstream standard under paragraph (c) of this 
section. This does not apply when gasoline is sold or dispensed for use 
in motor vehicles at a retail outlet or wholesale purchaser-consumer 
facility.
    (3) No person shall classify gasoline as being S-RGAS except as 
provided in paragraphs (e)(1) and (e)(2) of this section.
    (4) Product codes may be used to convey the information required by 
paragraphs (e)(1) and (e)(2) of this section if such codes are clearly 
understood by each transferee.
    (5) Gasoline from a terminal tank containing S-RGAS that is combined 
with gasoline from a terminal tank containing non-S-RGAS for the purpose 
of blending mid-grade gasoline in a transport truck may be classified on 
product transfer documents as S-RGAS, provided that the S-RGAS was 
combined with non-S-RGAS for the sole purpose of producing midgrade 
gasoline.

[[Page 855]]

    (6) Where S-RGAS is being delivered into a terminal storage tank 
containing non-S-RGAS which is simultaneously supplying gasoline to a 
transport truck, the terminal may identify the gasoline as S-RGAS before 
the delivery into the terminal tank is complete without performing the 
tests required in paragraph (d)(3) of this section. Upon completion of 
the delivery of S-RGAS into the terminal tank, the terminal may classify 
the gasoline as S-RGAS only if it meets the criteria for S-RGAS 
following testing in accordance with the requirements of paragraph 
(d)(3) of this section.
    (7) The information relating to S-RGAS required to be included in 
product transfer documentation under this paragraph (e) must be included 
in the product transfer documents which accompany the transfer of 
custody of the gasoline. Product transfer documents that transfer title 
of the gasoline may fulfill the requirements under this paragraph (e) by 
indicating that the required information relating to S-RGAS is contained 
in the product transfer documents which accompany the transfer of 
custody of the gasoline.
    (f) Downstream standards applicable to S-RGAS when produced or 
imported. (1) The downstream standard applicable to any gasoline 
classified as S-RGAS when produced or imported shall be calculated using 
the following equation:

D=S+105x((S+2)/10\4\)\0.4\

Where:

D=Downstream sulfur standard.
S=The sulfur content of the refiner's batch determined under Sec. 
80.330.

    (2) Where more than one S-RGAS batch is combined, prior to shipment, 
at the refinery or import facility where the S-RGAS is produced or 
imported, the downstream standard applicable to the mixture shall be the 
highest downstream standard, calculated under paragraph (f)(1) of this 
section, for any S-RGAS contained in the mixture.

[65 FR 6823, Feb. 10, 2000, as amended at 67 FR 40182, June 12, 2002]



Sec. 80.211  What are the requirements for treating imported
gasoline as blendstock?

    An importer may treat imported gasoline (as defined in Sec. 
80.2(c)) as gasoline treated as blendstock, or GTAB, under the 
provisions of Sec. 80.83 for purposes of compliance with this subpart 
H.

[70 FR 74578, Dec. 15, 2005]



Sec. 80.212  What requirements apply to oxygenate blenders?

    Effective January 1, 2004, oxygenate blenders who blend oxygenate 
into gasoline downstream of the refinery that produced the gasoline or 
the import facility where the gasoline was imported, are not subject to 
the requirements of this subpart applicable to refiners for this 
gasoline, but are subject to the requirements and prohibitions 
applicable to downstream parties and the prohibition specified in Sec. 
80.385(e).



Sec. 80.213  What alternative sulfur standards and requirements 
apply to transmix processors and transmix blenders?

    Transmix processors and transmix blenders, as defined in Sec. 
80.84(a), may comply with the following requirements instead of the 
requirements and standards otherwise applicable to a refiner under 
subpart H of this part.
    (a) Any transmix processor who recovers transmix gasoline product 
(TGP), as defined in Sec. 80.84(a), from transmix through transmix 
processing under Sec. 80.84(c) must show through sampling and testing, 
using the methods in Sec. 80.330, that the TGP meets the applicable 
sulfur standards under Sec. 80.210 or Sec. 80.220, prior to the TGP 
leaving the transmix processing facility.
    (1) The applicable sulfur standard is the standard in Sec. 
80.210(b); or
    (2) If the TGP sulfur is greater than the standard in Sec. 
80.210(b), and the transmix processor has product transfer documents 
that prove the TGP was originally produced by a small refiner, hardship 
refiner, or for use in the GPA, the applicable sulfur standard for the 
TGP is the downstream sulfur standard corresponding to the original 
gasoline.
    (b) The sampling and testing required under paragraph (a) of this 
section

[[Page 856]]

shall be conducted following each occasion TGP is produced.
    (c) Any transmix processor who produces gasoline by adding 
blendstock to TGP must, for such blendstock, comply with all 
requirements and standards that apply to a refiner under subpart H of 
this part, and must meet the applicable downstream sulfur standards 
under Sec. 80.210 or Sec. 80.220 for the gasoline produced by blending 
blendstock and TGP, prior to the gasoline leaving the transmix 
processing facility.
    (d) Any transmix processor who produces gasoline by blending 
blendstock into TGP may meet the sampling and testing requirements of 
subpart H of this part as follows:
    (1)(i) Sample and test the blendstock when received at the transmix 
processing facility, using the methods specified in Sec. 80.330, to 
determine the volume and sulfur content, and treat each volume of 
blendstock that is blended into a volume of TGP as a separate batch for 
purposes of calculating and reporting compliance with the applicable 
annual average and per-gallon cap sulfur standards in Sec. 80.195 or 
Sec. 80.216, as applicable; or
    (ii) Use sulfur test results of the blendstock supplier provided 
that the following requirements are met:
    (A) Sampling and testing by the blendstock supplier is performed 
using the methods specified in Sec. 80.330;
    (B) Testing for the sulfur content of the blendstock in the 
supplier's storage tank must be conducted subsequent to the last receipt 
of blendstock into the supplier's storage tank from which the transmix 
processor is supplied;
    (C) The transmix processor must obtain a copy of the blendstock 
supplier's test results, at the time of each transfer of blendstock to 
the transmix processor, that reflect the sulfur content of each load of 
blendstock supplied to the transmix processor;
    (D) The transmix processor must conduct a quality assurance program 
of sampling and testing for each blendstock supplier. The frequency of 
blendstock sampling and testing must be one sample for every 500,000 
gallons of blendstock received or one sample every 3 months, whichever 
results in more frequent sampling; and
    (E) If any of the requirements of this paragraph (d)(1)(ii) are not 
met, in whole or in part, for any blendstock blended into TGP, that 
blendstock is deemed in violation of the gasoline sulfur standards in 
Sec. 80.195.
    (2) Sample and test each batch of gasoline produced by blending 
blendstock into TGP, using the methods specified in Sec. 80.330, to 
determine the sulfur content of the batch.
    (3) The sulfur content of each batch of gasoline produced by 
blending blendstock into TGP must be no greater than the downstream 
sulfur standard under Sec. 80.210 or Sec. 80.220 applicable to the 
designation of the TGP; and
    (4) Gasoline produced by blending blendstock into TGP must be 
properly identified on product transfer documents in accordance with the 
provisions of Sec. 80.210 or Sec. 80.220, as applicable.
    (e) Any transmix blender who produces gasoline by blending transmix, 
or mixtures of gasoline and distillate fuel described in Sec. 80.84(e), 
into previously certified gasoline under Sec. 80.84(d) must meet the 
applicable downstream sulfur standards under Sec. 80.210 or Sec. 
80.220 for the gasoline produced by blending transmix and previously 
certified gasoline.
    (f) Any transmix processor or transmix blender who adds feedstocks 
to their transmix other than gasoline, distillate fuel, or gasoline 
blendstocks from pipeline interface must meet all requirements and 
standards that apply to a refiner under subpart H of this part, other 
than Sec. 80.213, for all gasoline they produce during a compliance 
period.

[71 FR 31963, June 2, 2006]



Sec. 80.214  [Reserved]

                       Geographic Phase-In Program



Sec. 80.215  What is the scope of the geographic phase-in program?

    (a) Geographic phase-in area. (1) The following states comprise the 
geographic phase-in area (GPA) subject to the provisions of the 
geographic phase-in program: North Dakota, Montana, Idaho, Wyoming, 
Utah, Colorado, New Mexico, and Alaska.

[[Page 857]]

    (2) In addition, the following counties within the states identified 
in paragraph (a)(2)(i) of this section and the following Federal Indian 
reservations in paragraph (a)(2)(ii) of this section are included in the 
GPA:
    (i) The list of counties follows:

                                 Arizona

Apache
Coconino
Gila
Greenlee
Navajo

                                Nebraska

Banner
Box Butte
Cheyenne
Dawes
Deuel
Garden
Keith
Kimball
Morrill
Scotts Bluff
Sheridan
Sioux

                                 Nevada

Elko
Eureka
Humboldt
Lander
Lincoln
White Pine

                                 Oregon

Baker
Crook
Gilliam
Grant
Harney
Malheur
Morrow
Sherman
Umatilla
Union
Wallowa
Wheeler

                              South Dakota

Bennett
Butte
Corson
Custer
Dewey
Fall River
Haakon
Harding
Jackson
Jones
Lawrence
Meade
Mellette
Pennington
Perkins
Shannon
Stanley
Todd
Ziebach

                               Washington

Adams
Asotin
Benton
Chelan
Columbia
Douglas
Ferry
Franklin
Garfield
Grant
Kittitas
Klickitat
Lincoln
Okanogan
Pend Oreille
Spokane
Stevens
Walla Walla
Whitman
Yakima
    (ii) The list of Federal Indian reservations follows: Burns Paiute, 
Cheyenne River, Colville, Duck Valley, Ely Colony, Fort Apache, Fort 
McDermitt, Goshute, Haulapai, Havasupai, Hopi, Kalispel, Navajo, Pine 
Ridge, Rosebud, Yakama, San Carlos, Spokane, Standing Rock, Summit Lake, 
Te-Moak, Umatilla, Winnemucca.
    (3) Contiguous tribal reservations of a particular tribe are 
included in the GPA if a portion of the tribal reservation is within the 
GPA state or county.
    (4) Any dispensing facility located partially within a GPA county or 
tribal reservation land shall be considered fully within the GPA for 
purposes of this program.
    (b) Duration of the program. (1) The geographic phase-in program 
applies to the 2004, 2005, and 2006 annual averaging periods, except as 
provided in paragraph (b)(2) of this section.

[[Page 858]]

    (2) Subject to the provisions of Sec. 80.540, the geographic phase-
in program shall also apply to the 2007 and 2008 annual averaging period 
for refiners approved for GPA standards in 2007 and 2008 under Sec. 
80.540.
    (c) Persons eligible. Any refiner or importer who produces or 
imports gasoline for use in the geographic area under paragraph (a) of 
this section is eligible to apply for the geographic phase-in program. 
The provisions of the geographic phase-in program shall apply to 
imported gasoline through the importer.

[65 FR 6823, Feb. 10, 2000, as amended at 66 FR 5136, Jan. 18, 2001; 66 
FR 19306, Apr. 13, 2001; 70 FR 70509, Nov. 22, 2005]



Sec. 80.216  What standards apply to gasoline produced or imported
for use in the GPA?

    (a) The refinery or importer annual average sulfur standard for 
gasoline produced or imported for use in the geographic phase-in area 
under Sec. 80.215, and designated as GPA gasoline under Sec. 
80.219(a), shall be 150.00 ppm.
    (b) The per-gallon cap standard for gasoline produced or imported 
for use in the GPA under paragraph (a) of this section shall be 300 ppm, 
except as specified in Sec. 80.195(d).
    (c) The refinery or importer annual average sulfur level is 
calculated in accordance with the provisions of Sec. 80.205.
    (d) The refinery or importer annual average standard under paragraph 
(a) of this section may be met using sulfur allotments or credits as 
provided under Sec. Sec. 80.275 and 80.315.
    (e) Gasoline produced by approved small refiners subject to the 
standards under Sec. 80.240 is not subject to the standards under 
paragraphs (a) and (b) of this section.
    (f)(1) A refiner or importer whose gasoline production or volume of 
imported gasoline in 2004 or 2005 is comprised of more than 50 percent 
of gasoline designated as GPA gasoline under Sec. 80.219(a) shall not 
be required to meet the corporate pool average standards under Sec. 
80.195 for its gasoline production or imported gasoline during the 
applicable averaging period.
    (2) A refiner or importer whose gasoline production or volume of 
imported gasoline in 2004 or 2005 is comprised of less than 50 percent 
of gasoline designated as GPA gasoline under Sec. 80.219(a) must meet 
the corporate pool average standards under Sec. 80.195 for all the 
refiner's gasoline production or the importer's volume of imported 
gasoline, including GPA gasoline, during the applicable averaging 
period.
    (g) The provisions for compliance deficits under Sec. 80.205(e) do 
not apply to gasoline subject to the standards under paragraphs (a) and 
(b) of this section.

[65 FR 6823, Feb. 10, 2000, as amended at 66 FR 19306, Apr. 13, 2001; 67 
FR 40182, June 12, 2002]



Sec. 80.217  How does a refiner or importer apply for the GPA standards?

    (a) To apply for the GPA standards under Sec. 80.216, a refiner or 
importer must submit an application in accordance with the provisions of 
Sec. 80.290.
    (b) Applications under paragraph (a) of this section must be 
submitted by May 1, 2001.
    (c)(1) If approved, EPA will notify the refiner or importer of each 
refinery's or the importer's annual average sulfur standard for gasoline 
produced for use in the GPA for the 2004 through 2006 annual averaging 
periods.
    (2) If disapproved, the refiner or importer must comply with the 
standards in Sec. 80.195 for gasoline produced for use in the GPA.
    (d) If EPA finds that a refiner or importer provided false or 
inaccurate information on its application under this section, upon 
notice from EPA, the refiner's or importer's application will be void ab 
initio.

[65 FR 6823, Feb. 10, 2000, as amended at 66 FR 19306, Apr. 13, 2001]



Sec. 80.218  [Reserved]



Sec. 80.219  Designation and downstream requirements for GPA gasoline.

    The requirements and prohibitions specified in this section apply 
during the period January 1, 2004 through December 31, 2006.
    (a) Designation. Any refiner or importer shall designate any 
gasoline produced or imported that is subject to the standards under 
Sec. 80.216 as ``GPA'' gasoline.

[[Page 859]]

    (b) Product transfer documents. (1) On each occasion that any person 
transfers custody or title to gasoline designated as GPA gasoline, other 
than when gasoline is sold or dispensed for use in motor vehicles at a 
retail outlet or wholesale purchaser-consumer facility, the transferor 
shall provide to the transferee documents that include the following 
information:
    (i) Identification of the gasoline as being GPA gasoline;
    (ii) A statement that the gasoline may not be distributed or sold 
for use outside the geographic phase-in area.
    (2) Except for transfers to truck carriers, retailers and wholesale 
purchaser-consumers, product codes may be used to convey the information 
required by paragraph (b)(1) of this section if such codes are clearly 
understood by each transferee.
    (3) The requirements under paragraph (b)(1) of this section are in 
addition to the requirement under Sec. 80.210(e), where appropriate, to 
identify gasoline as being S-RGAS.
    (c) GPA gasoline use prohibitions. (1) All parties in the 
distribution system, including refiners, importers, distributors, 
carriers, oxygenate blenders, retailers and wholesale purchaser-
consumers, are prohibited from:
    (i) Selling, offering for sale, dispensing, distributing, storing or 
transporting GPA gasoline for use outside the geographic phase-in area; 
and
    (ii) Commingling GPA gasoline with gasoline not designated as GPA 
gasoline unless the mixture is classified as GPA gasoline.
    (2) Gasoline not designated as GPA gasoline may be distributed or 
sold for use in the geographic phase-in area.



Sec. 80.220  What are the downstream standards for GPA gasoline?

    (a) GPA gasoline. (1) During the period February 1, 2004 through 
January 31, 2005, the sulfur content of GPA gasoline at any downstream 
location other than at a retail outlet or wholesale purchaser-consumer 
facility, and during the period March 1, 2004 through February 28, 2005, 
the sulfur content of GPA gasoline at any downstream location shall not 
exceed 378 ppm.
    (2) During the period February 1, 2005 through January 31, 2007, the 
sulfur content of GPA gasoline at any downstream location other than at 
a retail outlet or wholesale purchaser-consumer facility, and during the 
period March 1, 2005 through February 28, 2007, the sulfur content of 
GPA gasoline at any downstream location shall not exceed 326 ppm.
    (b) GPA gasoline mixed with S-RGAS. Notwithstanding the requirements 
in paragraph (a) of this section, the sulfur standard applicable to a 
mixture of GPA gasoline and S-RGAS gasoline at a downstream location 
shall be the greater of the standard under paragraph (a) of this section 
or the standard determined under Sec. 80.210.
    (c) Notwithstanding paragraph (a) of this section, the sulfur 
content standard of 326 ppm at any downstream location may be extended 
as provided under Sec. 80.540(m).

[65 FR 6823, Feb. 10, 2000, as amended at 66 FR 5136, Jan. 18, 2001]

                           Hardship Provisions



Sec. 80.225  What is the definition of a small refiner?

    (a) A small refiner is defined as any person, as defined by 42 
U.S.C. 7602(e), who: (1)(i) Produces gasoline at a refinery by 
processing crude oil through refinery processing units;
    (ii) Employed an average of no more than 1,500 people, based on the 
average number of employees for all pay periods from January 1, 1998, to 
January 1, 1999; and
    (iii) Had an average crude capacity less than or equal to 155,000 
barrels per calendar day (bpcd) for 1998.
    (2) For the purpose of determining the number of employees and crude 
capacity under paragraph (a)(1) of this section, the refiner shall 
include the employees and crude capacity of any subsidiary companies, 
any parent company and subsidiaries of the parent company, and any joint 
venture partners. A subsidiary under this paragraph means any subsidiary 
in which the refiner or parent company has a 50% or greater ownership 
interest.
    (b) The definition under paragraph (a) of this section applies to 
domestic and foreign refiners. For any refiner owned by a governmental 
entity, the number of employees as specified in

[[Page 860]]

paragraph (a) of this section shall include all employees of the 
governmental entity.
    (c) If, without merger with, or acquisition of, another business 
unit, a company with approved small refiner status under Sec. 80.235 
exceeds 1,500 employees, or a corporate crude capacity of 155,000 bpcd 
after January 1, 1999, it will be considered a small refiner for the 
duration of the small refiner program.
    (d) Notwithstanding the definition in paragraph (a) of this section, 
refiners who acquire a refinery after January 1, 1999, or reactivate a 
refinery that was shutdown or was non-operational between January 1, 
1998, and January 1, 1999, may apply for small refiner status in 
accordance with the provisions of Sec. 80.235.

[65 FR 6823, Feb. 10, 2000, as amended at 66 FR 19306, Apr. 13, 2001; 67 
FR 38340, June 3, 2002; 67 FR 40182, June 12, 2002]



Sec. 80.230  Who is not eligible for the hardship provisions for
small refiners?

    (a) The following are not eligible for the hardship provisions for 
small refiners:
    (1) Refiners with refineries built after January 1, 1999;
    (2) Refiners who exceed the employee or crude oil capacity criteria 
under Sec. 80.225(a) on January 1, 1999, but who meet these criteria 
after that date, regardless of whether the reduction in employees or 
crude capacity is due to operational changes at the refinery or a 
company sale or reorganization;
    (3) Importers; and
    (4) Refiners who produce gasoline other than by processing crude oil 
through refinery processing units.
    (b)(1)(i) Refiners who qualify as small under Sec. 80.225 and 
subsequently cease production of diesel fuel from processing crude oil 
through refinery processing units, or employ more than 1,500 people or 
exceed the 155,000 bpcd crude oil capacity limit after January 1, 2004 
as a result of merger with or acquisition of or by another entity, are 
disqualified as small refiners, except this shall not apply in the case 
of a merger between two previously approved small refiners. If 
disqualification occurs, the refiner shall notify EPA in writing no 
later than 20 days following this disqualifying event.
    (ii) Except as provided under paragraph (b)(1)(iii) of this section, 
any refiner whose status changes under this paragraph shall meet the 
applicable standards of Sec. 80.195 within a period of up to 30 months 
of the disqualifying event for any of its refineries that were 
previously subject to the small refiner standards of Sec. 80.240(a). 
However, such period shall not extend beyond December 31, 2007, or, for 
refineries for which the Administrator has approved an extension of the 
small refiner gasoline sulfur standards under Sec. 80.553(c), December 
31, 2010.
    (iii) A refiner may apply to EPA for an additional six months to 
comply with the standards of Sec. 80.195 if more than 30 months will be 
required for the necessary engineering, permitting, construction, and 
start-up work to be completed. Such applications must include detailed 
technical information supporting the need for additional time. EPA will 
base its decision to approve additional time on the information provided 
by the refiner and on other relevant information. In no case will EPA 
extend the compliance date beyond December 31, 2007, or, for refineries 
for which the Administrator has approved an extension of the small 
refiner gasoline sulfur standards under Sec. 80.553(c), December 31, 
2010.
    (iv) During the period of time up to 30 months provided under 
paragraph (b)(1)(ii) of this section, and any extension provided under 
paragraph (b)(1)(iii) of this section, the refiner may not generate 
gasoline sulfur credits under Sec. 80.310.
    (2) Any refiner who qualifies as a small refiner under Sec. 80.225 
may elect to meet the standards under Sec. 80.195 by notifying EPA in 
writing no later than November 15 prior to the year that the change will 
occur. Any refiner whose status changes under this paragraph (b)(2) 
shall meet the standards under Sec. 80.195 beginning with the first 
averaging period subsequent to the status change.

[65 FR 6823, Feb. 10, 2000, as amended at 66 FR 19307, Apr. 13, 2001; 69 
FR 39167, June 29, 2004]

[[Page 861]]



Sec. 80.235  How does a refiner obtain approval as a small refiner?

    (a) Applications for small refiner status must be submitted to EPA 
by December 31, 2000, except for applications submitted pursuant to 
Sec. 80.225(d), which must be submitted by June 1, 2002.
    (b) Applications for small refiner status must be sent to: U.S. EPA, 
Attn: Sulfur Program (6406J), 1200 Pennsylvania Ave., NW., Washington, 
DC 20460. For commercial delivery: U.S. EPA, Attn: Sulfur Program 
(6406J), 501 3rd Street, NW, Washington, DC 20001.
    (c) The small refiner status application must contain the following 
information for the company seeking small refiner status, plus any 
subsidiary companies, any parent company and subsidiaries of the parent 
company, and any joint venture partners:
    (1)(i) A listing of the name and address of each location where any 
employee worked during the 12 months preceding January 1, 1999; the 
average number of employees at each location based upon the number of 
employees for each pay period for the 12 months preceding January 1, 
1999; and the type of business activities carried out at each location; 
or
    (ii) In the case of a refiner who acquires a refinery after January 
1, 1999, or reactivates a refinery that was shutdown between January 1, 
1998, and January 1, 1999, a listing of the name and address of each 
location where any employee of the refiner worked since the refiner 
acquired or reactivated the refinery; the average number of employees at 
any such acquired or reactivated refinery during each calendar year 
since the refiner acquired or reactivated the refinery; and the type of 
business activities carried out at each location.
    (2) The total corporate crude oil capacity of each refinery as 
reported to the Energy Information Administration (EIA) of the U.S. 
Department of Energy (DOE), or, in the case of a foreign refiner, a 
comparable reputable source, such as a professional publication or trade 
journal. The information submitted to EIA or the comparable reputable 
source is presumed to be correct. In cases where a company, domestic or 
foreign, disagrees with this information, the company may petition EPA 
with appropriate data to correct the record within 60 days after the 
company submits its application for small refiner status.
    (3) A letter signed by the president, chief operating or chief 
executive officer of the company, or his/her designee, stating that the 
information contained in the application is true to the best of his/her 
knowledge.
    (4) Name, address, phone number, facsimile number and E-mail address 
(if available) of a corporate contact person.
    (d) For joint ventures, the total number of employees includes the 
combined employee count of all corporate entities in the venture.
    (e) For government-owned refiners, the total employee count includes 
all government employees.
    (f) Approval of small refiner status for refiners who apply under 
Sec. 80.225(d) will be based on all information submitted under 
paragraph (c) of this section. The information submitted must show that 
the refiner employed an average of no more than 1500 people and had an 
average crude oil capacity less than or equal to 155,000 bpcd. Where 
appropriate, the employee and crude oil capacity criteria for such 
refiners will be based on the most recent 12 months of operation.
    (g) EPA will notify a refiner of approval or disapproval of small 
refiner status by letter.
    (1) If approved, EPA will notify the refiner of each refinery's 
applicable annual average sulfur standard, baseline volume, and per-
gallon cap standard under Sec. 80.240 for the 2004-2007 averaging 
periods.
    (2) If disapproved, the refiner must comply with the standards in 
Sec. 80.195.
    (h) If EPA finds that a refiner provided false or inaccurate 
information on its application for small refiner status, upon notice 
from EPA the refiner's small refiner status will be void ab initio.
    (i) Upon notification to EPA, an approved small refiner may withdraw 
its status as a small refiner. Effective on January 1 of the year 
following such

[[Page 862]]

notification, the small refiner will become subject to the standards at 
Sec. 80.195.

[65 FR 6823, Feb. 10, 2000, as amended at 66 FR 19307, Apr. 13, 2001]



Sec. 80.240  What are the small refiner gasoline sulfur standards?

    (a) The gasoline sulfur standards for an approved small refiner are 
as follows:

----------------------------------------------------------------------------------------------------------------
                                          Temporary sulfur standards for small refiners applicable from January
                                                            1, 2004 through December 31, 2007
     Refinery baseline sulfur level     ------------------------------------------------------------------------
                                                    Annual average                      Per gallon cap
----------------------------------------------------------------------------------------------------------------
0 to 30................................  30.00                                300
31 to 200..............................  Baseline level                       300
201 to 400.............................  200.00                               300
401 to 600.............................  50% of baseline                      Factor of 1.5 times the average
                                                                               standard.
601 and above..........................  300.00                               450
----------------------------------------------------------------------------------------------------------------

    (b) The refinery annual average sulfur standards must be met on an 
annual calendar year basis for each refinery owned by a small refiner. 
The refinery annual average sulfur level is calculated in accordance 
with the provisions of Sec. 80.205.
    (c)(1) The refinery annual average standards specified in paragraph 
(a) of this section apply to the volume of gasoline produced by a small 
refiner's refinery up to the lesser of:
    (i) 105% of the baseline gasoline volume as determined under Sec. 
80.250(a)(1); or
    (ii) The volume of gasoline produced at that refinery during the 
averaging period by processing crude oil.
    (2) If a refiner exceeds the volume limitation in paragraph (c)(1) 
of this section during any averaging period, the annual average sulfur 
standard applicable to the refiner for that averaging period is 
calculated as follows:
[GRAPHIC] [TIFF OMITTED] TR10FE00.008

Where:

Ssr=Small refiner annual average sulfur standard.
Vb=Applicable volume under paragraph (c)(1) of this section.
Va=Averaging period gasoline volume.
Sb=Small refiner sulfur baseline as determined under Sec. 
80.250.
AF=Adjustment factor (120 in 2004; 90 in 2005; and 30 in 2006 and 
thereafter).

    (3) The small refiner average standards under paragraph (a) of this 
section may be met using sulfur allotments or credits as provided under 
Sec. 80.275 or Sec. 80.315.
    (4) The provisions for compliance deficits under Sec. 80.205(e) do 
not apply to small refiners subject to the standards under this section.
    (d) In the case of any refiner with small refiner status who 
generates sulfur allotments or credits pursuant to Sec. 80.275(a) or 
Sec. 80.305, the baseline applicable to that refiner's refinery for 
purposes of establishing the standard for the refinery under paragraph 
(a) of this section beginning in 2004 shall be the lowest annual average 
sulfur content for any year during the period in which the refiner 
generated allotments or credits.
    (e) Notwithstanding paragraph (a) of this section, the temporary 
sulfur standards for small refiners may be extended as provided under 
Sec. 80.553.
    (f)(1) In the case of a refiner without approved small refiner 
status who acquires a refinery from a refiner with approved small 
refiner status under Sec. 80.235, the applicable small refiner 
standards under paragraph (a) of this section will apply to the acquired 
small refinery for a period up to 30 months from the date of acquisition 
of the refinery, but no later than December 31, 2007, or, for a refinery 
for which the Administrator has approved an extension of the small 
refiner gasoline sulfur standards under Sec. 80.553(c), December 31, 
2010, after which time the standards of Sec. 80.195 shall apply to the 
acquired refinery.
    (2) A refiner may apply to EPA for an additional six months to 
comply with the standards of Sec. 80.195 for the acquired refinery if 
more than 30 months

[[Page 863]]

will be required for the necessary engineering, permitting, 
construction, and start-up work to be completed. Such applications must 
include detailed technical information supporting the need for 
additional time. EPA will base its decision to approve additional time 
on information provided by the refiner and on other relevant 
information. In no case will EPA extend the compliance date beyond 
December 31, 2007, or, for a refinery for which the Administrator has 
approved an extension of the small refiner gasoline sulfur standards 
under Sec. 80.553(c), December 31, 2010.

[65 FR 6823, Feb. 10, 2000, as amended at 66 FR 5136, Jan. 18, 2001; 69 
FR 39167, June 29, 2004]



Sec. 80.245  How does a small refiner apply for a sulfur baseline?

    (a) Any refiner seeking small refiner status must apply for a 
refinery sulfur baseline by the deadline under Sec. 80.235 for each of 
the refiner's refineries by providing the following information:
    (1) A sulfur baseline and baseline volume for every refinery 
calculated in accordance with Sec. 80.250.
    (2) The following information for each batch of gasoline produced in 
1997-1998:
    (i) Batch number assigned to the batch under Sec. 80.65(d) or Sec. 
80.101(i);
    (ii) Volume; and
    (iii) Sulfur content.
    (3) For any refiner that acquires and/or reactivates a refinery that 
was shut down or non-operational between January 1, 1997, and December 
31, 1998, the average sulfur level and average volume of gasoline 
produced during each annual averaging period that the refinery was in 
operation after the refinery was acquired and/or reactivated. EPA will 
evaluate all of the information and data submitted by the refiner in 
determining the appropriate sulfur baseline for the refinery. Where EPA 
concludes that the data submitted reasonably reflects current sulfur 
levels, the refinery's baseline will be determined based on the average 
sulfur content of gasoline produced by the refinery during the most 
recent annual averaging period in which the refinery was in operation.
    (b) The sulfur baseline application must be submitted to the address 
specified in Sec. 80.235(b).
    (c)(1) Foreign refiners who do not have an approved individual 
refinery baseline under Sec. 80.94 must follow the procedures specified 
in Sec. 80.410(b).
    (2) Foreign refiners who have an approved individual refinery 
baseline under Sec. 80.94, but one that was not in effect for purposes 
of anti-dumping compliance during the 1997-1998 annual averaging 
periods, must comply with the requirements of this section for the 
gasoline produced at the refinery and imported into the United States 
during each of the annual averaging periods in which the refinery was 
subject to its individual anti-dumping baseline. EPA will evaluate all 
of the information and data submitted under this section in determining 
the foreign refinery's sulfur baseline pursuant to this paragraph. Where 
EPA concludes that the data submitted reasonably reflects current sulfur 
levels, the refinery's baseline will be determined based on the annual 
average sulfur level and volume of gasoline produced by the foreign 
refinery and imported into the U.S. during the most recent annual 
averaging period in which the refinery was subject to its individual 
anti-dumping baseline.

[65 FR 6823, Feb. 10, 2000, as amended at 66 FR 19307, Apr. 13, 2001]



Sec. 80.250  How is the small refiner sulfur baseline and volume determined?

    (a)(1) The small refiner baseline volume is determined for each 
refinery as follows:
[GRAPHIC] [TIFF OMITTED] TR10FE00.009

Where:

VB=Baseline volume.
VI=Volume of gasoline batch i.
n = Total number of batches of gasoline produced from January 1, 1997, 
through December 31, 1998 (or the total number of batches of gasoline 
pursuant to Sec. 80.245(a)(3); or, for a foreign refinery, the total 
number of batches of gasoline produced and imported into the U.S. from 
January 1, 1997, through December 31, 1998,

[[Page 864]]

or the total number of batches of gasoline produced and imported into 
the U.S. pursuant to Sec. 80.245(c)(2)).
i = Individual batch of gasoline produced from January 1, 1997, through 
December 31, 1998 (or individual batch of gasoline pursuant to Sec. 
80.245(a)(3); or, for a foreign refinery, individual batch of gasoline 
produced and imported into the U.S. from January 1, 1997, through 
December 31, 1998, or individual batch of gasoline produced and imported 
into the U.S. pursuant to Sec. 80.245(c)(2)).

    (2) The small refiner sulfur baseline is determined for each 
refinery as follows:
[GRAPHIC] [TIFF OMITTED] TR10FE00.010

Where:

Sb=Small refiner sulfur baseline.
Vi=Volume of gasoline batch i.
Si=Sulfur content of batch i.
n=Total number of batches of gasoline produced from January 1, 1997, 
through December 31, 1998 (or the total number of batches of gasoline 
pursuant to Sec. 80.245(a)(3); or, for a foreign refinery, the total 
number of batches of gasoline produced and imported into the U.S. from 
January 1, 1997, through December 31, 1998, or the total number of 
batches of gasoline produced and imported into the U.S. pursuant to 
Sec. 80.245(c)(2)).
i=Individual batch of gasoline produced from January 1, 1997, through 
December 31, 1998 (or individual batch of gasoline produced pursuant to 
Sec. 80.245(a)(3); or, for a foreign refinery, individual batch of 
gasoline produced and imported into the U.S. from January 1, 1997, 
through December 31, 1998, or individual batch of gasoline produced and 
imported into the U.S. pursuant to Sec. 80.245(c)(2)).

    (3) Any refiner who, under Sec. 80.69 or Sec. 80.101(d)(4), 
included oxygenate blended downstream in compliance calculations for 
1997-1998 must include this oxygenate in the baseline calculations for 
sulfur content under this section.
    (4) Sulfur baseline calculations under this section shall be 
conducted to two decimal places.
    (b) [Reserved]
    (c) If at any time a small refinery baseline is determined to be 
incorrect, the corrected baseline applies ab initio and the annual 
average standards and cap standards are deemed to be those applicable 
under the corrected information.

[65 FR 6823, Feb. 10, 2000, as amended at 66 FR 19307, Apr. 13, 2001]



Sec. 80.255  Compliance plans and demonstration of commitment to produce low sulfur gasoline.

    The requirements of this section apply to any refiner approved for 
small refiner standards who wishes to be eligible for a hardship 
extension under Sec. 80.260.
    (a) Compliance commitment. By no later than June 1, 2004, any 
refiner who is approved for small refinery standards must submit a 
preliminary report to EPA which outlines the refiner's timeline for 
compliance and a project plan which discusses permits, capital 
commitments and engineering plans for making the necessary modifications 
to produce gasoline that meets the 30 ppm refinery average and 80 ppm 
per-gallon cap sulfur standards under Sec. 80.195 on or before January 
1, 2008. Documents showing activities and progress in these areas should 
be provided, if available.
    (b) Demonstration of Progress. (1)(i) By no later than June 1, 2005, 
the small refiner must submit a report to EPA that states in detail the 
progress toward compliance with the 30 ppm refinery average and 80 ppm 
cap sulfur standards to date based on their timeline and project plan. 
The report must include:
    (A) Copies of approved permits for construction of the equipment, or 
the permit application if approval is still pending;
    (B) Copies of contracts for design and construction; and
    (C) Any available evidence of having secured the necessary financing 
to complete the required construction;
    (ii) If the refiner anticipates any difficulties in meeting its 
compliance commitments under this section, the refiner must submit a 
detailed report of all efforts made to date and the factors that may 
cause delay, including costs, specification of engineering or other 
design work needed and reasons for delay, specification of equipment

[[Page 865]]

needed and any reasons for delay, potential equipment suppliers and 
history of negotiations, and any other relevant information. If 
unavailability of equipment is a factor, the report must include a 
discussion of other options considered and the reasons these other 
options are not feasible.
    (2) By no later than June 1, 2006, the small refiner must submit to 
EPA evidence that on-site construction has begun and that, absent 
unforeseen difficulties, the small refiner will be producing complying 
gasoline by January 1, 2008. If construction has not begun, the refiner 
must demonstrate that it has made all reasonable efforts to begin 
construction, that substantial progress is being made to begin 
construction as soon as possible, and that construction can be completed 
in time to begin production of gasoline that complies with the standards 
of Sec. 80.195 by January 1, 2008.
    (c) Additional information. The Administrator may request any 
additional information necessary to determine a refiner's commitment 
and/or progress toward meeting the standards in Sec. 80.195 by 2008.
    (d) Failure to comply with requirements. Any small refiner who fails 
to submit the progress reports required under this section will not be 
eligible for a hardship extension under Sec. 80.260.



Sec. 80.260  What are the procedures and requirements for obtaining 
a hardship extension?

    (a) An approved small refiner who has filed the reports specified in 
Sec. 80.255 may apply to EPA for a hardship extension of the small 
refiner standards for calendar years 2008 and 2009. The application must 
be submitted in writing no later than January 1, 2007, to U.S. EPA, 
Attn: Sulfur Program (6406J), 1200 Pennsylvania Ave., NW., Washington, 
DC 20460. For commercial (non-postal) delivery: U.S. EPA, Attn: Sulfur 
Program, 501 3rd Street NW, Washington, DC 20001.
    (b) The application must specify the factors that demonstrate a 
significant economic hardship and must provide a detailed discussion 
regarding the inability of the refinery to produce gasoline meeting the 
requirements of Sec. 80.195. Such an application must include, at a 
minimum, the following information:
    (1) Documentation of efforts made to obtain necessary financing, 
including:
    (i) Copies of loan applications for the necessary financing of the 
construction of appropriate sulfur reduction technology and other 
equipment procurements or improvements; and
    (ii) If financing has been disapproved or is otherwise unsuccessful, 
documents supporting the basis for that disapproval and evidence of 
efforts to pursue other means of financing;
    (2) A detailed analysis of the reasons the refinery is unable to 
produce gasoline meeting the standards of Sec. 80.195 in 2008, 
including costs, specification of equipment still needed, potential 
equipment suppliers, and efforts already completed to obtain the 
necessary equipment;
    (3) If unavailability of equipment is part of the reason for the 
inability to comply, a discussion of other options considered, and the 
reasons these other options are not feasible;
    (4) If relevant, a demonstration that a needed or lower cost 
technology is immediately unavailable, but will be available in the near 
future, and full information regarding when and from what sources it 
will be available;
    (5) Schematic drawings of the refinery configuration as of January 
1, 1999, and as of the date of the hardship extension application, and 
any planned future additions or changes;
    (6) If relevant, a demonstration that a temporary unavailability 
exists of engineering or construction resources necessary for design or 
installation of the needed equipment;
    (7) If sources of crude oil lower in sulfur than what the refiner is 
currently using are available, full information regarding the 
availability of these different crude sources, the sulfur content of 
those crude sources, the cost of the different crude sources over the 
past five years, and an estimate of gasoline sulfur levels achievable by 
the refinery if the lower sulfur crude sources were used;
    (8) A discussion of any sulfur reductions that can be achieved from 
current levels;

[[Page 866]]

    (9) The date the refiner anticipates compliance with the standards 
in Sec. 80.195 can be achieved at its refinery;
    (10) An analysis of the economic impact of compliance on the 
refiner's business (including financial statements from the last 5 
years, or for any time period up to 10 years, at EPA's request); and
    (11) Any other information regarding other strategies considered, 
including strategies or components of strategies that do not involve 
installation of equipment, and why meeting the standards in Sec. 80.195 
beginning in 2008 is infeasible.
    (c) The hardship extension application must contain a letter signed 
by the president or the chief operating or chief executive officer of 
the company, or his/her designee, stating that the information contained 
in the application is true to the best of his/her knowledge.



Sec. 80.265  How will the EPA approve or disapprove a hardship extension application?

    (a) EPA will evaluate each application for hardship extension on a 
case-by-case basis. The factors considered for a hardship extension may 
include: The refiner's financial position and efforts to obtain capital 
funding; the refiner's efforts to procure necessary equipment, obtain 
design and engineering services and construction contractors; the 
availability of desulfurization equipment; and any other relevant 
factor. An extension will be granted for a refinery for the 2008 
averaging period if the small refiner who owns the refinery adequately 
demonstrates that severe economic hardship would result if compliance 
with the standards in Sec. 80.195 is required in 2008, or that 
compliance with the standard in 2008 is not feasible for reasons beyond 
the refiner's control, and that the refiner has made the best efforts 
possible to achieve compliance with the national standards by January 1, 
2008. Upon reapplication by the refiner, if EPA determines that further 
relief is appropriate, EPA may grant a further extension through the 
2009 averaging period. In no case will a further extension for the 2009 
averaging period be granted unless the refiner demonstrates conclusively 
that it has financing in place and that it will be able to complete 
construction and meet the national gasoline sulfur standards no later 
than December 31, 2009.
    (b) EPA may request more information, if necessary, for evaluation 
of the application. If requested information is not submitted within the 
time specified in EPA's request, or any extensions granted, the 
application may be denied.
    (c) EPA will notify the refiner of approval or disapproval of 
hardship extension by letter.
    (1) If approved, EPA will also notify the refiner of the date that 
full compliance with the standards specified at Sec. 80.195 must be 
achieved or what interim sulfur levels or schedules apply, if any.
    (2) If disapproved, beginning January 1, 2008, the refinery is 
subject to the requirements in Sec. 80.195. Refiners who receive an 
extension for the 2008 averaging period shall meet the standards in 
Sec. 80.195 beginning on January 1, 2009, unless EPA grants an 
extension of the hardship relief for an additional year. If such an 
additional extension is granted, the refiner shall meet the standards in 
Sec. 80.195 on January 1, 2010.
    (d) Refiners who receive a hardship extension may be required to 
meet more stringent standards than those which apply to them during 
2007, and/or could be required to offset excess sulfur levels. EPA may 
impose reasonable conditions on an extension, such as requiring 
segregation of the small refiner's gasoline or requiring the gasoline to 
be sold for use in older vehicles only.



Sec. 80.270  Can a refiner seek temporary relief from the requirements
of this subpart?

    (a) EPA may permit a refiner to produce and distribute gasoline 
which does not meet the requirements of this subpart if the refiner 
demonstrates that:
    (1) Unusual circumstances exist that impose extreme hardship and 
significantly affect ability to comply by the applicable date; and
    (2) It has made best efforts to comply with the requirements of this 
subpart (including making efforts to obtain credits and/or allotments).

[[Page 867]]

    (b) Applications must be submitted to EPA by September 1, 2000. 
Relief may be granted from some or all of the requirements of this 
subpart, at EPA's discretion; however, EPA reserves the right to deny 
applications for appropriate reasons, including unacceptable 
environmental impact. Approval to distribute gasoline which does not 
meet the requirements of this subpart may be granted for such time 
period as EPA determines is appropriate, but shall not extend beyond 
January 1, 2008.
    (c)(1) Applications must include a plan demonstrating how the 
refiner will comply with the requirements of this subpart as 
expeditiously as possible. The plan shall include a showing that 
contracts are or will be in place for engineering and construction of 
desulfurization equipment, a plan for applying for and obtaining any 
permits necessary for construction, a description of plans to obtain 
necessary capital, and a detailed estimate of when the requirements of 
this subpart will be met.
    (2) Applications must include a detailed description of the refinery 
configuration and operations, including, at a minimum, the following 
information:
    (i) The portion of gasoline production that is produced using an FCC 
unit;
    (ii) The refinery's hydrotreating capacity;
    (iii) The refinery's total reformer unit throughput capacity;
    (iv) The refinery's total crude capacity;
    (v) Total crude capacity of any other refineries owned by the same 
entity;
    (vi) Total volume of gasoline production at the refinery;
    (vii) Total volume of other refinery products; and
    (viii) Geographic location(s) in which gasoline will be sold.
    (3) Applications must include, at a minimum, the following 
information:
    (i) Detailed description of efforts to obtain capital for refinery 
investments;
    (ii) Bond rating of entity that owns the refinery; and
    (iii) Estimated capital investment needed to comply with the 
requirements of this subpart by the applicable date.
    (4) Applicants must also provide any other relevant information 
requested by EPA.
    (d) EPA may impose any reasonable conditions on waivers granted 
under this section.

                        Allotment Trading Program



Sec. 80.271  How can a small refiner obtain an adjustment of its
2004-2007 per-gallon cap standard?

    (a) EPA may in its discretion adjust the small refiner per-gallon 
cap sulfur standard established for a refinery under Sec. 80.240(a) 
(the established small refiner per-gallon standard) if the refiner 
demonstrates that the burden of complying with the established small 
refiner per-gallon standard would effectively prevent the refiner from 
participating in the small refiner relief provided in Sec. 80.240. No 
refiner will be eligible for an adjustment of its established per-gallon 
standard above 450 ppm. The refinery annual average sulfur standards in 
Sec. 80.240(a) are not affected by this section.
    (b) A refiner wishing to apply for such an adjustment of its 
established small refiner per-gallon sulfur standard under Sec. 
80.240(a) must send a letter to Gasoline Sulfur Program, U.S. EPA, 
Office of Transportation and Air Quality, 2000 Traverwood Dr., Ann 
Arbor, MI 48105 no later than January 1, 2003. Such application must 
include the following information:
    (1) A detailed description of the nature of the difficulty that the 
per-gallon cap creates;
    (2) The refiner's proposed adjusted per-gallon cap standard and the 
proposed duration for the adjustment, including an explanation of how a 
lower per-gallon cap standard or shorter duration would not address the 
hardship;
    (3) The refiner's expected actual annual average sulfur level (i.e., 
prior to the use of any credits or allotments) for each year that the 
adjustment would be in effect;
    (4) The refiner's estimate of the number of gallons of gasoline it 
produces that will exceed the established small refiner per-gallon 
standard under Sec. 80.240(a) for each year that the adjusted per-
gallon cap would apply; and
    (5) The number of sulfur credits or allotments that the refiner 
estimates

[[Page 868]]

will be required under paragraph (d) of this section for each year that 
the adjusted per-gallon cap would apply and a plan for obtaining this 
number of credits or allotments.
    (6) Other relevant information that EPA requests.
    (c) EPA will evaluate each application for an adjusted per-gallon 
cap sulfur standard on a case-by-case basis. EPA may impose any 
reasonable conditions on adjustments granted under this section. EPA may 
in its discretion set forth the duration of the adjusted per-gallon cap 
sulfur standard but in no case shall it extend beyond December 31, 2007.
    (d)(1) A small refiner with an adjusted per-gallon sulfur cap 
standard under paragraph (a) of this section must obtain and use sulfur 
credits or allotments to offset the amount that the adjusted standard 
exceeds the established small refiner per-gallon standard under Sec. 
80.240(a). The number of sulfur credits or allotments needed for each 
year that the adjusted per-gallon cap would apply is calculated on a 
per-batch basis according to paragraph (d)(2) of this section and summed 
over the averaging period.
    (2) The formula for determining the number of sulfur credits or 
allotments that such a small refiner is required to use for any batch of 
gasoline exceeding the established small refiner per-gallon standard 
under Sec. 80.240(a) is as follows:

CRb = Vb x (Sb-Sc)

Where:

CRb = number of sulfur allotments or sulfur credits needed 
for the gasoline batch (ppm-gallons)
Vb = Volume of the gasoline batch (gallons)
Sb = Sulfur level of the gasoline batch (ppm)
Sc = Small refiner per-gallon cap standard established for 
that refinery under Sec. 80.240(a), in ppm.

    (3) Sulfur credits or allotments used when a small refiner exceeds 
an established per-gallon cap sulfur standard under Sec. 80.240(a) must 
be separate from and in addition to credits or allotments used for any 
other purposes provided under Sec. 80.275 or Sec. 80.315.
    (e) The approving official for an adjustment under this section is 
the Director of the Office of Transportation and Air Quality in the EPA 
Office of Air and Radiation.

[67 FR 40182, June 12, 2002]



Sec. 80.275  How are allotments generated and used?

    (a) Generation of allotments and credits in 2003. (1) During 2003 
only, any domestic or foreign refiner who produces gasoline from crude 
oil may have the option to generate credits in accordance with the 
provisions of Sec. 80.305 or generate allotments and credits under 
paragraph (a)(2) of this section.
    (2) If the average sulfur content of the gasoline produced at a 
refinery is less than the refinery's baseline as determined under Sec. 
80.295 and is 60 ppm or less, allotments and credits may be generated 
using the following procedures. This paragraph (a) does not apply to 
importers.
    (i) If the average sulfur content of the gasoline produced at a 
refinery is less than or equal to 30, and the refinery's sulfur baseline 
is greater than 120, the following procedures apply:

SATypeB = (30 - Sa) x V
SATypeA = V x 90
CR = (SBase - 120) x V

    (ii) If the average sulfur content of the gasoline produced at a 
refinery is less than or equal to 30, and the refinery's sulfur baseline 
is greater than 30 but less than or equal to 120, the following 
procedures apply:

SATypeB = (30 - Sa) x V
SATypeA = (SBase - 30) x V

    (iii) If the average sulfur content of the gasoline produced at a 
refinery is less than or equal to 30, and the refinery's sulfur baseline 
is less than or equal to 30, the following procedures apply:

SATypeB = ( SBase - Sa) x V

    (iv) If the average sulfur content of the gasoline produced at a 
refinery is greater than 30, and the refinery's sulfur baseline is 
greater than 120, the following procedures apply:

SATypeA = ((120 - Sa) x V) x 0.8
CR = (SBase - 120) x V

    (v) If the average sulfur content of the gasoline produced at a 
refinery is

[[Page 869]]

greater than 30, and the refinery's sulfur baseline is less than or 
equal to 120, the following procedures apply:

SATypeA = ((SBase - Sa) x V) x 0.8

    (vi) For purposes of the equations under paragraphs (a)(2)(i) 
through (v) of this section, the following definitions apply:

SATypeB = Type B sulfur allotments generated.
SATypeA = Type A sulfur allotments generated.
CR = Credits generated.
SBase = Refinery's sulfur baseline value under Sec. 80.295.
Sa = Average sulfur content of the gasoline produced at the 
refinery during 2003 (or for a foreign refinery, all gasoline produced 
during 2003 that was imported into the U.S.).
V = Volume of gasoline produced at the refinery during 2003 (or for a 
foreign refinery, all gasoline produced during 2003 that was imported 
into the U.S.).

    (b) Generation of allotments in 2004 and 2005. During 2004 and 2005 
only, refiners and importers that have corporate pool average sulfur 
levels below the corporate pool average standards under Sec. 80.195 may 
generate sulfur allotments separately for each year using the following 
procedures.
    (1) If the average sulfur content of the gasoline produced or 
imported is less than 30 the following procedures apply:

SATypeB = (30 - Sa) x Va
SATypeA = (SPS - 30) x Va

    (2) If the average sulfur content of the gasoline produced or 
imported is equal to or greater than 30 the following procedures apply:

SATypeA = (SPS - Sa) x Va

    (3) For purposes of the equations under paragraphs (b)(1) and (2) of 
this section, the following definitions apply:

SATypeB = Type B sulfur allotments generated.
SATypeA = Type A sulfur allotments generated.
Sa = Corporate pool average sulfur level for the year.
SPS = Corporate pool average standard (120 in 2004; 90 in 
2005).
Va = Total volume of gasoline produced and/or imported during 
the year.

    (4) Oxygenate blenders may not generate allotments under this 
section.
    (c) Use of sulfur allotments to meet standards. (1) Refiners and 
importers may use Type A and Type B sulfur allotments to meet the 
corporate pool average standards under Sec. 80.195, except that if 
allotments generated in 2003 or 2004 are used to meet the corporate pool 
standard in 2005 the allotments generated in 2003 or 2004 shall be 
reduced in value by 50%.
    (2)(i) Small refiners subject to the standards under Sec. 80.240, 
and refiners and importers of gasoline designated as GPA gasoline under 
Sec. 80.219(a), may use sulfur allotments to meet their annual average 
refinery or importer standards.
    (ii) Small refiners subject to the standards under Sec. 80.240 and 
that have received an adjustment of their per-gallon cap sulfur 
standards pursuant to Sec. 80.271(a) may also use sulfur allotments to 
meet the requirements of Sec. 80.271(d)(1) for any refinery that has 
received such an adjustment.
    (d) Transfers of sulfur allotments. Sulfur allotments generated 
under this section may be transferred, provided that:
    (1) No allotment may be transferred more than twice: The first 
transfer by the refiner or importer who generated the allotment may only 
be made to a refiner or importer who intends to use the allotment; if 
the transferee cannot use the allotment, it may make the second, and 
final, transfer only to a refiner or importer who intends to use the 
allotment. In no case may an allotment be transferred more than twice 
before being used or terminated.
    (2) The allotment transferor must apply any allotments necessary to 
meet the transferor's corporate pool average standard before 
transferring allotments to any other refiner or importer or before 
converting allotments into credits.
    (3) The transferor must supply to the transferee records indicating 
the year of generation and type of the allotments, the identity of the 
refiner or importer who generated the allotments, and the identity of 
the transferring party, if it is not the same part that generated the 
allotments.

[[Page 870]]

    (4) The transferor must inform the transferee whether any 
transferred allotments are Type A allotments or Type B allotments, as 
defined in paragraphs (a) and (b) of this section.
    (5) In the case of allotments that have been calculated or created 
improperly, or are otherwise determined to be invalid, the following 
provisions apply:
    (i) Invalid allotments cannot be used to achieve compliance with the 
transferee's corporate pool average standard or be converted to credits, 
regardless of the transferee's good faith belief that the allotments 
were valid.
    (ii) The refiner or importer who used the allotments, and any 
transferor of the allotments, must adjust their allotment records and 
reports and sulfur calculations as necessary to reflect the proper 
allotments.
    (iii) Any allotments remaining after correcting for the improperly 
created allotments must first be applied to correct the invalid 
transfers before the transferor may transfer any other allotments or 
before converting allotments into credits.
    (e) Conversion of allotments into credits. A refiner or importer may 
convert allotments into credits using the following procedures:
    (1) Type A allotments may be converted into credits with the same 
requirements and limitations on use that apply under Sec. 80.315 to 
credits generated in 2000 through 2003.
    (2) Type B allotments may be converted into credits with the same 
requirements and limitations on use that apply under Sec. 80.315 to 
credits generated in 2004 and later, based on the year of creation of 
the allotment.
    (3) Allotments generated in 2003 or 2004 which are carried over to 
2005 are discounted by 50 percent. The discounted allotments may be used 
to demonstrate compliance with the corporate pool average standard in 
2005, or they may be converted into credits for use in demonstrating 
compliance with the refinery average standard in 2005, or in a 
subsequent averaging period, in accordance with the provisions of this 
paragraph (e). Any allotments generated in 2003 or 2004 that are 
converted into credits before being carried over to 2005 are not 
discounted. Any allotments generated in 2003 or 2004 that are converted 
into credits before being carried over to 2005 may be reconverted into 
allotments for use in demonstrating compliance with the corporate pool 
average standard in 2005, but such reconverted allotments are discounted 
by 50 percent.
    (f) Small refiners. Small refiners subject to the standards under 
Sec. 80.240 may not generate sulfur allotments under paragraph (b) of 
this section.
    (g) GPA gasoline. GPA gasoline that is included in the refiner's or 
importer's corporate pool average under Sec. 80.216(f)(2) must be 
included in the calculations under paragraph (b) of this section. No 
refiner or importer may generate allotments in 2004 or 2005 who is not 
required to meet the corporate pool average standards.
    (h) Allotments and credits under this program are in units of ``ppm-
gallons''.

[65 FR 6823, Feb. 10, 2000, as amended at 67 FR 40183, June 12, 2002]

    Averaging, Banking and Trading (ABT) Program--General Information



Sec. 80.280  [Reserved]



Sec. 80.285  Who may generate credits under the ABT program?

    (a) Credit generation in 2000 through 2003. (1) Credits may be 
generated in 2000 through 2003 under Sec. 80.305 by refiners who 
produce gasoline from crude oil, and are:
    (i) Refiners who establish a sulfur baseline under Sec. 80.295 for 
a refinery;
    (ii) Foreign refiners for refineries with an approved baseline under 
Sec. 80.94, or refineries with baselines established in accordance with 
Sec. 80.290(d); or
    (iii) Small refiners for any refinery subject to the standards under 
Sec. 80.240, using their small refiner baseline established under Sec. 
80.250 for that refinery.
    (2) Importers and oxygenate blenders may not generate credits under 
Sec. 80.305.
    (b) Credit generation beginning in 2004. (1) Credits may be 
generated beginning in 2004 under Sec. 80.310 by:
    (i) Refiners for any refinery, and importers subject to the 
standards under Sec. 80.195;

[[Page 871]]

    (ii) Refiners and importers of gasoline designated as GPA gasoline 
under Sec. 80.219, using the least of 150.00 ppm, or the refinery's or 
importer's 1997-98 baseline calculated under Sec. 80.295 plus 30.00 
ppm, or the refinery's lowest annual average sulfur level for any year 
from 2000 through 2003 during which the refinery generated credits or 
allotments plus 30.00 ppm (for any party generating credits under both 
paragraphs (b)(1)(i) of this section and this paragraph (b)(1)(ii), such 
credits must be calculated separately); or
    (iii) Small refiners for any refinery subject to the standards under 
Sec. 80.240, using refinery's standard established under Sec. 80.240.
    (2) Generation of credits under Sec. 80.310 for all imported 
gasoline shall be through the importer.
    (3) Oxygenate blenders may not generate credits under Sec. 80.310.

[65 FR 6823, Feb. 10, 2000, as amended at 66 FR 19307, Apr. 13, 2001; 67 
FR 40183, June 12, 2002; 71 FR 54912, Sept. 20, 2006]



Sec. 80.290  How does a refiner apply for a sulfur baseline?

    (a) The refiner must submit an application to EPA which includes the 
information required under paragraph (c) of this section no later than 
September 30 of the year in which the refiner plans to begin generating 
credits, or the refiner or an importer plans to sell gasoline in the 
geographic phase-in area in accordance with Sec. 80.217.
    (b) The sulfur baseline request must be sent to: U.S. EPA, Attn: 
Sulfur Program (6406J), 1200 Pennsylvania Ave., NW Washington, DC 20460. 
For commercial (non-postal) delivery: U.S. EPA, Attn: Sulfur Program, 
501 3rd Street NW., Washington, DC 20001.
    (c) The sulfur baseline application must include the following 
information:
    (1) A listing of the names and addresses of all refineries owned by 
the corporation for which the refiner is applying for a sulfur baseline.
    (2) The annual average gasoline sulfur baseline for gasoline 
produced in 1997-1998, for each refinery for which the refiner is 
applying for a sulfur baseline, calculated in accordance with Sec. 
80.295.
    (3) A letter signed by the president, chief operating or chief 
executive officer, of the company, or his/her delegate, stating that the 
information contained in the sulfur baseline determination is true to 
the best of his/her knowledge.
    (4) Name, address, phone number, facsimile number and E-mail address 
of a corporate contact person.
    (5) The following information for each batch of gasoline produced in 
1997-1998:
    (i) Batch number assigned to the batch under Sec. 80.65(d) or Sec. 
80.101(i);
    (ii) Volume; and
    (iii) Sulfur content.
    (6) For any refiner that acquires and/or reactivates a refinery that 
was shut down or non-operational between January 1, 1997, and December 
31, 1998, the average sulfur level of gasoline produced during each 
annual averaging period that the refinery was in operation after the 
refinery was acquired and/or reactivated. EPA will evaluate all of the 
data submitted by the refiner in determining the appropriate sulfur 
baseline for the refinery. Where EPA concludes that the data submitted 
reasonably reflects current sulfur levels, the refinery's baseline will 
be determined based on the average sulfur content of the refinery's 
gasoline production during the most recent annual averaging period the 
refinery was in operation.
    (d)(1) Foreign refiners who do not have an approved refinery 
baseline under Sec. 80.94 must follow the procedures specified in Sec. 
80.410(b).
    (2) Foreign refiners who have an approved individual refinery 
baseline under Sec. 80.94, but one that was not in effect for purposes 
of anti-dumping compliance during the 1997-1998 annual averaging 
periods, must comply with the requirements of this section for the 
gasoline produced at the refinery and imported to the U.S. during each 
annual averaging period in which the refinery was subject to its 
individual anti-dumping baseline. EPA will evaluate all of the 
information and data submitted under this section in determining a 
foreign refinery's sulfur baseline pursuant to this paragraph (d). Where 
EPA concludes that the data submitted reasonably reflects current

[[Page 872]]

sulfur levels, a foreign refinery's baseline sulfur level under this 
paragraph will be determined based on the average sulfur level of 
gasoline produced by the foreign refinery and imported to the U.S. 
during the most recent annual averaging period in which the refinery was 
subject to its individual anti-dumping baseline.
    (e) Within 60 days of receipt of an application under this section, 
EPA will notify the refiner of approval of the refinery's baseline or of 
any deficiencies in the application.
    (f) If at any time the baseline submitted in accordance with the 
requirements of this section is determined to be incorrect, EPA will 
notify the refiner of the corrected baseline.
    (g) Any refiner that seeks temporary relief under Sec. 80.270 shall 
apply for a refinery sulfur baseline in accordance with the provisions 
of this section and Sec. 80.295, and if applicable, Sec. 80.410(b), no 
later than September 1, 2000.

[65 FR 6823, Feb. 10, 2000, as amended at 66 FR 19308, Apr. 13, 2001]

                   ABT Program--Baseline Determination



Sec. 80.295  How is a refinery sulfur baseline determined?

    (a) A refinery's gasoline sulfur baseline for the purpose of 
generating credits during years 2000 through 2003 is calculated using 
the following equation:
[GRAPHIC] [TIFF OMITTED] TR10FE00.011

Where:

SBase=Sulfur baseline value.
Vi=Volume of gasoline batch i.
Si=Sulfur content of gasoline batch i.
n = Total number of batches of gasoline produced during January 1, 1997 
through December 31, 1998 (or the total number of batches of gasoline 
pursuant to Sec. 80.290(c)(6); or, for a foreign refinery, the total 
number of batches of gasoline produced and imported into the U.S. during 
January 1, 1997 through December 31, 1998, or, the total number of 
batches of gasoline produced and imported into the U.S. pursuant to 
Sec. 80.290(d)(2)).
i = Individual batch of gasoline produced during January 1, 1997 through 
December 31, 1998 (or individual batch of gasoline produced pursuant to 
Sec. 80.290(c)(6); or, for a foreign refinery, individual batch of 
gasoline produced and imported into the U.S. during January 1, 1997 
through December 31, 1998, or, individual batch of gasoline produced and 
imported into the U.S. pursuant to Sec. 80.290(d)(2)).

    (b) Any refiner who, under Sec. 80.69 or Sec. 80.101(d)(4), 
included oxygenate blended downstream in compliance calculations for 
1997-1998 for a refinery must include this oxygenate in the baseline 
calculations for sulfur content for that refinery under paragraph (a) of 
this section.
    (c) Sulfur baseline calculations under this section shall be 
conducted to two decimal places.

[65 FR 6823, Feb. 10, 2000, as amended at 66 FR 19308, Apr. 13, 2001]



Sec. 80.300  [Reserved]

                     ABT Program--Credit Generation



Sec. 80.305  How are credits generated during the time period 
2000 through 2003?

    (a) Credits must be calculated as follows:

CRa=Va x (SBase - Sa)

Where:

CRa=Credits generated for the averaging period.
Va = Total volume of gasoline produced during the averaging 
period at the refinery (or for a foreign refinery, the total volume of 
gasoline produced during the averaging period at the refinery that was 
imported into the U.S. in accordance with the requirements of Sec. 
80.410)
SBase=Sulfur baseline value for the refinery established 
under Sec. 80.250 or Sec. 80.295.
Sa = Actual annual average sulfur level, calculated in 
accordance with the provisions of Sec. 80.205, for gasoline produced 
during the averaging period by the refinery, exclusive of any credits, 
(or for a foreign refinery, the actual average sulfur level, calculated 
in accordance with the provisions of Sec. 80.205, for gasoline produced 
during the averaging period at the refinery that was imported into the 
U.S., in accordance with the requirements of Sec. 80.410, exclusive of 
any credits.)

    (b) The refiner may include any oxygenates included in its RFG or 
conventional gasoline volume under Sec. Sec. 80.65

[[Page 873]]

and 80.101(d)(4), respectively, for the purpose of generating credits.
    (c) Credits under this program are in units of ``ppm-gallons''.
    (d) Refiners may generate credits for gasoline produced during an 
averaging period for a refinery only if the annual average sulfur level 
for the gasoline produced at that refinery during the averaging period 
is less than 0.90 of the refinery's baseline under Sec. 80.250 or Sec. 
80.295.
    (e) Credits generated in accordance with paragraph (a) of this 
section must be identified by the year of creation.
    (f) For gasoline produced during the year 2000, the averaging period 
for credits generated in accordance with paragraph (a) of this section 
may be less than the full calendar year. Such partial-year averaging 
period will begin with the first full month for which all applicable 
sampling, testing, and documentation requirements are met.

[65 FR 6823, Feb. 10, 2000, as amended at 66 FR 19308, Apr. 13, 2001; 67 
FR 40183, June 12, 2002]



Sec. 80.310  How are credits generated beginning in 2004?

    (a) A refiner for any refinery, or an importer, may generate credits 
in 2004 and thereafter if the annual average sulfur level for gasoline 
produced or imported for the averaging period is less than 30.00 ppm; 
or, for refiners that are subject to the small refiner standards in 
Sec. 80.240, the small refiner annual average sulfur standard 
applicable to that refinery; or, for refiners and importers subject to 
the GPA standards in Sec. 80.216, the least of 150.00 ppm, or the 
refinery's or importer's 1997-1998 sulfur level calculated under Sec. 
80.295 plus 30.00 ppm, or the refinery's lowest annual average sulfur 
level for any year from 2000 through 2003 during which the refinery 
generated credits or allotments plus 30.00 ppm.
    (b) Credits are calculated as follows:

CRa = Va x (SCredit - Sa)

Where:

CRa = Credits generated for the averaging period.
Va = Total annual volume of gasoline produced at a refinery 
or imported during the averaging period.
SCredit = 30.00 ppm; or the sulfur standard for a small 
refinery established under Sec. 80.240; or, for gasoline designated as 
GPA gasoline under Sec. 80.219, the least of 150.00 ppm, or the 
refinery's or importer's 1997-1998 sulfur level calculated under Sec. 
80.295 plus 30.00 ppm, or the refinery's lowest annual average sulfur 
level for any year from 2000 through 2003 during which the refinery 
generated credits or allotments plus 30.00 ppm.
Sa = Actual annual average sulfur level, calculated in 
accordance with the provisions of Sec. 80.205, for gasoline produced at 
a refinery or imported during the averaging period, exclusive of any 
credits.

    (c) Credits generated in accordance with this section must be 
identified by the year of creation.

[65 FR 6823, Feb. 10, 2000, as amended at 66 FR 19308, Apr. 13, 2001; 67 
FR 40184, June 12, 2002; 71 FR 54912, Sept. 20, 2006]

                         ABT Program--Credit Use



Sec. 80.315  How are credits used and what are the limitations on credit use?

    (a) Credit use. Credits may be used to meet the applicable refinery 
or importer annual average sulfur standards under Sec. 80.195, Sec. 
80.216, or Sec. 80.240, or may be used to meet the offset requirement 
under Sec. 80.271(d)(1) for any refinery with an adjustment of itsper-
gallon cap standard pursuant to Sec. 80.271(a), provided that:
    (1) Sulfur credits used were generated pursuant to the requirements 
of this subpart; and
    (2) The requirements of paragraphs (b) and (c) of this section are 
met.
    (b) Credit transfers. (1) Credits obtained from other persons may be 
used to meet the annual average standards specified in Sec. 80.195, 
Sec. 80.216, or Sec. 80.240, or may be used to meet the offset 
requirement under Sec. 80.271(d)(1) for any refinery with an adjustment 
of itsper-gallon cap standard pursuant to Sec. 80.271(a), if all the 
following conditions are met:
    (i) The credits are generated and reported according to the 
requirements of this subpart.
    (ii) The credits are used in compliance with the limitations 
regarding the appropriate periods for credit use in this subpart.
    (iii) Any credit transfer takes place no later than the last day of 
February

[[Page 874]]

following the calendar year averaging period when the credits are used.
    (iv) No credit may be transferred more than twice: The first 
transfer by the refiner or importer who generated the credit may only be 
made to a refiner or importer who intends to use the credit; if the 
transferee cannot use the credit, it may make the second, and final, 
transfer only to a refiner or importer who intends to use the credit. In 
no case may a credit be transferred more than twice before being used or 
terminated.
    (v) The credit transferor must apply any credits necessary to meet 
the transferor's applicable average standard before transferring credits 
to any other refiner or importer.
    (vi) No credits may be transferred that would result in the 
transferor having a negative credit balance.
    (vii) Each transferor must supply to the transferee records 
indicating the years the credits were generated, the identity of the 
refiner or importer who generated the credits, and the identity of the 
transferring party, if it is not the same party that generated the 
credits.
    (2) In the case of credits that have been calculated or created 
improperly, or are otherwise determined to be invalid, the following 
provisions apply:
    (i) Where a refiner's baseline has been determined to be incorrect 
under Sec. 80.250(c) or Sec. 80.290(f), any credits generated, banked, 
used or traded must be adjusted to reflect the corrected baseline.
    (ii) Invalid credits cannot be used to achieve compliance with the 
transferee's averaging standard, regardless of the transferee's good 
faith belief that the credits were valid.
    (iii) The refiner or importer who used the credits, and any 
transferor of the credits, must adjust their credit records and reports 
and sulfur calculations as necessary to reflect the proper credits.
    (iv) Any properly created credits existing in the transferor's 
credit balance after correcting the credit balance, and after the 
transferor applies credits as needed to meet the average standard at the 
end of the compliance year, must first be applied to correct the invalid 
transfers before the transferor trades or banks the credits.
    (c) Limitations on credit use. (1) Credits generated prior to 2004 
may only be used for demonstrating compliance with the refinery or 
importer annual average standards under Sec. 80.195 during the 2005 and 
2006 averaging periods. Such credits may be used to demonstrate 
compliance with the standards under Sec. 80.216 during the 2004 through 
2006 averaging periods, and with the standards under Sec. 80.240 during 
the 2004 through 2007 averaging periods, and the 2008 and 2009 averaging 
periods, if allowed under the terms of a hardship extension under Sec. 
80.265.
    (2) Credits generated in 2004 or later may only be used for 
demonstrating compliance with standards during an averaging period 
within five years of the year of generation.
    (3) A refiner or importer possessing credits must use all credits 
prior to falling into compliance deficit under Sec. 80.205(e).
    (4) Credits may not be used to meet corporate pool average standards 
under Sec. 80.195.

[65 FR 6823, Feb. 10, 2000, as amended at 67 FR 40184, June 12, 2002]



Sec. Sec. 80.320-80.325  [Reserved]

 Sampling, Testing and Retention Requirements for Refiners
 and Importers



Sec. 80.330  What are the sampling and testing requirements for
refiners and importers?

    (a) Sample and test each batch of gasoline. (1) Refiners and 
importers shall collect a representative sample from each batch of 
gasoline produced or imported and test each sample to determine its 
sulfur content for compliance with requirements under this subpart prior 
to the gasoline leaving the refinery or import facility, using the 
sampling and testing methods provided in this section.
    (2) Except as provided in paragraph (a)(3) of this section, the 
requirements of this section apply beginning January 1, 2004, or January 
1 of the first year of allotment or credit generation under Sec. 80.275 
or Sec. 80.305, whichever is earlier.

[[Page 875]]

    (3) Prior to January 1, 2004:
    (i) Any refiner may release gasoline from the refinery prior to 
obtaining the test results required under paragraph (a)(1) of this 
section.
    (ii) Any refiner of conventional gasoline may combine samples of 
gasoline from more than one batch of gasoline or blendstock prior to 
analysis and treat such composite sample as one batch of gasoline or 
blendstock pursuant to the requirements of Sec. 80.101(i)(2).
    (4)(i) Beginning January 1, 2004, any refiner who produces gasoline 
using computer-controlled in-line blending equipment is exempt from the 
requirement of paragraph (a)(1) of this section to obtain the test 
results required under paragraph (a)(1) of this section prior to the 
gasoline leaving the refinery, provided that the refiner obtains an 
exemption from this requirement from EPA. To obtain such exemption, the 
refiner must:
    (A) Have been granted an in-line blending exemption under Sec. 
80.65(f)(4); or
    (B) If the refiner has not been granted an exemption under Sec. 
80.65(f)(4), submit to EPA all of the information required under Sec. 
80.65(f)(4)(i)(A). A letter signed by the president, chief operating or 
chief executive officer of the company, or his/her designee, stating 
that the information contained in the submission is true to the best of 
his/her belief must accompany any submission under this paragraph 
(a)(4)(i)(B).
    (ii) Refiners who seek an exemption under paragraph (a)(4)(i) of 
this section must comply with any request by EPA for additional 
information or any other requirements that EPA includes as part of the 
exemption.
    (iii) Within 60 days of EPA's receipt of a submission under 
paragraph (a)(4)(i)(B) of this section, EPA will notify the refiner if 
the exemption is not approved or of any deficiencies in the refiner's 
submission, or if any additional information is required or other 
requirements are included in the exemption pursuant to paragraph 
(a)(4)(ii) of this section. In the absence of such notification from 
EPA, the effective date of an exemption under paragraph (a)(4)(i) of 
this section for refiners who do not hold an exemption under Sec. 
80.65(f)(4) is 60 days from EPA's receipt of the refiner's submission 
under paragraph (a)(4)(i)(B) of this section.
    (iv) EPA reserves the right to modify the requirements of an 
exemption under paragraph (a)(4)(i) of this section, in whole or in 
part, at any time, if EPA determines that the refiner's operation does 
not effectively or adequately control, monitor or document the sulfur 
content of the refinery's gasoline production, or if EPA determines that 
any other circumstances exist which merit modification of the 
requirements of an exemption, such as advancements in the state of the 
art for in-line blending measurement which allow for additional control 
or more accurate monitoring or documentation of sulfur content. If EPA 
finds that a refiner provided false or inaccurate information in any 
submission required for an exemption under this section, upon 
notification from EPA, the refiner's exemption will be void ab initio.
    (b) Sampling methods. For purposes of paragraph (a) of this section, 
refiners and importers shall sample each batch of gasoline by using one 
of the following methods:
    (1) Manual sampling of tanks and pipelines shall be performed 
according to the applicable procedures specified in one of the two 
following methods:
    (i) American Society for Testing and Materials (ASTM) method D 4057-
95, entitled ``Standard Practice for Manual Sampling of Petroleum and 
Petroleum Products.''
    (ii) Samples collected under the applicable procedures in ASTM 
method D 5842-95, entitled ``Standard Practice for Sampling and Handling 
of Fuels for Volatility Measurement,'' may be used for measuring sulfur 
content if there is no contamination present that could affect the 
sulfur test result.
    (2) Automatic sampling of petroleum products in pipelines shall be 
performed according to the applicable procedures specified in ASTM 
method D 4177-95, entitled ``Standard Practice for Automatic Sampling of 
Petroleum and Petroleum Products.''
    (c) Test method for measuring sulfur content of gasoline. (1) For 
purposes of paragraph (a) of this section, refiners and importers shall 
use the method

[[Page 876]]

provided in Sec. 80.46(a)(1) or one of the alternative test methods 
listed in Sec. 80.46(a)(3) to measure the sulfur content of gasoline 
they produce or import.
    (2) Except as provided in Sec. 80.350 and in paragraph (c)(1) of 
this section, any ASTM sulfur test method for liquefied fuels may be 
used for quality assurance testing under Sec. 80.400, or to determine 
whether gasoline qualifies for a S-RGAS downstream standard, if the 
protocols of the ASTM method are followed and the alternative method is 
correlated to the method provided in Sec. 80.46(a)(1).
    (d) Test method for sulfur in butane. (1) Refiners and importers 
shall use the method provided in Sec. 80.46(a)(2) to measure the sulfur 
content of butane when the butane constitutes a batch of gasoline.
    (2) Except as provided in paragraph (d)(1) of this section, any ASTM 
sulfur test method for gaseous fuels may be used for quality assurance 
testing under Sec. Sec. 80.340(b)(4) and 80.400, if the protocols of 
the ASTM method are followed and the alternative method is correlated to 
the method provided in Sec. 80.46(a)(2).
    (e) Incorporations by reference. ASTM standard practices D 4057-95, 
D 4177-95 and D 5842-95 are incorporated by reference. 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. Copies 
may be obtained from the American Society for Testing and Materials, 100 
Barr Harbor Dr., West Conshohocken, PA 19428. Copies may be inspected at 
the Air Docket Section (LE-131), room M-1500, U.S. Environmental 
Protection Agency, Docket No. A-97-03, 1200 Pennsylvania Ave., NW., 
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.

[65 FR 6823, Feb. 10, 2000, as amended at 66 FR 19308, Apr. 13, 2001; 68 
FR 57820, Oct. 7, 2003]



Sec. 80.335  What gasoline sample retention requirements apply
to refiners and importers?

    (a) Sample retention requirements. Beginning January 1, 2004, or 
January 1 of the first year allotments or credits are generated under 
Sec. Sec. 80.275 and 80.305, whichever is earlier, any refiner or 
importer shall:
    (1) Collect a representative portion of each sample analyzed under 
Sec. 80.330(a), of at least 330 ml in volume;
    (2) Retain sample portions for the most recent 20 samples collected, 
or for each sample collected during the most recent 21 day period, 
whichever is greater, not to exceed 90 days for any given sample;
    (3) Comply with the gasoline sample handling and storage procedures 
under Sec. 80.330(b) for each sample portion retained; and
    (4) Comply with any request by EPA to:
    (i) Provide a retained sample portion to the Administrator's 
authorized representative; and
    (ii) Ship a retained sample portion to EPA, within 2 working days of 
the date of the request, by an overnight shipping service or comparable 
means, to the address and following procedures specified by EPA, and 
accompanied with the sulfur test result for the sample determined under 
Sec. 80.330(a).
    (b) Sample retention requirement for samples subject to independent 
analysis requirements. (1) Any refiner or importer who meets the 
independent analysis requirements under Sec. 80.65(f) for any batch of 
reformulated gasoline or RBOB will have met the requirements of 
paragraph (a) of this section, provided the independent laboratory meets 
the requirements of paragraph (a) of this section for the gasoline 
batch.
    (2) For samples retained by an independent laboratory under 
paragraph (b) of this section, the test results required to be submitted 
under paragraph (a) of this section shall be the test results determined 
under Sec. 80.65(e).
    (c) Sampling compliance certification. Any refiner or importer shall 
include with each annual report filed under Sec. 80.370, the following 
statement, which must accurately reflect the facts and

[[Page 877]]

must be signed and dated by the same person who signs the annual report:

    I certify that I have made inquiries that are sufficient to give me 
knowledge of the procedures to collect and store gasoline samples, and I 
further certify that the procedures meet the requirements of the ASTM 
procedures required under 40 CFR 80.330.

    (d) Prior to January 1, 2004, for purposes of complying with the 
requirements of this section, refiners who analyze composited samples 
under Sec. 80.330(a)(3) must retain portions of the composited samples. 
Portions of samples of each batch comprising the composited samples are 
not required to be retained.
    (e) For purposes of complying with the requirements of this section 
for RBOB, a sample of each RBOB batch produced plus a sample of the 
ethanol used to conduct the handblend testing pursuant to Sec. 80.69 
must be retained.

[65 FR 6823, Feb. 10, 2000, as amended at 66 FR 19309, Apr. 13, 2001]



Sec. 80.340  What standards and requirements apply to refiners 
producing gasoline by blending blendstocks into previously certified 

gasoline (PCG)?

    (a) Any refiner who produces gasoline by blending blendstock into 
PCG must meet the requirements of Sec. 80.330 to sample and test every 
batch of gasoline as follows:
    (1)(i) Sample and test to determine the volume and sulfur content of 
the PCG prior to blendstock blending.
    (ii) Sample and test to determine the volume and sulfur content of 
the gasoline subsequent to blendstock blending.
    (iii) Calculate the volume and sulfur content of the blendstock, by 
subtracting the volume and sulfur content of the PCG from the volume and 
sulfur content of the gasoline subsequent to blendstock blending. The 
blendstock is a batch for purposes of compliance calculations and 
reporting. For purposes of this paragraph (a), compliance with the 
applicable cap standard under Sec. 80.195(a) shall be determined based 
on the sulfur content of the gasoline subsequent to blendstock blending.
    (2) In the alternative, a refiner may sample and test each batch of 
blendstock when received at the refinery to determine the volume and 
sulfur content, and treat each blendstock receipt as a separate batch 
for purposes of compliance calculations for the annual average sulfur 
standard and for reporting. This alternative applies only if every batch 
of blendstock used at a refinery during an averaging period has a sulfur 
content that is equal to, or less than, the applicable per-gallon cap 
standard under Sec. Sec. 80.195 or 80.216.
    (b) Refiners who blend only butane into PCG may meet the sampling 
and testing requirements by using sulfur test results of the butane 
supplier, provided that the following requirements are also met:
    (1) The sulfur content of the butane received from the butane 
supplier must not exceed the following sulfur standards on a per-gallon 
basis as follows:
    (i) 120 ppm in 2004, and 30 ppm for 2005 and any subsequent year;
    (ii) Except that the per-gallon sulfur content of butane blended to 
PCG that is designated as GPA gasoline shall not exceed 150 ppm from 
January 1, 2004, through December 31, 2006.
    (2) The refiner obtains test results from the butane supplier that 
demonstrate that the sulfur content of each load of butane supplied does 
not exceed the applicable per-gallon sulfur standard under paragraph 
(b)(1) of this section through test results of samples of the butane 
contained in the storage tank from which the butane blender is supplied.
    (i) Testing for the sulfur content of the butane by the supplier 
must be subsequent to each receipt of butane into the supplier's storage 
tank, or the testing must be immediately before transfer of butane to 
the butane blender.
    (ii) The testing must be performed by the method specified in Sec. 
80.46(a)(2) or by the alternative method specified in Sec. 80.46(a)(4).
    (iii) The butane blender must obtain a copy of the butane supplier's 
test results, at the time of each transfer of butane to the butane 
blender, that reflect the sulfur content of each load of butane supplied 
to the butane blender.
    (3) The sulfur content and volume of each batch of gasoline produced 
is that of the butane the refiner blends into gasoline for purposes of 
calculating compliance with the standards in Sec. Sec. 80.195 and 
80.216.

[[Page 878]]

    (4) The refiner must conduct a quality assurance program of sampling 
and testing for each butane supplier that demonstrates the butane sulfur 
content does not exceed the applicable per-gallon sulfur standard in 
paragraph (b)(1) of this section. The frequency of butane sampling and 
testing, for each butane supplier, must be one sample for every 500,000 
gallons of butane received, or one sample every 3 months, whichever 
results in more frequent sampling.
    (5) If any of the requirements of this section are not met, in whole 
or in part, for any butane blended into gasoline, that butane is deemed 
in violation of the gasoline sulfur standards in Sec. 80.195 or Sec. 
80.216, as applicable.
    (c) The procedures in Sec. Sec. 80.65(i) and 80.101(g)(9) may be 
applied for purposes of demonstrating compliance with the sulfur 
standards under this subpart.

[65 FR 6823, Feb. 10, 2000, as amended at 66 FR 67108, Dec. 28, 2001; 68 
FR 57820, Oct. 7, 2003]



Sec. 80.345  [Reserved]



Sec. 80.350  What alternative sulfur standards and requirements 
apply to importers who transport gasoline by truck?

    Importers who import gasoline into the United States by truck may 
comply with the following requirements instead of the requirements to 
sample and test every batch of gasoline under Sec. 80.330, and the 
annual sulfur average and per-gallon cap standards otherwise applicable 
to importers under Sec. Sec. 80.195 and 80.216:
    (a) Alternative standards. The imported gasoline must comply with 
the standards in paragraph (a)(1) or (a)(2) of this section as follows:
    (1) The applicable average standards, corporate average standards 
and per-gallon standards under Sec. 80.195(a)(1), except that imported 
gasoline designated for use in the geographic phase-in area from January 
1, 2004, through December 31, 2006 must comply with an average standard 
of 150 ppm and a per-gallon standard of 300 ppm; or
    (2) In 2004, a per-gallon standard of 120 ppm, and in 2005 and 
subsequent years a per-gallon standard of 30 ppm, except that imported 
gasoline designated for use in the geographic phase-in area from January 
1, 2004, through December 31, 2006 must comply with a per-gallon 
standard of 150 ppm.
    (b) Terminal testing. The importer may use test results for sulfur 
content testing conducted by the terminal operator, for gasoline 
contained in the storage tank from which trucks used to transport 
gasoline into the United States are loaded, for purposes of 
demonstrating compliance with the standards in paragraph (a) of this 
section, provided the following conditions are met:
    (1) The sampling and testing shall be performed after each receipt 
of gasoline into the storage tank, or immediately before each transfer 
of gasoline to the importer's truck.
    (2) The sampling and testing shall be performed using the methods 
specified in Sec. 80.330(b) and Sec. 80.46(a)(1) or one of the 
alternative test methods listed in Sec. 80.46(a)(3), respectively.
    (3) At the time of each transfer of gasoline to the importer's truck 
for import to the U.S., the importer must obtain a copy of the terminal 
test result that indicates the sulfur content of the truck load.
    (c) Quality assurance program. The importer must conduct a quality 
assurance program, as specified in this paragraph, for each truck 
loading terminal.
    (1) Quality assurance samples must be obtained from the truck-
loading terminal and tested by the importer, or by an independent 
laboratory, and the terminal operator must not know in advance when 
samples are to be collected.
    (2) The sampling and testing must be performed using the methods 
specified in Sec. Sec. 80.330(b) and 80.46(a)(1), respectively.
    (3) The quality assurance test results for sulfur must differ from 
the terminal test result by no more than the ASTM reproducibility of the 
terminal's test results, as determined by the following equation:

R = 105x ((S+2)/10\4\)\0.4\

Where:

R = ASTM reproducibility.
S = Sulfur content based on the terminal's test result.


[[Page 879]]


    (4) The frequency of the quality assurance sampling and testing must 
be at least one sample for each fifty of an importer's trucks that are 
loaded at a terminal, or one sample per month, whichever is more 
frequent.
    (d) Party required to conduct quality assurance testing. The quality 
assurance program under paragraph (c) of this section shall be conducted 
by the importer. In the alternative, this testing may be conducted by an 
independent laboratory that meets the criteria under Sec. 
80.65(f)(2)(iii), provided the importer receives, no later than 21 days 
after the sample was taken, copies of all results of tests conducted.
    (e) Assignment of batch numbers. The importer must treat each truck 
load of imported gasoline as a separate batch for purposes of assigning 
batch numbers and maintaining records under Sec. 80.365, and reporting 
under Sec. 80.370.
    (f) EPA inspections of terminals. EPA inspectors or auditors, and 
auditors conducting attest engagements under Sec. 80.415, must be given 
full and immediate access to the truck-loading terminal and any 
laboratory at which samples of gasoline collected at the terminal are 
analyzed, and must be allowed to conduct inspections, review records, 
collect gasoline samples, and perform audits. These inspections or 
audits may be either announced or unannounced.
    (g) Certified Sulfur-FRGAS. This section does not apply to Certified 
Sulfur-FRGAS.
    (h) Reporting requirements. Any importer who elects to comply with 
the alternative standards in paragraph (a) of this section shall comply 
with the following requirements:
    (1) All importer recordkeeping and reporting requirements under 
Sec. Sec. 80.365 and 80.370, except as provided in paragraph (h)(2) of 
this section.
    (2) An importer who elects to comply with the alternative standards 
in paragraph (a)(2) of this section must certify in the annual report 
whether it is in compliance with the applicable per-gallon batch 
standard set forth in paragraph (a)(2) of this section, in lieu of 
providing the information required by Sec. 80.370(a) regarding annual 
average sulfur content and compliance with the average standard under 
Sec. 80.195.
    (i) Effect of noncompliance. If any of the requirements of this 
section are not met, all gasoline imported by the truck importer during 
the time any requirements are not met is deemed in violation of the 
gasoline sulfur average and per-gallon cap standards in Sec. 80.195 or 
Sec. 80.216, as applicable. Additionally, if any requirement is not 
met, EPA may notify the importer of the violation and, if the 
requirement is not fulfilled within 10 days of notification, the truck 
importer may not in the future use the sampling and testing provisions 
in this section in lieu of the provisions in Sec. 80.330.

[38 FR 1255, Jan. 10, 1973, as amended at 68 FR 57820, Oct. 7, 2003]



Sec. 80.355  [Reserved]

                Recordkeeping and Reporting Requirements



Sec. 80.360  [Reserved]



Sec. 80.365  What records must be kept?

    (a) Records that must be kept. Beginning January 1, 2004, any person 
who produces, imports, sells, offers for sale, dispenses, distributes, 
supplies, offers for supply, stores, or transports gasoline, shall keep 
records that contain the following information:
    (1) The product transfer document information required under 
Sec. Sec. 80.77, 80.106, 80.210 and 80.219; and
    (2) For any sampling and testing for sulfur content required under 
this subpart:
    (i) The location, date, time and storage tank or truck 
identification for each sample collected;
    (ii) The name and title of the person who collected the sample and 
the person who performed the test;
    (iii) The results of the test as originally printed by the testing 
apparatus, or where no printed result is produced, the results as 
originally recorded by the person who performed the test; and
    (iv) Any record that contains a test result for the sample that is 
not identical to the result recorded under paragraph (a)(2)(iii) of this 
section.
    (b) Additional records that refiners and importers must keep. 
Beginning January 1, 2004, or January 1 of the first year allotments or 
credits are generated

[[Page 880]]

under Sec. 80.275 or Sec. 80.305, whichever is earlier, any refiner 
for each of its refineries, and any importer for the gasoline it 
imports, shall keep records that include the following information:
    (1) For each batch of gasoline produced or imported:
    (i) The batch volume;
    (ii) The batch number assigned under Sec. 80.65(d)(3) and the 
appropriate designation under paragraph (b)(1)(i) of this section; 
except that if composite samples of conventional gasoline representing 
multiple batches produced subsequent to December 31, 2003, are tested 
under Sec. 80.101(i)(2) for anti-dumping compliance purposes, for 
purposes of this subpart a separate batch number must be assigned to 
each batch using the batch numbering procedures under Sec. 80.65(d)(3);
    (iii) The date of production or importation; and
    (iv) If appropriate, the designation of the batch as GPA gasoline 
under Sec. 80.219, California gasoline under Sec. 80.375, exempt 
gasoline for research and development under Sec. 80.380, or for export 
outside the United States.
    (2) Information regarding credits and allotments, separately kept 
for credits and for allotments; separately kept according to the year of 
creation for the credits and for the allotments; and for credit 
generation or use starting in 2004, separately kept for GPA gasoline and 
other gasoline. Information shall be kept separately for different types 
of allotments and credits generated under Sec. Sec. 80.275(e)(1), 
80.275(e)(2), 80.305 and 80.310:
    (i) The number in the refiner's or importer's possession at the 
beginning of the averaging period;
    (ii) The number generated;
    (iii) The number used;
    (iv) If any were obtained from or transferred to other parties, for 
each other party its name, its EPA refiner or importer registration 
number, and the number obtained from, or transferred to, the other 
party;
    (v) The number that expired at the end of the averaging period;
    (vi) The number of allotments, by type, that were converted into 
credits under Sec. 80.275(e);
    (vii) The number in the refiner's or importer's possession that will 
carry over into the subsequent averaging period; and
    (viii) Contracts or other commercial documents that establish each 
transfer of credits and allotments from the transferor to the 
transferee.
    (3) The calculations used to determine the applicable refiner 
baseline under Sec. 80.250 or Sec. 80.295.
    (4) The calculations used to determine compliance with the 
applicable sulfur average standards of Sec. 80.195, Sec. 80.216, Sec. 
80.240, or Sec. 80.270.
    (5) The calculations used to determine the number of credits or 
allotments generated under Sec. 80.305, Sec. 80.310 or Sec. 80.275.
    (6) The calculations used to determine any applicable adjusted cap 
standard under Sec. 80.195(d).
    (7) A copy of all reports submitted to EPA under Sec. 80.370.
    (8) In the case of parties who process transmix, records of any 
sampling and testing required under Sec. 80.213.
    (c) Additional records importers must keep. Any importer shall keep 
records that identify and verify the source of each batch of certified 
Sulfur-FRGAS and non-certified Sulfur-FRGAS imported and demonstrate 
compliance with the requirements for importers under Sec. 80.410(o).
    (d) Length of time records must be kept. The records required in 
this section shall be kept for five years from the date they were 
created; except that:
    (1) Transfers of credits and allotments. Records relating to credit 
and allotment transfers, except as provided in paragraph (d)(2) of this 
section, shall be kept by the transferor for 5 years from the date the 
credits or allotments are transferred, and shall be kept by the 
transferee for 5 years from the date the credits or allotments were 
transferred, used or terminated, whichever is later.
    (2) Early credits and allotments. (i) Where the party generating the 
credits or allotments does not transfer the credits or allotments, 
records must be kept for 5 years from the date of creation, use, or 
termination, whichever is later.
    (ii) Where early credits or allotments are transferred, records 
relating to such credits or allotments shall be kept by both parties for 
5 years from the date the credits or allotments were

[[Page 881]]

transferred, used, or terminated, whichever is later.
    (e) Make records available to EPA. On request by EPA the records 
required in paragraphs (a), (b) and (c) of this section shall be 
provided to the Administrator's authorized representative. For records 
that are electronically generated or maintained the equipment and 
software necessary to read the records shall be made available, or if 
requested by EPA, electronic records shall be converted to paper 
documents which shall be provided to the Administrator's authorized 
representative.

[65 FR 6823, Feb. 10, 2000, as amended at 67 FR 40184, June 12, 2002; 71 
FR 31964, June 2, 2006]



Sec. 80.370  What are the sulfur reporting requirements?

    Beginning with the 2004 averaging period, or the first year credits 
or allotments are generated under Sec. 80.275 or Sec. 80.305, 
whichever is earlier, and continuing for each averaging period 
thereafter, any refiner or importer shall submit to EPA annual reports 
that contain the information required in this section, and such other 
information as EPA may require.
    (a) Refiner and importer annual reports. Any refiner, for each of 
its refineries, and any importer for the gasoline it imports, shall 
submit a report for each calendar year averaging period that includes 
the following information, and in the case of a refiner or importer 
producing or importing both GPA gasoline and other gasoline, the 
information shall be separately reported:
    (1) The EPA importer, or refiner and refinery facility registration 
numbers;
    (2) The applicable baseline, average standard, and adjusted cap 
standard as follows:
    (i) For the years 2000 through 2003, the applicable baseline under 
Sec. 80.250 or Sec. 80.295.
    (ii) For the 2004 averaging period and subsequent averaging periods:
    (A) All applicable average standards under Sec. 80.195, Sec. 
80.216, Sec. 80.240 or Sec. 80.270;
    (B) All applicable adjusted cap standards under Sec. 80.195(d), 
with the 2005 report identifying both the 2004 and 2005 applicable 
adjusted cap standards;
    (3) The total volume of gasoline produced or imported;
    (4) The annual average sulfur level of the gasoline produced or 
imported;
    (5) The annual average sulfur level after inclusion of any credits 
and allotments;
    (6) Information, separately provided, for credits and allotments, 
and separately by year of creation, as follows:
    (i) The number of credits and allotments at the beginning of the 
averaging period;
    (ii) The number of credits and allotments generated;
    (iii) The number of credits and allotments used;
    (iv) If any credits or allotments were obtained from or transferred 
to other parties, for each other party its name and EPA refiner or 
importer registration number, and the number of credits or allotments 
obtained from or transferred to the other party;
    (v) The number of credits and allotments that expired at the end of 
the averaging period;
    (vi) The number of credits and allotments that will carry over into 
the subsequent averaging period; and
    (vii) The number of each type of allotments converted to credits;
    (7) For each batch of gasoline produced or imported during the 
averaging period:
    (i) The batch number assigned under Sec. 80.65(d)(3) and the 
appropriate designation under Sec. 80.365; except that if composite 
samples of conventional gasoline representing multiple batches produced 
subsequent to December 31, 2003, are tested under Sec. 80.101(i)(2) for 
anti-dumping compliance purposes, for purposes of this subpart a 
separate batch number must be assigned to each batch using the batch 
numbering procedures under Sec. 80.65(d)(3);
    (ii) The date the batch was produced;
    (iii) The volume of the batch; and
    (iv) The sulfur content of the batch as determined under Sec. 
80.330; and
    (v) For any batch of small refiner gasoline produced by any refinery 
with an adjustment of its per-gallon cap standard under Sec. 80.271(a), 
the number of sulfur credits or allotments required under paragraph 
(d)(1) of this section, the number of credits or allotments

[[Page 882]]

used, and the source(s) of these credits or allotments.
    (8) When submitting reports under this paragraph (a), any importer 
shall exclude certified Sulfur-FRGAS.
    (b) Additional reporting requirements for importers. Any importer 
shall report the following information for Sulfur-FRGAS imported during 
the averaging period:
    (1) The EPA refiner and refinery registration numbers of each 
foreign refiner and refinery where the certified Sulfur-FRGAS was 
produced; and
    (2) The total gallons of certified Sulfur-FRGAS and non-certified 
Sulfur-FRGAS imported from each foreign refiner and refinery.
    (c) Corporate pool average reports. (1) Annual reports filed under 
this section for the 2004 and 2005 averaging periods must include the 
party's corporate pool average as determined under Sec. 80.205.
    (2) If the party submitting the annual report under paragraph (c)(1) 
of this section is a refiner with more than one refinery or is a refiner 
who also imports gasoline, then for the purposes of this paragraph, the 
party shall report the information required for individual refineries 
and for importers under paragraph (a) of this section, also in the 
aggregate for all the gasoline produced and imported during the calendar 
year.
    (3) Refiners and importers exempted from corporate pool standards 
under Sec. 80.216 or Sec. 80.240 are exempt from reporting the 
information required under paragraphs (c)(1) and (c)(2) of this section.
    (4) A parent company must identify in the corporate pool average 
reports required under paragraph (c)(1) of this section any refinery 
facilities owned by the parent company, any subsidiaries wholly-owned by 
the parent company, and any refinery facilities of the parent company's 
wholly-owned subsidiaries, except as provided in paragraph (c)(5) of 
this section.
    (5) Where the wholly-owned subsidiaries of a parent company comply 
with the corporate pool average standards individually pursuant to Sec. 
80.195(c)(6)(ii):
    (i) The corporate pool average reports required under paragraph 
(c)(1) of this section must be submitted by each wholly-owned subsidiary 
of the parent company;
    (ii) Each wholly-owned subsidiary of the parent company must 
identify in the corporate pool average reports required under paragraph 
(c)(1) of this section the subsidiary's parent company and any refinery 
facilities of the subsidiary; and
    (iii) The parent company must submit the corporate pool average 
reports required under paragraph (c)(1) of this section for any refinery 
facilities owned by the parent company which are not the refinery 
facilities of the parent company's wholly-owned subsidiaries.
    (d) Report submission. Any annual report required under this section 
shall be:
    (1) Signed and certified as meeting all of the applicable 
requirements of this subpart by the owner or a responsible corporate 
officer of the refiner or importer; and
    (2) Submitted to EPA no later than the last day of February for the 
prior calendar year averaging period.
    (f) Attest reports. Attest reports for refiner and importer attest 
engagements required under Sec. 80.415 shall be submitted to the 
Administrator by May 31 of each year for the prior calendar year 
averaging period.

[65 FR 6823, Feb. 10, 2000, as amended at 67 FR 40184, June 12, 2002]



Sec. Sec. 80.371-80.373  [Reserved]

                               Exemptions



Sec. 80.374  What if a refiner or importer is unable to produce 
gasoline conforming to the requirements of this subpart?

    In appropriate extreme and unusual circumstances (e.g., natural 
disaster or Act of God) which are clearly outside the control of the 
refiner or importer and which could not have been avoided by the 
exercise of prudence, diligence, and due care, EPA may permit a refiner 
or importer, for a brief period, to distribute gasoline which does not 
meet the requirements of this subpart provided the refiner or importer 
meets all the criteria, requirements and conditions contained in Sec. 
80.73 (a) through (e).

[[Page 883]]



Sec. 80.375  What requirements apply to California gasoline?

    (a) Definition. For purposes of this subpart California gasoline 
means any gasoline designated by the refiner as for use in California.
    (b) California gasoline exemption. California gasoline that complies 
with all the requirements of this section is exempt from all other 
provisions of this subpart.
    (c) Requirements for California gasoline. The requirements are:
    (1) Each batch of California gasoline must be designated as such by 
its refiner or importer;
    (2) Designated California gasoline must be kept segregated from 
gasoline that is not California gasoline, at all points in the 
distribution system;
    (3) Designated California gasoline must ultimately be used in the 
State of California and not used elsewhere;
    (4) In the case of California gasoline produced outside the State of 
California, the transferors and transferees must meet the product 
transfer document requirements under Sec. 80.81(g); and
    (5) Gasoline that is ultimately used in any part of the United 
States outside of the State of California must comply with the standards 
and requirements of this subpart, regardless of any designation as 
California gasoline.
    (d) Use of California test methods and off site sampling procedures. 
In the case of any gasoline that is not California gasoline and that is 
either produced at a refinery located in the State of California or is 
imported from outside the United States into the State of California, 
the refiner or importer may, with regard to such gasoline:
    (1) Use the sampling and testing methods approved in Title 13 of the 
California Code of Regulations instead of the sampling and testing 
methods required under Sec. 80.330; and
    (2) Determine the sulfur content of gasoline at off site tankage as 
permitted in Sec. 80.81(h)(2).



Sec. 80.380  What are the requirements for obtaining an exemption for
gasoline used for research, development or testing purposes?

    Any person may request an exemption from the provisions of this 
subpart for gasoline used for research, development or testing (``R&D'') 
purposes by submitting to EPA an application that includes all the 
information listed in paragraph (b) of this section.
    (a) Criteria for an R&D exemption. For an R&D exemption to be 
granted, the proposed test program must:
    (1) Have a purpose that constitutes an appropriate basis for 
exemption;
    (2) Necessitate the granting of an exemption;
    (3) Be reasonable in scope; and
    (4) Have a degree of control consistent with the purpose of the 
program and EPA's monitoring requirements.
    (b) Information required to be submitted. To demonstrate each of the 
four elements in paragraphs (a)(1) through (4) of this section, the 
application required under this section must include the following 
information:
    (1) A statement of the purpose of the program demonstrating that the 
program has an appropriate R&D purpose.
    (2) An explanation of why the stated purpose of the program cannot 
be achieved in a practicable manner without performing one or more of 
the prohibited acts under Sec. 80.385.
    (3) To demonstrate the reasonableness of the scope of the program:
    (i) An estimate of the program's beginning and ending dates;
    (ii) An estimate of the maximum number of vehicles and engines 
involved in the program, and the number of miles and engine hours that 
will be accumulated on each;
    (iii) The sulfur content of the gasoline expected to be used in the 
program; and
    (iv) The quantity of gasoline that exceeds the applicable sulfur 
standard that is expected to be used in the program.
    (4) With regard to control, a demonstration that the program affords 
EPA a monitoring capability, including at a minimum:
    (i) A description of the technical and operational aspects of the 
program;
    (ii) The site(s) of the program (including street address, city, 
county, State, and ZIP code);
    (iii) The manner in which information on vehicles and engines used 
in the program will be recorded and made available to EPA;

[[Page 884]]

    (iv) The manner in which results of the program will be recorded and 
made available to EPA;
    (v) The manner in which information on the gasoline used in the 
program (including quantity, sulfur content, name, address, telephone 
number and contact person of the supplier, and the date received from 
the supplier), will be recorded and made available to EPA;
    (vi) The manner in which distribution pumps will be labeled to 
insure proper use of the gasoline where appropriate;
    (vii) The name, address, telephone number and title of the person(s) 
in the organization requesting an exemption from whom further 
information on the application may be obtained; and
    (viii) The name, address, telephone number and title of the 
person(s) in the organization requesting an exemption who is responsible 
for recording and making available the information specified in 
paragraphs (b)(4)(iii), (iv) and (v) of this section, and the location 
in which such information will be maintained.
    (c) Additional requirements. (1) The product transfer documents 
associated with R&D gasoline must identify the gasoline as such, and 
must state that the gasoline is to be used only for research, 
development, or testing purposes.
    (2) The R&D gasoline must be designated by the refiner or importer 
as exempt R&D gasoline.
    (3) The R&D gasoline must be kept segregated from non-exempt 
gasoline at all points in the distribution system of the gasoline.
    (4) The R&D gasoline must not be sold, distributed, offered for sale 
or distribution, dispensed, supplied, offered for supply, transported to 
or from, or stored by a gasoline retail outlet, or by a wholesale 
purchaser-consumer facility, unless the wholesale purchaser-consumer 
facility is associated with the R&D program that uses the gasoline.
    (d) Memorandum of exemption. The Administrator will grant an R&D 
exemption upon a demonstration that the requirements of this section 
have been met. The R&D exemption will be granted in the form of a 
memorandum of exemption signed by the applicant and the Administrator 
(or delegate), which may include such terms and conditions as the 
Administrator determines necessary to monitor the exemption and to carry 
out the purposes of this section, including restoration of motor vehicle 
emissions control systems. Any violation of such a term or condition of 
the exemption or any requirement under this section will cause the 
exemption to be void ab initio.
    (e) Effects of exemption. Gasoline that is subject to an R&D 
exemption under this section is exempt from other provisions of this 
subpart provided that the gasoline is used in a manner that complies 
with the memorandum of exemption granted under paragraph (d) of this 
section.



Sec. 80.382  What requirements apply to gasoline for use in American
Samoa, Guam and the Commonwealth of the Northern Mariana Islands?

    The gasoline sulfur standards of Sec. Sec. 80.195 and 80.240(a) do 
not apply to gasoline that is produced, imported, sold, offered for 
sale, supplied, offered for supply, stored, dispensed, or transported 
for use in the Territories of Guam, American Samoa or the Commonwealth 
of the Northern Mariana Islands, provided that such gasoline is:
    (a) Designated by the refiner or importer as high sulfur gasoline 
only for use in Guam, American Samoa, or the Commonwealth of the 
Northern Mariana Islands;
    (b) Used only in Guam, American Samoa, or the Commonwealth of the 
Northern Mariana Islands;
    (c) Accompanied by documentation that complies with the product 
transfer document requirements of Sec. 80.365; and
    (d) Segregated from non-exempt high sulfur fuel at all points in the 
distribution system from the point the fuel is designated as exempt fuel 
only for use in Guam, American Samoa, or the Commonwealth of the 
Northern Mariana Islands, while the exempt fuel is in the United States 
but outside these Territories.

[71 FR 78093, Dec. 28, 2006]

[[Page 885]]

                          Violation Provisions



Sec. 80.385  What acts are prohibited under the gasoline sulfur program?

    No person shall:
    (a) Averaging violation. Produce or import gasoline that does not 
comply with the applicable sulfur average standard under Sec. 80.195, 
Sec. 80.216 or Sec. 80.240.
    (b) Cap standard violation. Produce, import, sell, offer for sale, 
dispense, supply, offer for supply, store or transport gasoline that 
does not comply with the applicable sulfur cap standard under Sec. 
80.195, Sec. 80.216, Sec. 80.210, Sec. 80.220, Sec. 80.240, or does 
not comply with an adjusted cap standard approved for a small refiner 
under Sec. 80.271.
    (c) Causing an averaging, cap standard, or geographic phase-in area 
(GPA) use violation. Cause another person to commit an act in violation 
of paragraph (a), (b), or (f) of this section.
    (d) Causing violating gasoline to be in the distribution system. 
Cause gasoline to be in the distribution system which does not comply 
with an applicable sulfur cap standard under Sec. 80.195, Sec. 80.210, 
Sec. 80.216, Sec. 80.220 or Sec. 80.240; a sulfur average standard 
under Sec. 80.195, Sec. 80.216 or Sec. 80.240; or a GPA use 
prohibition under Sec. 80.219(c).
    (e) Denatured ethanol violation. Blend into gasoline denatured 
ethanol with a sulfur content higher than 30 ppm.
    (f) GPA use violation. Produce, import, sell, offer for sale, 
dispense, supply, offer for supply, store or transport gasoline that 
does not comply with a GPA use prohibition under Sec. 80.219(c).
    (g) Failure to use sufficient sulfur credits or allotments to offset 
a per-gallon cap adjustment. For a small refiner that has an approved 
adjustment of its per-gallon cap sulfur standard for a refinery under 
Sec. 80.271, to fail to obtain (or generate) and use the required 
number of sulfur credits or allotments to offset the revised per-gallon 
cap sulfur standard under Sec. 80.217(d).

[65 FR 6823, Feb. 10, 2000, as amended at 67 FR 40184, June 12, 2002]



Sec. 80.390  What evidence may be used to determine compliance with
the prohibitions and requirements of this subpart and liability

for violations of this 
          subpart?

    (a) Compliance with the sulfur standards of this subpart shall be 
determined based on the sulfur level of the gasoline, measured using the 
methodologies specified in Sec. Sec. 80.330(b) and 80.46(a). Any 
evidence or information, including the exclusive use of such evidence or 
information, may be used to establish the sulfur level of gasoline if 
the evidence or information is relevant to whether the sulfur level of 
gasoline would have been in compliance with the standards if the 
appropriate sampling and testing methodology had been correctly 
performed. Such evidence may be obtained from any source or location and 
may include, but is not limited to, test results using methods other 
than those specified in Sec. Sec. 80.330(b) and 80.46(a), business 
records, and commercial documents.
    (b) Determinations of compliance with the requirements of this 
subpart other than the sulfur standards, and determinations of liability 
for any violation of this subpart, may be based on information obtained 
from any source or location. Such information may include, but is not 
limited to, business records and commercial documents.



Sec. 80.395  Who is liable for violations under the gasoline sulfur program?

    (a) Persons liable for violations of prohibited acts.--(1) Averaging 
violation. Any refiner or importer who violates Sec. 80.385(a) is 
liable for the violation.
    (2) Causing an averaging violation. Any refiner, importer, 
distributor, reseller, carrier, retailer, wholesale purchaser-consumer, 
or oxygenate blender who causes another party to violate Sec. 
80.385(a), is liable for a violation of Sec. 80.385(c).
    (3) Cap standard violation. Any refiner, importer, distributor, 
reseller, carrier, retailer, wholesale purchaser-consumer, or oxygenate 
blender who owned, leased, operated, controlled or supervised a facility 
where a violation of Sec. 80.385 (b) occurred, is deemed in violation 
of Sec. 80.385(b).

[[Page 886]]

    (4) Causing a cap standard violation. Any refiner, importer, 
distributor, reseller, carrier, retailer, wholesale purchaser-consumer, 
or oxygenate blender who produced, imported, sold, offered for sale, 
dispensed, supplied, offered for supply, stored, transported, or caused 
the transportation or storage of gasoline that violates Sec. 80.385(b), 
is deemed in violation of Sec. 80.385(c).
    (5) GPA use violation. Any refiner, importer, distributor, reseller, 
carrier, retailer, wholesale purchaser-consumer, or oxygenate blender 
who owned, leased, operated, controlled or supervised a facility where a 
violation of Sec. 80.385(f) occurred, is deemed in violation of Sec. 
80.385(f).
    (6) Causing a GPA use violation. Any refiner, importer, distributor, 
reseller, carrier, retailer, wholesale purchaser-consumer, or oxygenate 
blender who produced, imported, sold, offered for sale, dispensed, 
supplied, offered for supply, stored, transported, or caused the 
transportation or storage of gasoline that violates Sec. 80.385(f), is 
deemed in violation of Sec. 80.385(c).
    (7) Branded refiner/importer liability. Any refiner or importer 
whose corporate, trade, or brand name, or whose marketing subsidiary's 
corporate, trade, or brand name appeared at a facility where a violation 
of Sec. 80.385(b) or (f) occurred, is deemed in violation of Sec. 
80.385(b) or (f), as applicable.
    (8) Causing violating gasoline to be in the distribution system. Any 
refiner, importer, distributor, reseller, carrier, or oxygenate blender, 
who owned, leased, operated, controlled or supervised a facility from 
which gasoline was released into the distribution system which does not 
comply with an applicable sulfur cap standard, a sulfur averaging 
standard, or a GPA use prohibition, is deemed in violation of Sec. 
80.385(d).
    (9) Carrier causation. In order for a carrier to be liable under 
paragraph (a)(2), (4), (6), or (8) of this section, EPA must 
demonstrate, by reasonably specific showing by direct or circumstantial 
evidence, that the carrier caused the violation.
    (10) Denatured ethanol violation. Any oxygenate blender who violates 
Sec. 80.385(e) is liable for the violation.
    (11) Parent corporation liability. Any parent corporation is liable 
for any violations of this subpart that are committed by any of its 
wholly-owned subsidiaries.
    (12) Joint venture and joint owner liability. Each partner to a 
joint venture, or each owner of a facility owned by two or more owners, 
is jointly and severally liable for any violation of this subpart that 
occurs at the joint venture facility or facility owned by the joint 
owners, or is committed by the joint venture operation or any of the 
joint owners of the facility.
    (13) Failure to use credits violation. Any small refiner that has an 
approved adjustment of its per-gallon cap under Sec. 80.271 and that 
does not obtain (or generate) and use the required number of sulfur 
credits or allotments under Sec. 80.271(d) by the time it submits its 
annual report under Sec. 80.370 is deemed in violation of Sec. 
80.385(g).
    (b) Persons liable for failure to meet other provisions of this 
subpart. (1) Any refiner, importer, distributor, reseller, carrier, 
wholesale purchaser-consumer, retailer, or oxygenate blender who fails 
to meet a provision of this subpart not addressed in paragraph (a) of 
this section is liable for a violation of that provision.
    (2) Any refiner, importer, distributor, reseller, carrier, wholesale 
purchaser-consumer, retailer, or oxygenate blender who caused another 
person to fail to meet a requirement of this subpart not addressed in 
paragraph (a) of this section, is liable for causing a violation of that 
provision.

[65 FR 6823, Feb. 10, 2000, as amended at 67 FR 40184, June 12, 2002]



Sec. 80.400  What defenses apply to persons deemed liable for a 
violation of a prohibited act?

    (a) Any person deemed liable for a violation of a prohibition under 
Sec. 80.395 (a)(3) through (8), will not be deemed in violation if the 
person demonstrates that:
    (1) The violation was not caused by the person or the person's 
employee or agent; and
    (2) The person conducted a quality assurance sampling and testing 
program, as described in paragraph (d) of this section. A carrier may 
rely on the quality assurance program carried out by another party, 
including the party

[[Page 887]]

who owns the gasoline in question, provided that the quality assurance 
program is carried out properly. Retailers and wholesale purchaser-
consumers are not required to conduct quality assurance programs.
    (b) In the case of a violation found at a facility operating under 
the corporate, trade or brand name of a refiner or importer, or a 
refiner's or importer's marketing subsidiary, the refiner or importer 
must show, in addition to the defense elements required under paragraphs 
(a)(1) and (2) of this section, that the violation was caused by:
    (1) An act in violation of law (other than the Clean Air Act or this 
part 80), or an act of sabotage or vandalism;
    (2) The action of any refiner, importer, retailer, distributor, 
reseller, oxygenate blender, carrier, retailer or wholesale purchaser-
consumer in violation of a contractual agreement between the branded 
refiner or importer and the person designed to prevent such action, and 
despite periodic sampling and testing by the branded refiner or importer 
to ensure compliance with such contractual obligation; or
    (3) The action of any carrier or other distributor not subject to a 
contract with the refiner or importer, but engaged for transportation of 
gasoline, despite specifications or inspections of procedures and 
equipment which are reasonably calculated to prevent such action.
    (c) Under paragraph (a) of this section for any person to show that 
a violation was not caused by that person, or under paragraph (b) of 
this section to show that a violation was caused by any of the specified 
actions, the person must demonstrate by reasonably specific showing, by 
direct or circumstantial evidence, that the violation was caused or must 
have been caused by another person and that the person asserting the 
defense did not contribute to that other person's causation.
    (d) Quality assurance and testing program. To demonstrate an 
acceptable quality assurance and testing program under paragraph (a)(2) 
of this section, a person must present evidence of the following:
    (1) A periodic sampling and testing program to ensure the gasoline 
the person sold, dispensed, supplied, stored, or transported, meets the 
applicable sulfur standard; and
    (2) On each occasion when gasoline is found not in compliance with 
the applicable sulfur standard:
    (i) The person immediately ceases selling, offering for sale, 
dispensing, supplying, offering for supply, storing or transporting the 
non-complying product; and
    (ii) The person promptly remedies the violation and the factors that 
caused the violation (for example, by removing the non-complying product 
from the distribution system until the applicable standard is achieved 
and taking steps to prevent future violations of a similar nature from 
occurring).
    (3) For any carrier who transports gasoline in a tank truck, the 
quality assurance program required under this paragraph (d) need not 
include periodic sampling and testing of gasoline in the tank truck, but 
in lieu of such tank truck sampling and testing, the carrier shall 
demonstrate evidence of an oversight program for monitoring compliance 
with the requirements of this subpart relating to the transport or 
storage of gasoline by tank truck, such as appropriate guidance to 
drivers regarding compliance with the applicable sulfur standard and 
product transfer document requirements, and the periodic review of 
records received in the ordinary course of business concerning gasoline 
quality and delivery.



Sec. 80.405  What penalties apply under this subpart?

    (a) Any person liable for a violation under Sec. 80.395 is subject 
to civil penalties as specified in section 205 of the Clean Air Act for 
every day of each such violation and the amount of economic benefit or 
savings resulting from each violation.
    (b) Any person liable under Sec. 80.395(a)(1) or (2) for a 
violation of the applicable sulfur averaging standard or causing another 
party to violate that standard during any averaging period, is subject 
to a separate day of violation for each and every day in the averaging 
period. Any person liable under

[[Page 888]]

Sec. 80.395(b) for a failure to fulfill any requirement for credit or 
allotment generation, transfer, use, banking, or deficit correction, is 
subject to a separate day of violation for each and every day in the 
averaging period in which invalid credits or allotments are generated or 
used.
    (c)(1) Any person liable under Sec. 80.395(a)(3), (4), (5), or (6) 
for a violation of an applicable sulfur per gallon cap standard under 
Sec. 80.195, Sec. 80.210, Sec. 80.216, Sec. 80.220 or Sec. 80.240, 
a GPA use prohibition under Sec. 80.219(c), or of causing another party 
to violate a cap standard or a GPA use prohibition, is subject to a 
separate day of violation for each and every day the non-complying 
gasoline remains any place in the gasoline distribution system.
    (2) Any person liable under Sec. 80.395(a)(8) for causing gasoline 
to be in the distribution system which does not comply with an 
applicable sulfur cap standard, a sulfur averaging standard, or a GPA 
use prohibition, is subject to a separate day of violation for each and 
every day that the non-complying gasoline remains any place in the 
gasoline distribution system.
    (3) For purposes of paragraph (c) of this section, the length of 
time the gasoline in question remained in the gasoline distribution 
system is deemed to be twenty-five days, unless a person subject to 
liability or EPA demonstrates by reasonably specific showings, by direct 
or circumstantial evidence, that the non-complying gasoline remained in 
the gasoline distribution system for fewer than or more than twenty-five 
days.
    (d) Any person liable under Sec. 80.395(b) for failure to meet, or 
causing a failure to meet, a provision of this subpart is liable for a 
separate day of violation for each and every day such provision remains 
unfulfilled.
    (e) Any person liable under Sec. 80.395(a)(13) for failing to 
obtain (or generate) and use the total required number of sulfur credits 
or allotments under Sec. 80.271(d) for a calendar year is subject to a 
separate day of violation for each day until the required number of 
credits or allotments is used.

[65 FR 6823, Feb. 10, 2000, as amended at 67 FR 40185, June 12, 2002]

    Provisions for Foreign Refiners With Individual Sulfur Baselines



Sec. 80.410  What are the additional requirements for gasoline 
produced at foreign refineries having individual small refiner

sulfur baselines, foreign 
          refineries granted temporary relief under Sec. 80.270, or 
          baselines for generating credits during 2000 through 2003?

    (a) Definitions. (1) A foreign refinery is a refinery that is 
located outside the United States, the Commonwealth of Puerto Rico, the 
Virgin Islands, Guam, American Samoa, and the Commonwealth of the 
Northern Mariana Islands (collectively referred to in this section as 
``the United States'').
    (2) A foreign refiner is a person who meets the definition of 
refiner under Sec. 80.2(i) for a foreign refinery.
    (3) A small foreign refiner is a refiner that meets the definition 
of a small refiner under Sec. 80.225.
    (4) ``Sulfur-FRGAS'' means gasoline produced at a foreign refinery 
that has been assigned an individual refinery sulfur baseline under 
Sec. Sec. 80.250 or 80.295, or has been granted temporary relief under 
Sec. 80.270, and that is imported into the United States.
    (5) ``Non-Sulfur-FRGAS'' means gasoline that is produced at a 
foreign refinery that has not been assigned an individual refinery 
sulfur baseline, gasoline produced at a foreign refinery with an 
individual refinery sulfur baseline that is not imported into the United 
States, and gasoline produced at a foreign refinery with an individual 
sulfur baseline during a year when the foreign refiner has opted to not 
participate in the Sulfur-FRGAS program under paragraph (c)(3) of this 
section.
    (6) ``Certified Sulfur-FRGAS'' means Sulfur-FRGAS the foreign 
refiner intends to include in the foreign refinery's sulfur compliance 
calculations under Sec. 80.205 pursuant to Sec. 80.240 or Sec. 80.270 
or credit calculations under Sec. Sec. 80.305 or 80.310 and allotment 
calculations under Sec. 80.275(a), and does include in these compliance 
calculations when reported to EPA.
    (7) ``Non-Certified Sulfur-FRGAS'' means Sulfur-FRGAS that is not 
Certified Sulfur-FRGAS.
    (b) Baseline establishment. Any foreign refiner who does not have an 
approved

[[Page 889]]

refinery baseline under Sec. 80.94 may submit a petition to the 
Administrator for an individual refinery sulfur baseline pursuant to 
Sec. Sec. 80.245 and 80.250, a baseline for generating credits or 
allotments under Sec. Sec. 80.290 and 80.295, or a baseline for 
temporary refinery relief under Sec. Sec. 80.270 and 80.295.
    (1) The refiner shall follow the procedures specified in Sec. Sec. 
80.91 through 80.93 to establish the volume and sulfur content of 
gasoline that was produced at the foreign refinery and imported into the 
United States during 1997 and 1998 for purposes of establishing 
baselines under Sec. 80.250 or Sec. 80.295.
    (2) In making determinations for foreign refinery baselines EPA will 
consider all information supplied by a foreign refiner, and in addition 
may rely on any and all appropriate assumptions necessary to make such 
determinations.
    (3) Where a foreign refiner submits a petition that is incomplete or 
inadequate to establish an accurate baseline, and the refiner fails to 
cure this defect after a request for more information, EPA will not 
assign an individual refinery sulfur baseline.
    (c) General requirements for foreign refiners with individual 
refinery sulfur baselines. A foreign refiner of a refinery that has been 
assigned an individual sulfur baseline under Sec. 80.250 or Sec. 
80.295 must designate all gasoline produced at the foreign refinery that 
is exported to the United States as either Certified Sulfur-FRGAS or as 
Non-Certified Sulfur-FRGAS, except as provided in paragraph (c)(3) of 
this section.
    (1) In the case of Certified Sulfur-FRGAS, the foreign refiner must 
meet all provisions that apply to refiners under this subpart H.
    (2) In the case of Non-Certified Sulfur-FRGAS, the foreign refiner 
shall meet all the following provisions, except the foreign refiner 
shall substitute the name Non-Certified Sulfur-FRGAS for the names 
``reformulated gasoline'' or ``RBOB'' wherever they appear in the 
following provisions:
    (i) The designation requirements in this section;
    (ii) The recordkeeping requirements under Sec. 80.365;
    (iii) The reporting requirements in Sec. 80.370 and this section;
    (iv) The product transfer document requirements in this section;
    (v) The prohibitions in this section and Sec. 80.385; and
    (vi) The independent audit requirements under Sec. 80.415, 
paragraph (h) of this section, Sec. Sec. 80.125 through 80.127, Sec. 
80.128(a),(b),(c),(g) through (i), and Sec. 80.130.
    (3)(i) Any foreign refiner that generates sulfur credits under Sec. 
80.305 during the period 2000 through 2003, or allotments under Sec. 
80.275(a) during 2003, and any small refiner generating credits under 
Sec. 80.310, shall designate all Sulfur-FRGAS as Certified Sulfur-FRGAS 
for any year that such credits are generated.
    (ii) Any foreign refiner that has been assigned an individual sulfur 
baseline for a foreign refinery under Sec. 80.250 or Sec. 80.295 may 
elect to classify no gasoline imported into the United States as Sulfur-
FRGAS, provided the foreign refiner notifies EPA of the election no 
later than November 1 of the prior calendar year.
    (iii) An election under paragraph (c)(3)(ii) of this section shall:
    (A) Apply to an entire calendar year averaging period, and apply to 
all gasoline produced during the calendar year at the foreign refinery 
that is used in the United States; and
    (B) Remain in effect for each succeeding calendar year averaging 
period, unless and until the foreign refiner notifies EPA of a 
termination of the election. The change in election shall take effect at 
the beginning of the next calendar year.
    (d) Designation, product transfer documents, and foreign refiner 
certification. (1) Any foreign refiner of a foreign refinery that has 
been assigned an individual sulfur baseline must designate each batch of 
Sulfur-FRGAS as such at the time the gasoline is produced, unless the 
refinery has elected to classify no gasoline exported to the United 
States as Sulfur-FRGAS under paragraph (c)(3)(ii) of this section.
    (2) On each occasion when any person transfers custody or title to 
any Sulfur-FRGAS prior to its being imported into the United States, it 
must include the following information as part of the product transfer 
document information in this section:

[[Page 890]]

    (i) Identification of the gasoline as Certified Sulfur-FRGAS or as 
Non-Certified Sulfur-FRGAS; and
    (ii) The name and EPA refinery registration number of the refinery 
where the Sulfur-FRGAS was produced.
    (3) On each occasion when Sulfur-FRGAS is loaded onto a vessel or 
other transportation mode for transport to the United States, the 
foreign refiner shall prepare a certification for each batch of the 
Sulfur-FRGAS that meets the following requirements:
    (i) The certification shall include the report of the independent 
third party under paragraph (f) of this section, and the following 
additional information:
    (A) The name and EPA registration number of the refinery that 
produced the Sulfur-FRGAS;
    (B) The identification of the gasoline as Certified Sulfur-FRGAS or 
Non-Certified Sulfur-FRGAS;
    (C) The volume of Sulfur-FRGAS being transported, in gallons;
    (D) In the case of Certified Sulfur-FRGAS:
    (1) The sulfur content as determined under paragraph (f) of this 
section; and
    (2) A declaration that the Sulfur-FRGAS is being included in the 
compliance calculations under Sec. 80.205 or credit calculations under 
Sec. 80.305 or allotments under Sec. 80.275(a) for the refinery that 
produced the Sulfur-FRGAS.
    (ii) The certification shall be made part of the product transfer 
documents for the Sulfur-FRGAS. Prior to 2004, the information required 
under paragraph (d)(3)(i)(D)(1) of this section may be omitted from the 
product transfer documents that accompany the gasoline, provided that 
such information is provided to the United States importer prior to 
collection of the representative sample required under paragraph 
(o)(3)(ii)(A) of this section.
    (e) Transfers of Sulfur-FRGAS to non-United States markets. The 
foreign refiner is responsible to ensure that all gasoline classified as 
Sulfur-FRGAS is imported into the United States. A foreign refiner may 
remove the Sulfur-FRGAS classification, and the gasoline need not be 
imported into the United States, but only if:
    (1)(i) The foreign refiner excludes:
    (A) The volume of gasoline from the refinery's compliance 
calculations under Sec. 80.205; and
    (B) In the case of Certified Sulfur-FRGAS, the volume and sulfur 
content of the gasoline from the compliance calculations under Sec. 
80.205 or credit calculations under Sec. 80.305.
    (ii) The exclusions under paragraph (e)(1)(i) of this section shall 
be on the basis of the sulfur content and volumes determined under 
paragraph (f) of this section; and
    (2) The foreign refiner obtains sufficient evidence in the form of 
documentation that the gasoline was not imported into the United States.
    (f) Load port independent sampling, testing and refinery 
identification. (1) On each occasion Sulfur-FRGAS is loaded onto a 
vessel for transport to the United States a foreign refiner shall have 
an independent third party:
    (i) Inspect the vessel prior to loading and determine the volume of 
any tank bottoms;
    (ii) Determine the volume of Sulfur-FRGAS loaded onto the vessel 
(exclusive of any tank bottoms present before vessel loading);
    (iii) Obtain the EPA-assigned registration number of the foreign 
refinery;
    (iv) Determine the name and country of registration of the vessel 
used to transport the Sulfur-FRGAS to the United States; and
    (v) Determine the date and time the vessel departs the port serving 
the foreign refinery.
    (2) On each occasion Certified Sulfur-FRGAS is loaded onto a vessel 
for transport to the United States a foreign refiner shall have an 
independent third party:
    (i) Collect a representative sample of the Certified Sulfur-FRGAS 
from each vessel compartment subsequent to loading on the vessel and 
prior to departure of the vessel from the port serving the foreign 
refinery;
    (ii) Prepare a volume-weighted vessel composite sample from the 
compartment samples, and determine the value for sulfur in accordance 
with the methodology and requirements specified in Sec. 80.330, by:
    (A) The third party analyzing the sample; or

[[Page 891]]

    (B) The third party observing the foreign refiner analyze the 
sample;
    (iii) Review original documents that reflect movement and storage of 
the certified Sulfur-FRGAS from the refinery to the load port, and from 
this review determine:
    (A) The refinery at which the Sulfur-FRGAS was produced; and
    (B) That the Sulfur-FRGAS remained segregated from:
    (1) Non-Sulfur-FRGAS and Non-Certified Sulfur-FRGAS; and
    (2) Other Certified Sulfur-FRGAS produced at a different refinery.
    (3) The independent third party shall submit a report:
    (i) To the foreign refiner containing the information required under 
paragraphs (f)(1) and (2) of this section, to accompany the product 
transfer documents for the vessel; and
    (ii) To the Administrator containing the information required under 
paragraphs (f)(1) and (2) of this section, within thirty days following 
the date of the independent third party's inspection. This report shall 
include a description of the method used to determine the identity of 
the refinery at which the gasoline was produced, assurance that the 
gasoline remained segregated as specified in paragraph (n)(1) of this 
section, and a description of the gasoline's movement and storage 
between production at the source refinery and vessel loading.
    (4) The independent third party must:
    (i) Be approved in advance by EPA, based on a demonstration of 
ability to perform the procedures required in this paragraph (f);
    (ii) Be independent under the criteria specified in Sec. 
80.65(f)(2)(iii); and
    (iii) Sign a commitment that contains the provisions specified in 
paragraph (i) of this section with regard to activities, facilities and 
documents relevant to compliance with the requirements of this paragraph 
(f).
    (g) Comparison of load port and port of entry testing. (1)(i) Except 
as described in paragraph (g)(1)(ii) of this section, any foreign 
refiner and any United States importer of Certified Sulfur-FRGAS shall 
compare the results from the load port testing under paragraph (f) of 
this section, with the port of entry testing as reported under paragraph 
(o) of this section, for the volume of gasoline and the sulfur value.
    (ii) Where a vessel transporting Certified Sulfur-FRGAS off loads 
this gasoline at more than one United States port of entry, and the 
conditions of paragraph (g)(2)(i) of this section are met at the first 
United States port of entry, the requirements of paragraph (g)(2) of 
this section do not apply at subsequent ports of entry if the United 
States importer obtains a certification from the vessel owner, that 
meets the requirements of paragraph (s) of this section, that the vessel 
has not loaded any gasoline or blendstock between the first United 
States port of entry and the subsequent port of entry.
    (2)(i) The requirements of this paragraph (g)(2) apply if:
    (A) The temperature-corrected volumes determined at the port of 
entry and at the load port differ by more than one percent; or
    (B) The sulfur value determined at the port of entry is higher than 
the sulfur value determined at the load port, and the amount of this 
difference is greater than the reproducibility amount specified for the 
port of entry test result by the American Society of Testing and 
Materials (ASTM).
    (ii) The United States importer and the foreign refiner shall treat 
the gasoline as Non-Certified Sulfur-FRGAS, and the foreign refiner 
shall exclude the gasoline volume and properties from its gasoline 
sulfur compliance calculations under Sec. 80.205.
    (h) Attest requirements. The following additional procedures shall 
be carried out by any foreign refiner of Sulfur-FRGAS as part of the 
applicable attest engagement for each foreign refinery under Sec. 
80.415:
    (1) The inventory reconciliation analysis under Sec. 80.128(b) and 
the tender analysis under Sec. 80.128(c) shall include Non-Sulfur-FRGAS 
in addition to the gasoline types listed in Sec. 80.128(b) and (c).
    (2) Obtain separate listings of all tenders of Certified Sulfur-
FRGAS, and of Non-Certified Sulfur-FRGAS. Agree the total volume of 
tenders from the listings to the gasoline inventory reconciliation 
analysis in Sec. 80.128(b), and to the volumes determined by the third

[[Page 892]]

party under paragraph (f)(1) of this section.
    (3) For each tender under paragraph (h)(2) of this section where the 
gasoline is loaded onto a marine vessel, report as a finding the name 
and country of registration of each vessel, and the volumes of Sulfur-
FRGAS loaded onto each vessel.
    (4) Select a sample from the list of vessels identified in paragraph 
(h)(3) of this section used to transport Certified Sulfur-FRGAS, in 
accordance with the guidelines in Sec. 80.127, and for each vessel 
selected perform the following:
    (i) Obtain the report of the independent third party, under 
paragraph (f) of this section, and of the United States importer under 
paragraph (o) of this section.
    (A) Agree the information in these reports with regard to vessel 
identification, gasoline volumes and test results.
    (B) Identify, and report as a finding, each occasion the load port 
and port of entry parameter and volume results differ by more than the 
amounts allowed in paragraph (g) of this section, and determine whether 
the foreign refiner adjusted its refinery calculations as required in 
paragraph (g) of this section.
    (ii) Obtain the documents used by the independent third party to 
determine transportation and storage of the Certified Sulfur-FRGAS from 
the refinery to the load port, under paragraph (f) of this section. 
Obtain tank activity records for any storage tank where the Certified 
Sulfur-FRGAS is stored, and pipeline activity records for any pipeline 
used to transport the Certified Sulfur-FRGAS, prior to being loaded onto 
the vessel. Use these records to determine whether the Certified Sulfur-
FRGAS was produced at the refinery that is the subject of the attest 
engagement, and whether the Certified Sulfur-FRGAS was mixed with any 
Non-Certified Sulfur-FRGAS, Non-Sulfur-FRGAS, or any Certified Sulfur-
FRGAS produced at a different refinery.
    (5)(i) Select a sample from the list of vessels identified in 
paragraph (h)(3) of this section used to transport certified and Non-
Certified Sulfur-FRGAS, in accordance with the guidelines in Sec. 
80.127, and for each vessel selected perform the following:
    (ii) Obtain a commercial document of general circulation that lists 
vessel arrivals and departures, and that includes the port and date of 
departure of the vessel, and the port of entry and date of arrival of 
the vessel. Agree the vessel's departure and arrival locations and dates 
from the independent third party and United States importer reports to 
the information contained in the commercial document.
    (6) Obtain separate listings of all tenders of Non-Sulfur-FRGAS, and 
perform the following:
    (i) Agree the total volume of tenders from the listings to the 
gasoline inventory reconciliation analysis in Sec. 80.128(b).
    (ii) Obtain a separate listing of the tenders under paragraph (h)(6) 
of this section where the gasoline is loaded onto a marine vessel. 
Select a sample from this listing in accordance with the guidelines in 
Sec. 80.127, and obtain a commercial document of general circulation 
that lists vessel arrivals and departures, and that includes the port 
and date of departure and the ports and dates where the gasoline was off 
loaded for the selected vessels. Determine and report as a finding the 
country where the gasoline was off loaded for each vessel selected.
    (7) In order to complete the requirements of this paragraph (h) an 
auditor shall:
    (i) Be independent of the foreign refiner;
    (ii) Be licensed as a Certified Public Accountant in the United 
States and a citizen of the United States, or be approved in advance by 
EPA based on a demonstration of ability to perform the procedures 
required in Sec. Sec. 80.125 through 80.130, Sec. 80.415 and this 
paragraph (h); and
    (iii) Sign a commitment that contains the provisions specified in 
paragraph (i) of this section with regard to activities and documents 
relevant to compliance with the requirements of Sec. Sec. 80.125 
through 80.130, Sec. 80.415 and this paragraph (h).
    (i) Foreign refiner commitments. Any foreign refiner shall commit to 
and comply with the provisions contained in this paragraph (i) as a 
condition to

[[Page 893]]

being assigned an individual refinery sulfur baseline.
    (1) Any United States Environmental Protection Agency inspector or 
auditor will be given full, complete and immediate access to conduct 
inspections and audits of the foreign refinery.
    (i) Inspections and audits may be either announced in advance by 
EPA, or unannounced.
    (ii) Access will be provided to any location where:
    (A) Gasoline is produced;
    (B) Documents related to refinery operations are kept;
    (C) Gasoline or blendstock samples are tested or stored; and
    (D) Sulfur-FRGAS is stored or transported between the foreign 
refinery and the United States, including storage tanks, vessels and 
pipelines.
    (iii) Inspections and audits may be by EPA employees or contractors 
to EPA.
    (iv) Any documents requested that are related to matters covered by 
inspections and audits will be provided to an EPA inspector or auditor 
on request.
    (v) Inspections and audits by EPA may include review and copying of 
any documents related to:
    (A) Refinery baseline establishment, including the volume and sulfur 
content, and transfers of title or custody, of any gasoline or 
blendstocks, whether Sulfur-FRGAS or Non-Sulfur-FRGAS, produced at the 
foreign refinery during the period January 1, 1997 through the date of 
the refinery baseline petition or through the date of the inspection or 
audit if a baseline petition has not been approved, and any work papers 
related to refinery baseline establishment;
    (B) The volume and sulfur content of Sulfur-FRGAS;
    (C) The proper classification of gasoline as being Sulfur-FRGAS or 
as not being Sulfur-FRGAS, or as Certified Sulfur-FRGAS or as Non-
Certified Sulfur-FRGAS;
    (D) Transfers of title or custody to Sulfur-FRGAS;
    (E) Sampling and testing of Sulfur-FRGAS;
    (F) Work performed and reports prepared by independent third parties 
and by independent auditors under the requirements of this section and 
Sec. 80.415 including work papers; and
    (G) Reports prepared for submission to EPA, and any work papers 
related to such reports.
    (vi) Inspections and audits by EPA may include taking samples of 
gasoline or blendstock, and interviewing employees.
    (vii) Any employee of the foreign refiner will be made available for 
interview by the EPA inspector or auditor, on request, within a 
reasonable time period.
    (viii) English language translations of any documents will be 
provided to an EPA inspector or auditor, on request, within 10 working 
days.
    (ix) English language interpreters will be provided to accompany EPA 
inspectors and auditors, on request.
    (2) An agent for service of process located in the District of 
Columbia will be named, and service on this agent constitutes service on 
the foreign refiner or any employee of the foreign refiner for any 
action by EPA or otherwise by the United States related to the 
requirements of this subpart H.
    (3) The forum for any civil or criminal enforcement action related 
to the provisions of this section for violations of the Clean Air Act or 
regulations promulgated thereunder shall be governed by the Clean Air 
Act, including the EPA administrative forum where allowed under the 
Clean Air Act.
    (4) United States substantive and procedural laws shall apply to any 
civil or criminal enforcement action against the foreign refiner or any 
employee of the foreign refiner related to the provisions of this 
section.
    (5) Submitting a petition for an individual refinery sulfur 
baseline, producing and exporting gasoline under an individual refinery 
sulfur baseline, and all other actions to comply with the requirements 
of this subpart H relating to the establishment and use of an individual 
refinery sulfur baseline constitute actions or activities that satisfy 
the provisions of 28 U.S.C. section 1605(a)(2), but solely with respect 
to actions instituted against the foreign refiner, its agents and 
employees in any court or other tribunal in the United States for 
conduct that violates the requirements applicable to the foreign

[[Page 894]]

refiner under this subpart H, including conduct that violates Title 18 
U.S.C. section 1001 and Clean Air Act section 113(c)(2).
    (6) The foreign refiner, or its agents or employees, will not seek 
to detain or to impose civil or criminal remedies against EPA inspectors 
or auditors, whether EPA employees or EPA contractors, for actions 
performed within the scope of EPA employment related to the provisions 
of this section.
    (7) The commitment required by this paragraph (i) shall be signed by 
the owner or president of the foreign refiner business.
    (8) In any case where Sulfur-FRGAS produced at a foreign refinery is 
stored or transported by another company between the refinery and the 
vessel that transports the Sulfur-FRGAS to the United States, the 
foreign refiner shall obtain from each such other company a commitment 
that meets the requirements specified in paragraphs (i)(1) through (7) 
of this section, and these commitments shall be included in the foreign 
refiner's baseline petition.
    (j) Sovereign immunity. By submitting a petition for an individual 
foreign refinery baseline under this section, or by producing and 
exporting gasoline to the United States under an individual refinery 
sulfur baseline under this section, the foreign refiner, its agents and 
employees, without exception, become subject to the full operation of 
the administrative and judicial enforcement powers and provisions of the 
United States without limitation based on sovereign immunity, with 
respect to actions instituted against the foreign refiner, its agents 
and employees in any court or other tribunal in the United States for 
conduct that violates the requirements applicable to the foreign refiner 
under this subpart H, including conduct that violates Title 18 U.S.C. 
section 1001 and Clean Air Act section 113(c)(2).
    (k) Bond posting. Any foreign refiner shall meet the requirements of 
this paragraph (k) as a condition to being assigned an individual 
refinery sulfur baseline.
    (l) The foreign refiner shall post a bond of the amount calculated 
using the following equation:


Bond=Gx$ 0.01

where:

Bond=amount of the bond in U. S. dollars.
G=the largest volume of gasoline produced at the foreign refinery and 
exported to the United States, in gallons, during a single calendar year 
among the most recent of the following calendar years, up to a maximum 
of five calendar years: the calendar year immediately preceding the date 
the baseline petition is submitted, the calendar year the baseline 
petition is submitted, and each succeeding calendar year.

    (2) Bonds shall be posted by:
    (i) Paying the amount of the bond to the Treasurer of the United 
States;
    (ii) Obtaining a bond in the proper amount from a third party surety 
agent that is payable to satisfy United States administrative or 
judicial judgments against the foreign refiner, provided EPA agrees in 
advance as to the third party and the nature of the surety agreement; or
    (iii) An alternative commitment that results in assets of an 
appropriate liquidity and value being readily available to the United 
States, provided EPA agrees in advance as to the alternative commitment.
    (3) If the bond amount for a foreign refinery increases, the foreign 
refiner shall increase the bond to cover the shortfall within 90 days of 
the date the bond amount changes. If the bond amount decreases, the 
foreign refiner may reduce the amount of the bond beginning 90 days 
after the date the bond amount changes.
    (4) Bonds posted under this paragraph (k) shall:
    (i) Be used to satisfy any judicial judgment that results from an 
administrative or judicial enforcement action for conduct in violation 
of this subpart H, including where such conduct violates Title 18 U.S.C. 
section 1001 and Clean Air Act section 113(c)(2);
    (ii) Be provided by a corporate surety that is listed in the United 
States Department of Treasury Circular 570 ``Companies Holding 
Certificates of Authority as Acceptable Sureties on Federal Bonds and 
Acceptable Reinsuring Companies'' (Available from the U.S. Department of 
the Treasury, Financial Management Service, Surety Bond Branch, 3700 
East-West Highway, Room 6A04, Hyattsville, Md. 20782. Also available on 
the internet at http://www.fms.treas.gov/c570/c570.html); and

[[Page 895]]

    (iii) Include a commitment that the bond will remain in effect for 
at least five (5) years following the end of latest averaging period 
that the foreign refiner produces gasoline pursuant to the requirements 
of this Subpart H.
    (5) On any occasion a foreign refiner bond is used to satisfy any 
judgment, the foreign refiner shall increase the bond to cover the 
amount used within 90 days of the date the bond is used.
    (l) [Reserved]
    (m) English language reports. Any report or other document submitted 
to EPA by any foreign refiner shall be in English language, or shall 
include an English language translation.
    (n) Prohibitions. (1) No person may combine Certified Sulfur-FRGAS 
with any Non-Certified Sulfur-FRGAS or Non-Sulfur-FRGAS, and no person 
may combine Certified Sulfur-FRGAS with any Certified Sulfur-FRGAS 
produced at a different refinery, until the importer has met all the 
requirements of paragraph (o) of this section, except as provided in 
paragraph (e) of this section.
    (2) No foreign refiner or other person may cause another person to 
commit an action prohibited in paragraph (n)(1) of this section, or that 
otherwise violates the requirements of this section.
    (o) United States importer requirements. Any United States importer 
shall meet the following requirements:
    (1) Each batch of imported gasoline shall be classified by the 
importer as being Sulfur-FRGAS or as Non-Sulfur-FRGAS, and each batch 
classified as Sulfur-FRGAS shall be further classified as Certified 
Sulfur-FRGAS or as Non-certified Sulfur-FRGAS.
    (2) Gasoline shall be classified as Certified Sulfur-FRGAS or as 
Non-Certified Sulfur-FRGAS according to the designation by the foreign 
refiner if this designation is supported by product transfer documents 
prepared by the foreign refiner as required in paragraph (d) of this 
section, unless the gasoline is classified as Non-Certified Sulfur-FRGAS 
under paragraph (g) of this section.
    (3) For each gasoline batch classified as Sulfur-FRGAS, any United 
States importer shall perform the following procedures:
    (i) In the case of both Certified and Non-Certified Sulfur-FRGAS, 
have an independent third party:
    (A) Determine the volume of gasoline in the vessel;
    (B) Use the foreign refiner's Sulfur-FRGAS certification to 
determine the name and EPA-assigned registration number of the foreign 
refinery that produced the Sulfur-FRGAS;
    (C) Determine the name and country of registration of the vessel 
used to transport the Sulfur-FRGAS to the United States; and
    (D) Determine the date and time the vessel arrives at the United 
States port of entry.
    (ii) In the case of Certified Sulfur-FRGAS, have an independent 
third party:
    (A) Collect a representative sample from each vessel compartment 
subsequent to the vessel's arrival at the United States port of entry 
and prior to off loading any gasoline from the vessel;
    (B) Prepare a volume-weighted vessel composite sample from the 
compartment samples; and
    (C) Determine the sulfur value using the methodologies specified in 
Sec. 80.330, by:
    (1) The third party analyzing the sample; or
    (2) The third party observing the importer analyze the sample.
    (4) Any importer shall submit reports within thirty days following 
the date any vessel transporting Sulfur-FRGAS arrives at the United 
States port of entry:
    (i) To the Administrator containing the information determined under 
paragraph (o)(3) of this section; and
    (ii) To the foreign refiner containing the information determined 
under paragraph (o)(3)(ii) of this section.
    (5)(i) Any United States importer shall meet the requirements 
specified in Sec. 80.195 for any imported gasoline that is not 
classified as Certified Sulfur-FRGAS under paragraph (o)(2) of this 
section.
    (p) Truck imports of Certified Sulfur-FRGAS produced at a small 
refinery. (1) Any refiner whose Certified Sulfur-FRGAS is transported 
into the United States by truck may petition EPA to

[[Page 896]]

use alternative procedures to meet the following requirements:
    (i) Certification under paragraph (d)(5) of this section;
    (ii) Load port and port of entry sampling and testing under 
paragraphs (f) and (g) of this section;
    (iii) Attest under paragraph (h) of this section; and
    (iv) Importer testing under paragraph (o)(3) of this section.
    (2) These alternative procedures must ensure Certified Sulfur-FRGAS 
remains segregated from Non-Certified Sulfur-FRGAS and from Non-Sulfur-
FRGAS until it is imported into the United States. The petition will be 
evaluated based on whether it adequately addresses the following:
    (i) Provisions for monitoring pipeline shipments, if applicable, 
from the refinery, that ensure segregation of Certified Sulfur-FRGAS 
from that refinery from all other gasoline;
    (ii) Contracts with any terminals and/or pipelines that receive and/
or transport Certified Sulfur-FRGAS, that prohibit the commingling of 
Certified Sulfur-FRGAS with any of the following:
    (A) Other Certified Sulfur-FRGAS from other refineries;
    (B) All Non-Certified Sulfur-FRGAS; or
    (C) All Non-Sulfur-FRGAS;
    (iii) Procedures for obtaining and reviewing truck loading records 
and United States import documents for Certified Sulfur-FRGAS to ensure 
that such gasoline is only loaded into trucks making deliveries to the 
United States; and
    (iv) Attest procedures to be conducted annually by an independent 
third party that review loading records and import documents based on 
volume reconciliation, or other criteria, to confirm that all Certified 
Sulfur-FRGAS remains segregated throughout the distribution system and 
is only loaded into trucks for import into the United States.
    (3) The petition required by this section must be submitted to EPA 
along with the application for small refiner status and individual 
refinery sulfur baseline and standards under Sec. 80.240 and this 
section.
    (q) Withdrawal or suspension of a foreign refinery's baseline. EPA 
may withdraw or suspend a baseline that has been assigned to a foreign 
refinery where:
    (1) A foreign refiner fails to meet any requirement of this section;
    (2) A foreign government fails to allow EPA inspections as provided 
in paragraph (i)(1) of this section;
    (3) A foreign refiner asserts a claim of, or a right to claim, 
sovereign immunity in an action to enforce the requirements in this 
subpart H; or
    (4) A foreign refiner fails to pay a civil or criminal penalty that 
is not satisfied using the foreign refiner bond specified in paragraph 
(k) of this section.
    (r) Early use of a foreign refinery baseline. (1) A foreign refiner 
may begin using an individual refinery baseline before EPA has approved 
the baseline, provided that:
    (i) A baseline petition has been submitted as required in paragraph 
(b) of this section;
    (ii) EPA has made a provisional finding that the baseline petition 
is complete;
    (iii) The foreign refiner has made the commitments required in 
paragraph (i) of this section;
    (iv) The persons who will meet the independent third party and 
independent attest requirements for the foreign refinery have made the 
commitments required in paragraphs (f)(4)(iii) and (h)(7)(iii) of this 
section; and
    (2) In any case where a foreign refiner uses an individual refinery 
baseline before final approval under paragraph (r)(1) of this section, 
and the foreign refinery baseline values that ultimately are approved by 
EPA are more stringent than the early baseline values used by the 
foreign refiner, the foreign refiner shall recalculate its compliance, 
ab initio, using the baseline values approved by EPA, and the foreign 
refiner shall be liable for any resulting violation of the conventional 
gasoline requirements.
    (s) Additional requirements for petitions, reports and certificates. 
Any petition for a refinery baseline under

[[Page 897]]

Sec. 80.250 or Sec. 80.295, any alternative procedures under paragraph 
(p) of this section, and any certification under paragraph (d)(3) of 
this section shall be:
    (1) Submitted in accordance with procedures specified by the 
Administrator, including use of any forms that may be specified by the 
Administrator; and
    (2) Be signed by the president or owner of the foreign refiner 
company, or by that person's immediate designee, and shall contain the 
following declaration:

    I hereby certify: (1) that I have actual authority to sign on behalf 
of and to bind [insert name of foreign refiner] with regard to all 
statements contained herein; (2) that I am aware that the information 
contained herein is being certified, or submitted to the United States 
Environmental Protection Agency, under the requirements of 40 CFR. Part 
80, subpart H, and that the information is material for determining 
compliance under these regulations; and (3) that I have read and 
understand the information being certified or submitted, and this 
information is true, complete and correct to the best of my knowledge 
and belief after I have taken reasonable and appropriate steps to verify 
the accuracy thereof.
    I affirm that I have read and understand the provisions of 40 CFR 
Part 80, subpart H, including 40 CFR 80.410 [insert name of foreign 
refiner]. Pursuant to Clean Air Act section 113(c) and Title 18, United 
States Code, section 1001, the penalty for furnishing false, incomplete 
or misleading information in this certification or submission is a fine 
of up to $10,000, and/or imprisonment for up to five years.

[65 FR 6823, Feb. 10, 2000, as amended at 66 FR 19309, Apr. 13, 2001; 67 
FR 40185, June 12, 2002; 70 FR 74578, Dec. 15, 2005]

                           Attest Engagements



Sec. 80.415  What are the attest engagement requirements for gasoline
sulfur compliance applicable to refiners and importers?

    In addition to the requirements for attest engagements that apply to 
refiners and importers under Sec. Sec. 80.125 through 80.130, and Sec. 
80.410, the attest engagements for importers and refiners must include 
the following procedures and requirements each year.
    (a) Baseline. (1) Obtain the EPA sulfur baseline approval letter for 
the refinery to determine the refinery's applicable sulfur baseline and 
baseline volume under Sec. Sec. 80.250 or 80.295.
    (2) If the year being reviewed is 2004 through 2006 (2007 for 
refineries with small refiner status) and the refinery or importer 
produced or imported any GPA gasoline under Sec. 80.216 or the refiner 
has approved status for a small refinery:
    (i) Obtain the refinery's annual sulfur reports for 2000 through 
2003; and
    (ii) Determine whether the annual average sulfur level for any year 
credits were generated for 2000 through 2003 was less than the baseline 
level under paragraph (a)(1) of this section.
    (iii) If the annual average sulfur level for any year in which 
credits were generated for 2000 through 2003 was less than the baseline 
level under paragraph (a)(1) of this section, for small refiners report 
as a finding the lowest annual sulfur level as the new baseline value 
for purposes of establishing the small refiner standards under Sec. 
80.240, and for GPA gasoline report as a finding the lowest annual 
sulfur level plus 30.00 ppm as the new sulfur level for purposes of 
credit generation under Sec. 80.310, if lower than 150.00 ppm.
    (iv) If the refinery being reviewed is a small refinery and the 
annual volume under paragraph (b)(2) of this section is greater than the 
baseline volume, calculate the applicable standard in accordance with 
Sec. 80.240(c).
    (3) Obtain a written representation from the company representative 
stating the sulfur value that the company used as its baseline and agree 
that number to paragraphs (a)(1) and (a)(2) of this section and to the 
reports to EPA.
    (b) EPA reports. (1) Obtain and read a copy of the refinery's or 
importer's annual sulfur reports filed with EPA for the year.
    (2) Agree the yearly volume of gasoline reported to EPA in the 
sulfur reports with the inventory reconciliation analysis under Sec. 
80.128.
    (3) For the years 2004 through 2006, calculate the annual volume and 
average sulfur level for gasoline classified as GPA gasoline under 
Sec. Sec. 80.216 and 80.219, and calculate the annual volume and 
average sulfur level for gasoline not classified as GPA gasoline, and 
agree these values with the values reported to EPA.

[[Page 898]]

    (4) Except as provided in paragraph (b)(3) of this section, 
calculate the annual average sulfur level for all gasoline and agree 
that value with the value reported to EPA.
    (5) Obtain and read a copy of the refinery's or importer's sulfur 
credit report.
    (6) Agree the information in the refinery's or importer's batch 
reports filed with EPA under Sec. Sec. 80.75 and 80.105, and any 
laboratory test results, with the information contained in the annual 
sulfur report required under Sec. 80.370.
    (c) Credit generation before 2004. In the case of a refinery that 
only generates credits during 2000 through 2003:
    (1) Obtain a written representation from the company representative 
stating the refinery produces gasoline from crude oil.
    (2) Compute and report as a finding the sulfur baseline from 
paragraph (a) of this section multiplied by 0.9.
    (3) Obtain the annual average sulfur level from paragraph (b)(4) of 
this section.
    (4) If the sulfur value under paragraph (c)(3) of this section is 
less than the sulfur value under paragraph (c)(2) of this section, 
compute and report as a finding the difference between the annual 
average sulfur level and the refinery's sulfur baseline from paragraph 
(a) of this section.
    (5) Compute and report as a finding the total number of sulfur 
credits generated by multiplying the value in paragraph (c)(4) of this 
section by the volume of gasoline in paragraph (b)(2) of this section, 
and agree this value with the value reported to EPA.
    (d) Credit generation in 2004 and thereafter. The following 
procedures shall be completed for a refinery or importer that generates 
credits in 2004 and thereafter:
    (1) Obtain the annual average sulfur level for gasoline not 
classified as GPA from paragraph (b)(3) of this section.
    (2) If the sulfur value under paragraph (d)(1) of this section is 
less than 30 ppm, compute and report as a finding the difference between 
the sulfur level under paragraph (d)(1) of this section and 30 ppm.
    (3) Compute and report as a finding the total number of sulfur 
credits generated by multiplying the value calculated in paragraph 
(d)(2) of this section by the volume of gasoline not classified as GPA 
in paragraph (b)(3) of this section, and agree this number with the 
number reported to EPA.
    (4) Obtain the annual average sulfur level for gasoline classified 
as GPA from paragraph (b)(3) of this section.
    (5) If the sulfur value under paragraph (d)(4) of this section is 
less than the applicable level under Sec. 80.310, compute and report as 
a finding the difference between the sulfur level under paragraph (d)(4) 
of this section and the appropriate level in Sec. 80.310 .
    (6) Compute and report as a finding the total number of sulfur 
credits generated by multiplying the value calculated in paragraph 
(d)(5) of this section by the volume of gasoline classified as GPA in 
paragraph (b)(3) of this section, and agree this number with the number 
reported to EPA.
    (7) If the refiner has an approved status as a small refinery, 
obtain the annual average sulfur level for gasoline from paragraph 
(b)(4) of this section.
    (8) If the sulfur value under paragraph (d)(7) of this section is 
less than the applicable standard under Sec. 80.240, compute and report 
as a finding the difference between the sulfur level under paragraph 
(d)(7) of this section and the appropriate standard under Sec. 80.240.
    (9) Compute and report as a finding the total number of sulfur 
credits generated by multiplying the value calculated in paragraph 
(d)(8) of this section by the volume of gasoline in paragraph (b)(4) of 
this section, and agree this number with the number reported to EPA.
    (e) Credit purchases and sales. The following attest procedures 
shall be completed for a refinery or importer that is a transferor or 
transferee of credits during an averaging period:
    (1) Obtain contracts or other documents for all credits transferred 
to another refinery or importer during the year being reviewed; compute 
and report as a finding the number and year of creation of credits 
represented in these documents as being transferred away; and agree with 
the report to EPA.

[[Page 899]]

    (2) Obtain contracts or other documents for all credits received 
during the year being reviewed; compute and report as a finding the 
number and year of creation of credits represented in these documents as 
being received; and agree with the report to EPA.
    (f) Credits required for non-GPA gasoline. The following attest 
procedures shall be completed for refineries and importers in 2005 and 
thereafter (2004 and thereafter for refineries having standards under 
Sec. 80.240):
    (1) Obtain the annual average sulfur level for gasoline not 
classified as GPA from paragraph (b)(3) of this section.
    (2) If the value in paragraph (f)(1) of this section is greater than 
30 ppm (or greater than the small refinery standard), compute and report 
as a finding the difference between 30 ppm (or the standard under Sec. 
80.240) and the value in paragraph (f)(1) of this section.
    (3) Compute and report as a finding the total sulfur credits 
required by multiplying the value in paragraph (f)(2) of this section 
times the volume of gasoline not classified as GPA in paragraph (b)(3) 
of this section, and agree with the report to EPA.
    (4) Obtain the refiner's or importer's representation as to the 
portion of the deficit under paragraph (f)(3) of this section that was 
resolved with credits, the portion that was resolved with allotments in 
2005 only or that was carried forward as a deficit under Sec. 80.205, 
and agree with the report to EPA (refineries subject to standards under 
Sec. 80.240 cannot carry deficits forward).
    (g) Credits required for GPA gasoline. The following attest 
procedures shall be completed in 2004 through 2006 for a refinery or 
importer that produces gasoline subject to the geographic phase-in area 
standards under Sec. 80.216:
    (1) Obtain the annual average sulfur level for the refinery's or 
importer's GPA gasoline from paragraph (b)(3) of this section.
    (2) If the value in paragraph (g)(1) of this section is greater than 
the refinery's or importer's baseline plus 30 ppm under Sec. 80.216, as 
determined in paragraph (a) of this section or 150 ppm, whichever is 
less, compute and report as a finding the difference between the annual 
average sulfur level and the baseline level plus 30 ppm, or 150 ppm, 
whichever is less.
    (3) Compute and report as a finding the total sulfur credits and/or 
allotments required by multiplying the value in paragraph (g)(2) of this 
section times the volume of GPA gasoline from paragraph (b)(3) of this 
section.
    (4) Obtain the refiner's or importer's representation as to the 
portion of the deficit under paragraph (g)(3) of this section that was 
resolved with credits, or the portion that was resolved with allotments 
in 2004 or 2005 only (compliance deficits for GPA gasoline cannot be 
carried forward).
    (h) Credit expiration. The following attest procedures shall be 
completed for a refinery or importer that possesses credits during an 
averaging period:
    (1) Obtain a list of all credits in the refiner's or importer's 
possession at any time during the year being reviewed, identified by the 
year of creation of the credits.
    (2) If the year being reviewed is 2006 and thereafter, except in the 
case of gasoline produced for use in the GPA and gasoline produced by 
small refiners, determine whether any credits identified in paragraph 
(h)(1) of this section or Type A sulfur allotments created under 
paragraph (i) of this section and converted to credits were created 
before 2004, and if so, report as a finding this number of expired 
credits.
    (3) If the year being reviewed is 2008 and thereafter, determine 
whether any credits identified in paragraph (h)(1) of this section or 
Type B sulfur allotments created under paragraph (i) of this section and 
converted to credits were created more than 5 years before the year 
being reviewed, and if so, report as a finding this number of expired 
credits (for example, unused credits created during the 2004 averaging 
period expire at the end of the 2009 averaging period).
    (i) Optional credit and allotment generation in 2003. The following 
requirements apply to any refinery that generates credits and allotments 
in 2003 under Sec. 80.275(a):
    (1) Obtain a written representation from the company representative 
stating the refinery produces gasoline from crude oil.

[[Page 900]]

    (2) Obtain the refinery baseline value from paragraph (b)(1) of this 
section, the annual volume from paragraph (b)(2) of this section and the 
annual average sulfur level from paragraph (b)(4) of this section.
    (3) Based on the annual sulfur level and refinery baseline, 
determine which equation under Sec. 80.275(a)(2) applies.
    (4) Using the applicable equations under Sec. 80.275(a)(2), 
recalculate the sulfur allotments, by type, and credits and report as a 
finding.
    (j) Credit reconciliation. The following attest procedures shall be 
completed each year credits were in the refiner's or importer's 
possession at any time during the year:
    (1) Obtain the credits remaining or the credit deficit from the 
previous year from the refiner's or importer's report to EPA for the 
previous year.
    (2) Compute and report as a finding the net credits remaining at the 
conclusion of the year being reviewed by totaling:
    (i) Credits remaining from the previous year; plus
    (ii) Credits generated under paragraphs (c), (d) and (i) of this 
section; plus
    (iii) Allotments generated under paragraph (i) of this section which 
are converted to credits; plus
    (iv) Credits purchased under paragraph (e) of this section; minus
    (v) Credits sold under paragraph (e) of this section; minus
    (vi) Credits used under paragraphs (f) and (g) of this section; 
minus
    (vii) Credits expiring under paragraph (h) of this section; minus
    (viii) Credit deficit from the previous year.
    (3) Agree the credits remaining or the credit deficit at the 
conclusion of the year being reviewed with the report to EPA.
    (4) If the refinery or importer had a credit deficit for both the 
previous year and the year being reviewed, report this fact as a 
finding.
    (k) Sulfur allotments in 2004 and 2005. The following requirements 
apply to any refinery or importer that is subject to corporate pool 
average standards under Sec. 80.195:
    (1) Corporate pool average. (i) Obtain the annual average sulfur 
level for the refiner or importer from the sulfur report filed with EPA 
for all gasoline subject to corporate pool standards (all gasoline 
produced and imported, except that if 50% or greater of the gasoline 
volume was GPA gasoline the refiner or importer is not subject to the 
corporate pool average).
    (ii) Compute and report as a finding the company's gasoline volume 
subject to corporate pool standards and average sulfur level for 
gasoline subject to corporate pool standards, and agree with the values 
reported to EPA.
    (2) Allotment generation. (i) For 2004, if the corporate pool 
average is less than 120 ppm, compute and report as a finding the number 
and type of sulfur allotments generated in accordance with the 
applicable provisions under Sec. 80.275(b).
    (ii) For 2005, if the corporate pool average is less than 90 ppm, 
compute and report as a finding the number and type of sulfur allotments 
generated in accordance with the applicable provisions under Sec. 
80.275(b).
    (iii) If the refiner or importer produced and imported 50% or more 
of its gasoline for GPA use in 2004 or 2005, no allotments can be 
generated in that year.
    (3) Allotment purchases and sales. (i) Obtain contracts or other 
documents for all allotments transferred to another company during the 
year being reviewed; compute and report as a finding the number of 
allotments represented in these documents as being transferred away; and 
agree with the report to EPA.
    (ii) Obtain contracts or other documents for all allotments received 
during the year being reviewed; compute and report as a finding the 
number of allotments represented in these documents as being received; 
and agree with the report to EPA.
    (4) Allotments required. (i) For 2004, if the corporate pool average 
is greater than 120 ppm, compute and report as a finding the number of 
allotments required by multiplying the amount the corporate pool average 
is above 120 ppm times the corporate pool volume, and agree with the 
report to EPA.
    (ii) For 2005, if the corporate pool average is greater than 90 ppm, 
compute and report as a finding the number of

[[Page 901]]

allotments required by multiplying the amount the corporate pool average 
is above 90 ppm times the corporate pool volume, and agree with the 
report to EPA.
    (iii) Obtain the number of allotments used to meet standards for GPA 
gasoline determined in paragraph (g) of this section.
    (5) Allotment reconciliation. (i) Compute and report as a finding 
the net allotments remaining at the conclusion of the year being 
reviewed by totaling allotments:
    (A) Generated under paragraphs (i)(4) and (k)(2) of this section; 
plus
    (B) Purchased under paragraph (k)(3) of this section; minus
    (C) Sold under paragraph (k)(3) of this section; minus
    (D) Used under paragraph (k)(4) of this section for demonstrating 
compliance with the corporate pool average.
    (ii) Report as a finding any allotments generated in 2003 or 2004 
that are used to meet the corporate pool standards in 2005 that were not 
reduced to 50% of their original value.
    (iii) If the company's net allotments remaining are less than zero, 
report this fact as a finding.

[65 FR 6823, Feb. 10, 2000, as amended at 67 FR 40185, June 12, 2002; 71 
FR 54912, Sept. 20, 2006]



  Subpart I_Motor Vehicle, Nonroad, Locomotive, and Marine Diesel Fuel

    Source: 66 FR 5136, Jan. 18, 2001, unless otherwise noted.

                           General Information



Sec. 80.500  What are the implementation dates for the motor vehicle
diesel fuel sulfur control program?

    The implementation dates for standards for motor vehicle diesel fuel 
and diesel fuel additives, and for other provisions of this subpart, are 
as follows:
    (a) Implementation date for standards applicable to production or 
importation of motor vehicle diesel fuel, and to motor vehicle diesel 
fuel additives. Except as provided in paragraph (d) of this section, 
beginning June 1, 2006:
    (1) The standards and requirements under Sec. 80.520(a) and (b) 
shall apply to any motor vehicle diesel fuel produced or imported by any 
refiner or importer; and
    (2) The standards and requirements under Sec. 80.521 shall apply to 
any motor vehicle diesel fuel additive.
    (b) Implementation date for standards applicable to motor vehicle 
diesel fuel downstream of the refinery or importer. Except as provided 
in paragraphs (c) and (d) of this section, beginning September 1, 2006, 
the standards and requirements under Sec. 80.520(a) shall apply to any 
motor vehicle diesel fuel at any downstream location.
    (c) Implementation date for standards applicable to motor vehicle 
diesel fuel at retail outlets and wholesale purchaser-consumer 
facilities. Except as provided in paragraph (d) of this section, 
beginning October 15, 2006, the standards and requirements under Sec. 
80.520(a) shall apply to any motor vehicle diesel fuel at any retail 
outlet or wholesale purchaser-consumer facility.
    (d) Implementation date for motor vehicle diesel fuel subject to the 
500 ppm sulfur content standard in Sec. 80.520(c). (1) Beginning June 
1, 2006, the sulfur content standard of Sec. 80.520(c) shall apply to 
motor vehicle diesel fuel, but only where authorized under, and subject 
to, an applicable provision of this Subpart.
    (2) Beginning June 1, 2010, the sulfur content standard of Sec. 
80.520(c) shall no longer apply to any motor vehicle diesel fuel 
produced or imported by any refiner or importer.
    (3) Beginning October 1, 2010, the sulfur content standard of Sec. 
80.520(c) shall no longer apply to any motor vehicle diesel fuel at any 
downstream location other than a retail or wholesale purchaser-consumer 
facility.
    (4) Beginning December 1, 2010, the sulfur content standard of Sec. 
80.520(c) shall no longer apply to any motor vehicle diesel fuel.
    (e) Other provisions. All other provisions of this subpart apply 
beginning June 1, 2006, unless another date is specified.

[66 FR 5136, Jan. 18, 2001, as amended at 69 FR 39168, June 29, 2004; 70 
FR 70509, Nov. 22, 2005]

[[Page 902]]



Sec. 80.501  What fuel is subject to the provisions of this subpart?

    (a) Included fuel and additives. The provisions of this subpart 
apply to the following fuels and additives except as specified in 
paragraph (b) of this section:
    (1) Motor vehicle diesel fuel.
    (2) Nonroad, locomotive, or marine diesel fuel.
    (3) Diesel fuel additives.
    (4) Heating oil.
    (5) Other distillate fuels.
    (6) Motor oil that is used as or intended for use as fuel in diesel 
motor vehicles or nonroad diesel engines or is blended with diesel fuel 
for use in diesel motor vehicles or nonroad diesel engines, including 
locomotive and marine diesel engines, at any downstream location.
    (b) Excluded fuel. The provisions of this subpart do not apply to 
distillate fuel that is designated for export outside the United States 
in accordance with Sec. 80.598, identified for export by a transfer 
document as required under Sec. 80.590, and that is exported.

[69 FR 39168, June 29, 2004]



Sec. 80.502  What definitions apply for purposes of this subpart?

    The definitions of Sec. 80.2 and the following additional 
definitions apply to this subpart I:
    (a) Entity means any refiner, importer, distributor, retailer or 
wholesale-purchaser consumer of any distillate fuel.
    (b) Facility means any place, or series of places, where an entity 
produces, imports, or maintains custody of any distillate fuel from the 
time it is received to the time custody is transferred to another 
entity, except as described in paragraphs (b)(1) through (b)(4) of this 
section:
    (1) Where an entity maintains custody of a batch of diesel fuel from 
one place in the distribution system to another place (e.g., from a 
pipeline to a terminal), all owned by the same entity, both places 
combined are considered to be one single aggregated facility, except 
where an entity chooses to treat components of such an aggregated 
facility as separate facilities. The choice made to treat these places 
as separate facilities may not be changed by the entity during any 
applicable compliance period. Except as specified in paragraph (b)(2) of 
this section, where compliance requirements depend upon facility-type, 
the entire facility must comply with the requirements that apply to its 
components as follows:
    (i) If an aggregated facility includes a refinery, the entire 
facility must comply with the requirements applicable to refineries.
    (ii) If an aggregated facility includes a truck loading terminal but 
not a refinery, the entire facility must comply with the requirements 
applicable to truck loading terminals.
    (iii) Situations where a refinery is aggregated with a truck loading 
terminal.
    (A) Where a refinery is aggregated with a truck loading terminal, 
diesel fuel or other product subject to the requirements of this subpart 
I produced by such refinery and distributed over the truck terminal rack 
must be included in refinery batches that may be based on shipments to a 
truck terminal rack tank or on the total volumes delivered to tanker 
trucks for a period not to exceed 1 calendar month per batch.
    (B) Where a refinery is aggregated with a truck loading terminal, 
diesel fuel or other product subject to the requirements of this subpart 
I that were imported or produced by another refinery, and that are 
distributed through the refinery or truck terminal rack, must be treated 
as previously designated fuel for which the aggregated facility is 
responsible for all applicable balance and downgrade requirements under 
Sec. Sec. 80.527, 80.598, 80.599 and related recordkeeping and 
reporting requirements like any other distributor downstream from the 
refiner or importer.
    (2) A refinery or import facility may not be aggregated with 
facilities that receive fuel from other refineries or import facilities, 
either directly or indirectly. For example, a refinery may not be 
aggregated with a terminal that receives any fuel from a common carrier 
pipeline. However, a refinery may be aggregated with a pipeline and 
terminal that are owned by the same entity and which receive no fuel 
from any source other than the refinery. Likewise, a refinery may not be 
aggregated

[[Page 903]]

with a mobile facility that is also carrying another entity's fuel; it 
may however be aggregated with a mobile facility that does not receive 
fuel from any source other than the refinery. If a refinery or import 
facility is aggregated with other facilities, then the aggregated 
facility is treated as a refinery or import facility.
    (3) Retail outlets or wholesale purchaser consumers may not be 
aggregated with any other facility.
    (4) Mobile components and mobile facilities. (i) Where an entity 
maintains custody of diesel fuel in one or more mobile components (e.g., 
rail, barge, shipping, or trucking operations), the mobile components 
may be aggregated as a single facility. Mobile components may also be 
aggregated with a facility from which they receive fuel or a facility to 
which they deliver fuel. However, mobile components may not be 
aggregated with both a facility from which they receive fuel and a 
facility to which they deliver fuel.
    (ii) When an entity maintains title to, but not custody of, diesel 
fuel in one or more mobile components, the entity may treat the mobile 
component(s) as a facility under this paragraph (b), but only for the 
fuel to which the entity has title. In the event that title changes 
while a mobile component is in transport (but the fuel physically 
remains in the same mobile facility), the original entity that had title 
to the fuel continues to be responsible for the designate and track 
requirements until custody of the fuel is transferred from the mobile 
facility.
    (5) An individual refinery or contiguous pipeline may not be 
subdivided into more than one facility. An individual terminal may not 
be subdivided into more than one facility unless approved by the 
Administrator.
    (c) Truck loading terminal means any facility that dyes NRLM diesel 
fuel, pays taxes on motor vehicle diesel fuel per IRS code (26 CFR part 
48), or adds a fuel marker pursuant to Sec. 80.510 to heating oil and 
delivers diesel fuel or heating oil into trucks for delivery to retail 
or ultimate consumer locations.
    (d) Batch means a quantity of diesel fuel or distillate which is 
homogeneous with regard to those properties that are specified for 
MVNRLM diesel fuel under this subpart I of this part, has the same 
designation under this subpart I (if applicable), and whose custody is 
transferred from one facility to another facility.
    (1) In the case of aggregated facilities consisting of a refinery 
and a truck loading terminal, a batch may be defined by one of the 
following methods:
    (i) The sum of the deliveries from the truck loading terminal rack 
to trucks for periods not to exceed 1 month;
    (ii) Each individual truck or truck compartment; or
    (iii) For refineries with ``certification tanks'' where testing is 
performed and ``rack tanks'' that feed the truck loading terminal rack, 
each transfer from the certification tank to the rack tank. If this 
method of determining a batch is selected, it must be the sole method 
used and must be performed such that no double-counting or undercounting 
of volumes occurs.
    (2) [Reserved]
    (e) Downstream location means any point in the diesel fuel 
distribution system that is downstream of refineries and import 
facilities, for example, diesel fuel at facilities of distributors, 
carriers, retailers, kerosene blenders, and wholesale purchaser-
consumers.
    (f) Definition of PADD. For the purposes of this subpart only, the 
following definitions of PADDs apply:
    (1) The following States 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

    (2) The following States are included in PADD II:

Illinois
Indiana

[[Page 904]]

Iowa
Kansas
Kentucky
Michigan
Minnesota
Missouri
Nebraska
North Dakota
Ohio
Oklahoma
South Dakota
Tennessee
Wisconsin

    (3) The following States are included in PADD III:

Alabama
Arkansas
Louisiana
Mississippi
New Mexico
Texas

    (4) The following States are included in PADD IV:

Colorado
Idaho
Montana
Utah
Wyoming

    (5) The following States are included in PADD V:

Alaska
Arizona
California
Hawaii
Nevada
Oregon
Washington

    (6) The following areas are included in PADD VI:

U.S. Virgin Islands
Commonwealth of Puerto Rico


[69 FR 39168, June 29, 2004, as amended at 70 FR 70509, Nov. 22, 2005; 
71 FR 25716, May 1, 2006]



Sec. Sec. 80.503-80.509  [Reserved]



Sec. 80.510  What are the standards and marker requirements for
NRLM diesel fuel?

    (a) Beginning June 1, 2007. Except as otherwise specifically 
provided in this subpart, all NRLM diesel fuel is subject to the 
following per-gallon standards:
    (1) Sulfur content. 500 parts per million (ppm) maximum.
    (2) Cetane index or aromatic content, as follows:
    (i) A minimum cetane index of 40; or
    (ii) A maximum aromatic content of 35 volume percent.
    (b) Beginning June 1, 2010. Except as otherwise specifically 
provided in this subpart, all NR and LM diesel fuel is subject to the 
following per-gallon standards:
    (1) Sulfur content.
    (i) 15 ppm maximum for NR diesel fuel.
    (ii) 500 ppm maximum for LM diesel fuel.
    (2) Cetane index or aromatic content, as follows:
    (i) A minimum cetane index of 40; or
    (ii) A maximum aromatic content of 35 volume percent.
    (c) Beginning June 1, 2012. Except as otherwise specifically 
provided in this subpart, all NRLM diesel fuel is subject to the 
following per-gallon standards:
    (1) Sulfur content. 15 ppm maximum.
    (2) Cetane index or aromatic content, as follows:
    (i) A minimum cetane index of 40; or
    (ii) A maximum aromatic content of 35 volume percent.
    (d) Marking provisions. From June 1, 2007 through May 31, 2010:
    (1) Except as provided for in paragraph (i) of this section, prior 
to distribution from a truck loading terminal, all heating oil shall 
contain six milligrams per liter of marker solvent yellow 124.
    (2) All motor vehicle and NRLM diesel fuel shall be free of solvent 
yellow 124.
    (3) Any diesel fuel that contains greater than or equal to 0.10 
milligrams per liter of marker solvent yellow 124 shall be deemed to be 
heating oil and shall be prohibited from use in any motor vehicle or 
nonroad diesel engine (including locomotive, or marine diesel engines).
    (4) Except as provided for in paragraph (i) of this section, any 
diesel fuel, other than jet fuel or kerosene that is downstream of a 
truck loading terminal, that contains less than 0.10 milligrams per 
liter of marker solvent yellow 124 shall be considered motor vehicle 
diesel fuel or NRLM diesel fuel, as appropriate.

[[Page 905]]

    (5) Any heating oil that is required to contain marker solvent 
yellow 124 pursuant to the requirements of this paragraph (d) must also 
contain visible evidence of dye solvent red 164.
    (e) Marking provisions. From June 1, 2010 through May 31, 2012:
    (1) Except as provided for in paragraph (i) of this section, prior 
to distribution from a truck loading terminal, all heating oil and 
diesel fuel designated as 500 ppm sulfur LM diesel fuel shall contain 
six milligrams per liter of solvent yellow 124.
    (2) All motor vehicle and NR diesel fuel shall be free of marker 
solvent yellow 124.
    (3) Any diesel fuel that contains greater than or equal to 0.10 
milligrams per liter of marker solvent yellow 124 shall be deemed to be 
LM diesel fuel or heating oil, as appropriate, and shall be prohibited 
from use in any motor vehicle or nonroad diesel engine (except for 
locomotive or marine diesel engines).
    (4) Except as provided for in paragraph (i) of this section, any 
diesel fuel, other than jet fuel or kerosene that is downstream of a 
truck loading terminal, that contains less than 0.10 milligrams per 
liter of marker solvent yellow 124 shall be considered motor vehicle 
diesel fuel or NR diesel fuel, as appropriate.
    (5) Any LM diesel fuel or heating oil that is required to contain 
marker solvent yellow 124 pursuant to the requirements of this paragraph 
(e) must also contain visible evidence of dye solvent red 164.
    (f) Marking provisions. Beginning June 1, 2012:
    (1) Except as provided for in paragraph (i) of this section, prior 
to distribution from a truck loading terminal, all heating oil shall 
contain six milligrams per liter of marker solvent yellow 124.
    (2) All motor vehicle and NRLM diesel fuel shall be free of marker 
solvent yellow 124.
    (3) Any diesel fuel that contains greater than or equal to 0.10 
milligrams per liter of marker solvent yellow 124 shall be deemed to be 
heating oil and shall be prohibited from use in any motor vehicle or 
nonroad diesel engine (including locomotive, or marine diesel engines).
    (4) Except as provided for in paragraph (i) of this section, any 
diesel fuel, other than jet fuel or kerosene that is downstream of a 
truck loading terminal, that contains less than 0.10 milligrams per 
liter of marker solvent yellow 124 shall be considered motor vehicle 
diesel fuel or NRLM diesel fuel, as appropriate.
    (5) Any heating oil that is required to contain marker solvent 
yellow 124 pursuant to the requirements of this paragraph (f) must also 
contain visible evidence of dye solvent red 164.
    (g) Special provisions in this part apply to the following areas:
    (1) Northeast/Mid-Atlantic Area which includes the following states 
and counties: North Carolina, Virginia, Maryland, Delaware, New Jersey, 
Connecticut, Rhode Island, Massachusetts, Vermont, New Hampshire, Maine, 
Washington D.C., New York (except for the counties of Chautauqua, 
Cattaraugus, and Allegany), Pennsylvania (except for the counties of 
Erie, Warren, Mc Kean, Potter, Cameron, Elk, Jefferson, Clarion, Forest, 
Venango, Mercer, Crawford, Lawrence, Beaver, Washington, and Greene), 
and the eight eastern-most counties of West Virginia (Jefferson, 
Berkeley, Morgan, Hampshire, Mineral, Hardy, Grant, and Pendleton).
    (2) Alaska.
    (h) Pursuant and subject to the provisions of Sec. 80.536, Sec. 
80.554, Sec. 80.560, or Sec. 80.561:
    (1) Except as provided in paragraph (j) of this section, from June 
1, 2007 through May 31, 2010, NRLM diesel fuel produced or imported in 
full compliance with the requirements of Sec. Sec. 80.536, 80.554, 
80.560, and 80.561 is exempt from the per-gallon sulfur content standard 
and cetane or aromatics standard of paragraph (a) of this section.
    (2) Except as provided in paragraph (j) of this section, from June 
1, 2010 through May 31, 2012 for NR diesel fuel and from June 1, 2012 
through May 31, 2014 for NRLM diesel fuel produced or imported in full 
compliance with the requirements of Sec. Sec. 80.536, 80.554, 80.560, 
and 80.561 is exempt from the per-gallon standards of paragraphs (b) and 
(c) of this section, but is subject to the

[[Page 906]]

per-gallon standards of paragraph (a) of this section.
    (i) The marking requirements of paragraphs (d)(1), (d)(4), (e)(1), 
(e)(4), (f)(1), and (f)(4) of this section do not apply to heating oil, 
or, for paragraphs (e)(1) and (e)(4) of this section, diesel fuel 
designated as LM diesel fuel that is distributed from a truck loading 
terminal located within the areas listed in paragraphs (g)(1) and (g)(2) 
of this section and is for sale or intended for sale within these areas, 
or that is distributed from any other truck loading terminal and is for 
sale or intended for sale within the area listed in (g)(2) of this 
section.
    (j) The provisions of paragraphs (h)(1) and (h)(2) of this section 
do not apply to diesel fuel sold or intended for sale in the areas 
listed in paragraph (g)(1) of this section that is produced or imported 
in full compliance with the requirements of Sec. Sec. 80.536 and 80.554 
or to diesel fuel sold or intended for sale in the area listed in 
paragraph (g)(2) of this section that is produced or imported in full 
compliance with the requirements of Sec. 80.536.

[69 FR 39168, June 29, 2004, as amended at 70 FR 40895, July 15, 2005]



Sec. 80.511  What are the per-gallon and marker requirements that
apply to NRLM diesel fuel and heating oil downstream of the

refiner or importer?

    (a) Applicable dates for marker requirements. Beginning June 1, 
2006, all NRLM diesel fuel shall contain less than 0.10 milligrams per 
liter of the marker solvent yellow 124, except for LM diesel fuel 
subject to the marking requirements of Sec. 80.510(e).
    (b) Applicable dates for per-gallon standards. (1) Beginning June 1, 
2006, all NRLM diesel fuel must comply with the per-gallon sulfur 
standard for the designation or classification stated on its PTD, pump 
label, or other documentation. Based on the provisions of Sec. 
80.510(h) and (j), there is no uniform downstream sulfur standard until 
the downstream dates identified in paragraphs (b)(3) through (b)(8) of 
this section.
    (2) Except as provided in paragraphs (b)(5) and (b)(8) of this 
section, beginning December 1, 2010, all NRLM diesel fuel must comply 
with the cetane index or aromatics standard of Sec. 80.510.
    (3) Except as provided in paragraphs (b)(5) through (b)(8) of this 
section, the per-gallon sulfur standard of Sec. 80.510(a) shall apply 
to all NRLM diesel fuel beginning August 1, 2010 for all downstream 
locations other than retail outlets or wholesale purchaser-consumer 
facilities, shall apply to all NRLM diesel fuel beginning October 1, 
2010 for retail outlets and wholesale purchaser-consumer facilities, and 
shall apply to all NRLM diesel fuel beginning December 1, 2010 for all 
locations.
    (4) Except as provided in paragraphs (b)(5) through (b)(8) of this 
section, the per-gallon sulfur standard of Sec. 80.510(c) shall apply 
to all NRLM diesel fuel beginning August 1, 2014 for all downstream 
locations other than retail outlets or wholesale purchaser-consumer 
facilities, shall apply to all NRLM diesel fuel beginning October 1, 
2014 for retail outlets and wholesale purchaser-consumer facilities, and 
shall apply to all NRLM diesel fuel beginning December 1, 2014 for all 
locations. This paragraph (b)(4) does not apply to LM diesel fuel that 
is sold or intended for sale in areas other than those listed in Sec. 
80.510(g)(1) or (g)(2).
    (5) For all NRLM diesel fuel that is sold or intended for sale in 
the areas listed in Sec. 80.510(g)(1), the per-gallon sulfur standard 
and the cetane index or aromatics standard of 80.510(a) shall apply to 
all NRLM diesel fuel beginning August 1, 2007 for all downstream 
locations other than retail outlets or wholesale purchaser-consumer 
facilities, shall apply to all NRLM diesel fuel beginning October 1, 
2007 for retail outlets and wholesale purchaser-consumer facilities, and 
shall apply to all NRLM diesel fuel beginning December 1, 2007 for all 
locations.
    (6) For all NR diesel fuel that is sold or intended for sale in the 
areas listed in Sec. 80.510(g)(1), the per-gallon sulfur standard of 
Sec. 80.510(b) shall apply to all NR diesel fuel beginning August 1, 
2010 for all downstream locations other than retail outlets or wholesale 
purchaser-consumer facilities, shall apply to all NR diesel fuel 
beginning October 1, 2010 for retail outlets and wholesale purchaser-
consumer facilities, and

[[Page 907]]

shall apply to all NR diesel fuel beginning December 1, 2010 for all 
locations.
    (7) For all NRLM diesel fuel that is sold or intended for sale in 
the areas listed in Sec. 80.510(g)(1), the per-gallon sulfur standard 
of Sec. 80.510(c) shall apply to all NRLM diesel fuel beginning August 
1, 2012 for all downstream locations other than retail outlets or 
wholesale purchaser-consumer facilities, shall apply to all NRLM diesel 
fuel beginning October 1, 2012 for retail outlets and wholesale 
purchaser-consumer facilities, and shall apply to all NRLM diesel fuel 
beginning December 1, 2012 for all locations.
    (8) The provisions of paragraphs (b)(5) through (b)(7) of this 
section shall apply for all NRLM or NR diesel fuel that is sold or 
intended for sale in the area listed in Sec. 80.510(g)(2), except for 
NRLM or NR diesel fuel that is produced in accordance with a compliance 
plan approved under Sec. 80.554.
    (9) For the purposes of this section, distributors that have their 
own fuel storage tanks and deliver only to ultimate consumers shall be 
treated the same as retailers and their facilities treated the same as 
retail outlets.

[69 FR 39169, June 29, 2004]



Sec. 80.512  May an importer treat diesel fuel as blendstock?

    An importer may exclude diesel fuel that it imports from the 
requirements under this subpart, and instead may designate such diesel 
fuel as diesel fuel treated as blendstock (DTAB), if all the following 
conditions are met:
    (a) The DTAB must be included in all applicable designation, credit 
and compliance calculations for diesel fuel for a refinery operated by 
the same entity that is the importer . That entity must meet all refiner 
standards and requirements.
    (b) The importer entity may not transfer title of the DTAB to 
another entity until the DTAB has been used to produce diesel fuel and 
all refiner standards and requirements have been met for the diesel fuel 
produced.
    (c) The refinery at which the DTAB is used to produce diesel fuel 
must be physically located at either the same terminal at which the DTAB 
first arrives in the U.S., the import facility, or at a facility to 
which the DTAB is directly transported from the import facility.
    (d) The DTAB must be completely segregated from any other diesel 
fuel, including any diesel fuel tank bottoms, prior to the point of 
blending, sampling and testing in the importer entity's refinery 
operation. The DTAB may, however, be added to a diesel fuel blending 
tank where the diesel fuel tank bottom is not included as part of the 
batch volume for a prior batch. In addition, the DTAB may be placed into 
a storage tank that contains other DTAB imported by that importer. The 
DTAB also may be discharged into a tank containing finished diesel fuel 
of the same category as the diesel fuel which will be produced using the 
DTAB (for example, 15 ppm sulfur undyed or 15 ppm sulfur dyed diesel 
fuel) provided the blending process is performed in that same tank.
    (e) The entity must account for the volume of diesel fuel produced 
using DTAB in a manner that excludes the volume of any previously 
designated diesel fuel. The diesel fuel tank bottom may not be included 
in the company's refinery compliance calculations for that batch of 
diesel fuel if the fuel in that tank bottom has been previously 
designated by a refiner or importer. This exclusion of previously 
designated diesel fuel must be accomplished using the following 
approach:
    (1) Determine the volume of any tank bottom that is previously 
designated diesel fuel before any diesel fuel production begins.
    (2) Add the DTAB plus any blendstock to the storage tank, and 
completely mix the tank.
    (3) Determine the volume and sulfur content of the diesel fuel 
contained in the storage tank after blending is complete. Mathematically 
subtract the volume of the tank bottom to determine the volume of the 
DTAB plus blendstock added, and subsequently transferred to another 
facility. Such fuel is reported to EPA as a batch of diesel fuel under 
Sec. Sec. 80.593, 80.601, and 80.604.
    (4) If previously designated motor vehicle diesel fuel having a 
sulfur content of 15 ppm or less is blended with DTAB, and the combined 
product after

[[Page 908]]

blending has a sulfur content that exceeds 15 ppm, the importer entity, 
in its capacity as a refiner, must redesignate all the diesel fuel as 
500 ppm sulfur motor vehicle diesel fuel for purposes of the temporary 
compliance option under Sec. 80.530, or other permissible redesignation 
under Sec. 80.598. If 2D 15 ppm sulfur motor vehicle diesel 
fuel is redesignated as 2D 500 ppm sulfur motor vehicle diesel 
fuel, such entity must apply the volume of previously designated 15 ppm 
sulfur diesel fuel, for purposes of its operations as a distributor, to 
its downgrading limitation under Sec. 80.527, if applicable, and for 
volume balancing purposes under Sec. 80.599.
    (5) As an alternative to paragraphs (e)(1) through (e)(4) of this 
section, where an importer has a blending tank that is used only to 
combine DTAB and blending components, and no previously designated 
diesel fuel is added to the tank, the importer entity, in its capacity 
as a refiner, may account for the diesel fuel produced in such a 
blending tank by sampling and testing for the sulfur content of the 
batch after DTAB and blendstock are added and mixed, and reporting the 
volume of diesel fuel transferred from that tank to a different 
facility, up to the point where a new blend is produced by adding new 
DTAB and blendstock.
    (f) The importer must include the volume and sulfur content of each 
batch of DTAB in the annual importer reports to EPA, as prescribed under 
Sec. Sec. 80.593, 80.601, and 80.604, but with a notation that the 
batch is not included in the importer compliance calculations because 
the product is DTAB. Any DTAB that ultimately is not used in the 
importer's refinery operation (for example, a tank bottom of DTAB at the 
conclusion of the refinery operation), must be treated as newly imported 
diesel fuel, for which all required sampling and testing, and 
recordkeeping must be accomplished, and included in the importer's 
compliance calculations for the averaging period when this sampling and 
testing occurs.
    (g) The importer must retain records that reflect the importation, 
sampling and testing, and physical movement of any DTAB, and must make 
these records available to EPA on request.

[69 FR 39170, June 29, 2004]



Sec. 80.513  What provisions apply to transmix processing facilities?

    For purposes of this section, transmix means a mixture of finished 
fuels that no longer meets the specifications for a fuel that can be 
used or sold without further processing. This section applies to 
refineries that produce diesel fuel from transmix by distillation or 
other refining processes but do not produce diesel fuel by processing 
crude oil. This section only applies to the volume of diesel fuel 
produced by such a transmix processor using these processes, and does 
not apply to any diesel fuel produced by the blending of blendstocks.
    (a) From June 1, 2006 through May 31, 2010, motor vehicle diesel 
fuel produced by a transmix processor is subject to the 500 ppm sulfur 
standard under Sec. 80.520(c).
    (b) Beginning June 1, 2010, motor vehicle diesel fuel produced by a 
transmix processor is subject to the sulfur standard under Sec. 
80.520(a)(1).
    (c) From June 1, 2007 through May 31, 2010, NRLM diesel fuel 
produced by a transmix processor is exempt from the standards of Sec. 
80.510(a). This paragraph (c) does not apply to NRLM diesel fuel that is 
sold or intended for sale in the areas listed in Sec. 80.510(g)(1) or 
(g)(2).
    (d) From June 1, 2010 through May 31, 2014, NRLM diesel fuel 
produced by a transmix processor is subject to the standards under Sec. 
80.510(a). This paragraph (d) does not apply to NRLM diesel fuel that is 
sold or intended for sale in the areas listed in Sec. 80.510(g)(1) or 
(g)(2).
    (e) From June 1, 2014 and beyond, NRLM diesel fuel produced by a 
transmix processor is subject to the standards of Sec. 80.510(c), 
except that LM diesel fuel is subject to the sulfur standard of Sec. 
80.510(a). This paragraph (e) does not apply to NRLM or LM diesel fuel 
that is sold or intended for sale in the areas listed in Sec. 
80.510(g)(1) or (g)(2).

[69 FR 39171, June 29, 2004]

[[Page 909]]



Sec. Sec. 80.514-80.519  [Reserved]

          Motor Vehicle Diesel Fuel Standards and Requirements



Sec. 80.520  What are the standards and dye requirements for motor
vehicle diesel fuel?

    (a) Standards. All motor vehicle diesel fuel is subject to the 
following per-gallon standards:
    (1) Sulfur content. 15 parts per million (ppm) maximum, except as 
provided in paragraph (c) of this section;
    (2) Cetane index and aromatic content. (i) A minimum cetane index of 
40; or
    (ii) A maximum aromatic content of 35 volume percent.
    (b) Dye requirements. (1) All motor vehicle diesel fuel shall be 
free of visible evidence of dye solvent red 164 (which has a 
characteristic red color in diesel fuel), except for motor vehicle 
diesel fuel that is used in a manner that is tax exempt under section 
4082 of the Internal Revenue Code. All motor vehicle diesel fuel shall 
be free of yellow solvent 124.
    (2) Until June 1, 2010, any 1D or 2D distillate, 
or NP diesel fuel that does not show visible evidence of dye solvent red 
164 shall be considered to be motor vehicle diesel fuel and subject to 
all the requirements of this subpart for motor vehicle diesel fuel, 
except for distillate fuel designated or classified as any of the 
following:
    (i) For use only in the State of Alaska, as provided under 40 CFR 
69.51.
    (ii) For use under a national security exemption under Sec. 80.606 
or for use only in a research and development testing program exempted 
under Sec. 80.607.
    (iii) For use in the U.S. Territories as provided under Sec. 
80.608.
    (iv) Jet fuel meeting the definition under Sec. 80.2.
    (v) Kerosene meeting the definition under Sec. 80.2.
    (vi) Diesel fuel that is produced beginning June 1, 2006, with a 
sulfur level less than or equal to 500 ppm, and designated as NRLM or LM 
that has not yet been distributed from a truck loading terminal or bulk 
terminal to a retail outlet, wholesale purchaser-consumer or ultimate 
consumer.
    (c) Pursuant and subject to the provisions of Sec. Sec. 80.530-
80.532, 80.552(a), 80.560-80.561, and 80.620, only motor vehicle diesel 
fuel produced or imported in full compliance with the requirements of 
those provisions is subject to the following per-gallon standard for 
sulfur content: 500 ppm maximum.

[66 FR 5136, Jan. 18, 2001, as amended at 69 FR 39171, June 29, 2004; 71 
FR 25717, May 1, 2006]



Sec. 80.521  What are the standards and identification requirements
for diesel fuel additives?

    (a) Except as provided in paragraph (b) of this section, any diesel 
fuel additive that is added to, intended for adding to, used in, or 
offered for use in any MVNRLM diesel fuel subject to the 15 ppm sulfur 
content standards of Sec. 80.510(b), Sec. 80.510(c), or Sec. 
80.520(a) at any downstream location must--
    (1) Have a sulfur content less than or equal to 15 ppm.
    (2) Be accompanied by a product transfer document pursuant to Sec. 
80.591 indicating that the additive complies with the 15 ppm sulfur 
standard for diesel fuel, except for those diesel fuel additives which 
are only sold in containers for use by the ultimate consumer of diesel 
fuel and which are subject to the requirements of Sec. 80.591(d).
    (b) Any diesel fuel additive that is added to, intended for adding 
to, used in, or offered for use in diesel fuel subject to the 15 ppm 
sulfur content standards of Sec. 80.510(b) or (c) or Sec. 80.520(a) 
may have a sulfur content exceeding 15 ppm provided that each of the 
following conditions are met:
    (1) The additive is added to or used in the diesel fuel in a 
quantity less than one percent by volume of the resultant additive/
diesel fuel mixture;
    (2) The product transfer document complies with the informational 
requirements of Sec. 80.591; and
    (3) The additive is not used or intended for use by an ultimate 
consumer in diesel motor vehicles or nonroad diesel engines.

[69 FR 39171, June 29, 2004]



Sec. 80.522  May used motor oil be dispensed into diesel motor
vehicles or nonroad diesel engines?

    No person may introduce used motor oil, or used motor oil blended 
with diesel fuel, into the fuel system of model year 2007 or later 
diesel motor vehicles

[[Page 910]]

or model year 2011 or later nonroad diesel engines (not including 
locomotive or marine diesel engines), unless both of the following 
requirements have been met:
    (a) The vehicle or engine manufacturer has received a Certificate of 
Conformity under 40 CFR part 86, 40 CFR part 89, or 40 CFR part 1039 and 
the certification of the vehicle or engine configuration is explicitly 
based on emissions data with the addition of motor oil; and
    (b) The oil is added in a manner and rate consistent with the 
conditions of the Certificate of Conformity.

[69 FR 39171, June 29, 2004]



Sec. 80.523  [Reserved]



Sec. 80.524  What sulfur content standard applies to motor vehicle 
diesel fuel downstream of the refinery or importer?

    (a) Except as provided in paragraph (b) of this section or otherwise 
in the provisions of this Subpart I, the 15 ppm sulfur content standard 
of Sec. 80.520(a) shall apply to all motor vehicle diesel fuel at any 
downstream location.
    (b) Prior to the October 1, 2010 and December 1, 2010 dates 
specified in Sec. 80.500(d)(3) and (4), the 500 ppm sulfur content 
standard of Sec. 80.520(c) shall apply to motor vehicle diesel fuel at 
any downstream location, provided the following conditions are met:
    (1) The product transfer documents comply with the requirements of 
Sec. 80.590, including indicating that the fuel complies with the 500 
ppm sulfur standard for motor vehicle diesel fuel and is for use only in 
model year 2006 and older diesel motor vehicles, or the fuel is 
downgraded pursuant to the provision of Sec. 80.527 to motor vehicle 
diesel fuel subject to the 500 ppm sulfur standard;
    (2) The motor vehicle diesel fuel is not represented or intended for 
sale or use as subject to the 15 ppm sulfur content standard, and is not 
dispensed, or intended to be dispensed, into model year 2007 and later 
motor vehicles by a retailer or wholesale purchaser-consumer; and
    (3) For retailers or wholesale purchaser-consumers, the pump 
labeling requirements of Sec. 80.570(a) are satisfied.



Sec. 80.525  What requirements apply to kerosene blenders?

    (a) For purposes of this subpart, a kerosene blender means any 
refiner who produces NRLM or motor vehicle diesel fuel by adding 
kerosene to NRLM or motor vehicle diesel fuel downstream of the refinery 
that produced that fuel or of the import facility where the fuel was 
imported, without altering the quality or quantity of the fuel in any 
other manner.
    (b) Kerosene blenders are not subject to the requirements of this 
subpart applicable to refiners of motor vehicle diesel fuel, but are 
subject to the requirements and prohibitions applicable to downstream 
parties.
    (c) For purposes of compliance with Sec. Sec. 80.524(b)(1) and 
80.511(b)(1), the product transfer documents must indicate that the fuel 
to which kerosene is added complies with the 500 ppm sulfur standard for 
motor vehicle diesel fuel and is for use only in model year 2006 and 
older diesel motor vehicles, the fuel is properly downgraded pursuant to 
the provisions of Sec. 80.527 to motor vehicle diesel fuel subject to 
the 500 ppm sulfur standard, or the applicable NRLM standard.
    (d) Kerosene that a kerosene blender adds or intends to add to motor 
vehicle diesel fuel subject to the 15 ppm sulfur content standard must 
meet the 15 ppm sulfur content standard, and the following requirements:
    (1) The product transfer document received by the kerosene blender 
indicates that the kerosene is motor vehicle diesel fuel that complies 
with the 15 ppm sulfur content standard; or
    (2) The kerosene blender has test results indicating the kerosene 
complies with the 15 ppm sulfur standard.

[66 FR 5136, Jan. 18, 2001, as amended at 70 FR 40895, July 15, 2005]



Sec. 80.526  [Reserved]



Sec. 80.527  Under what conditions may motor vehicle diesel fuel
subject to the 15 ppm sulfur standard be downgraded to motor

vehicle diesel fuel subject to 
          the 500 ppm sulfur standard?

    (a) Definitions. As used in this section, downgrade means changing 
the designation or classification of motor

[[Page 911]]

vehicle diesel fuel subject to the 15 ppm sulfur standard under Sec. 
80.520(a)(1) to motor vehicle diesel fuel subject to the 500 ppm sulfur 
standard under Sec. 80.520(c). A downgrade occurs when the change in 
designation or classification takes place. Changing the designation or 
classification of motor vehicle diesel fuel subject to the 15 ppm sulfur 
standard under Sec. 80.520(a)(1) to any designation or classification 
that is not a motor vehicle diesel fuel is not a downgrade for purposes 
of this section.
    (b) Who is subject to the downgrade limitation: Any distributor, 
retailer, or wholesale purchaser consumer that takes custody of any 
diesel fuel designated or classified as 2D 15 ppm sulfur motor 
vehicle diesel fuel and delivers any diesel fuel designated or 
classified as 2D 500 ppm motor vehicle diesel fuel.
    (c) Downgrading limitation. The provisions of this section apply 
beginning October 15, 2006.
    (1) Except as provided in paragraphs (d) and (e) of this section, a 
person described in paragraph (b) of this section may not downgrade a 
total of more than 20 percent of the 2D motor vehicle diesel 
fuel (by volume) that is subject to the 15 ppm sulfur standard of Sec. 
80.520(a)(1) to 2D motor vehicle diesel fuel subject to the 
sulfur standard of Sec. 80.520(c) while such person has custody of such 
fuel.
    (2) The limitation of paragraph (c)(1) of this section applies 
separately to each facility as defined under Sec. 80.502 where there is 
custody of the fuel when it is downgraded.
    (3) Compliance with the limitation of paragraph (c)(1) of this 
section applies separately for the compliance periods of October 15, 
2006 through May 31, 2007; June 1, 2007 through June 30, 2008; July 1, 
2008 through June 30, 2009; July 1, 2009 through May 31, 2010.
    (4) Except as provided in paragraph (e) of this section, compliance 
with the limitation of paragraph (c)(1) of this section shall be as 
calculated under Sec. 80.599(e).
    (d) Diesel fuel in violation of the 15 ppm standard. Where motor 
vehicle diesel fuel subject to the 15 ppm sulfur standard of Sec. 
80.520(a)(1) is found to be in violation of any standard under Sec. 
80.520(a) and is consequently downgraded to 500 ppm sulfur motor vehicle 
diesel fuel, the person having custody of the fuel at the time it is 
found to be in violation must include the volume of such downgraded fuel 
toward its 20 percent volume limitation under paragraph (c)(1) of this 
section, unless the person demonstrates that it did not cause the 
violation.
    (e) Special provisions for retail outlets and wholesale purchaser-
consumer facilities. Notwithstanding the provisions of paragraph (c)(1) 
of this section, retailers and wholesale purchaser-consumers shall 
comply with the downgrading limitation as follows:
    (1) Retailers and wholesale purchaser-consumers who sell, offer for 
sale, or dispense motor vehicle diesel fuel that is subject to the 15 
ppm sulfur standard under Sec. 80.520(a)(1) are exempt from the volume 
limitations of paragraph (c)(1) of this section.
    (2) A retailer or wholesale purchaser-consumer who does not sell, 
offer for sale, or dispense motor vehicle diesel fuel subject to the 15 
ppm sulfur standard under Sec. 80.520(a)(1) must comply with the 
downgrading limitations of paragraph (c) of this section, such that it 
may not downgrade a volume of motor vehicle diesel fuel, designated as 
subject to the 15 ppm sulfur standard, for more than 20% of the total 
volume of motor vehicle diesel fuel that it sells, offers for sale, or 
dispenses in any compliance period.
    (f) Termination of downgrading limitations. The provisions of this 
section shall not apply after May 31, 2010.

[69 FR 39172, June 29, 2004, as amended at 71 FR 25717, May 1, 2006]



Sec. Sec. 80.528-80.529  [Reserved]

                       Temporary Compliance Option



Sec. 80.530  Under what conditions can 500 ppm motor vehicle diesel
fuel be produced or imported after May 31, 2006?

    (a) Beginning June 1, 2006, a refiner or importer may produce or 
import motor vehicle diesel fuel subject to the 500 ppm sulfur content 
standard of Sec. 80.520(c) if all of the following requirements are 
met:
    (1) Each batch of motor vehicle diesel fuel subject to the 500 ppm 
sulfur content standard must be designated by

[[Page 912]]

the refiner or importer as subject to such standard, pursuant to Sec. 
80.598(a).
    (2) The refiner or importer must meet the requirements for product 
transfer documents in Sec. 80.590 for each batch subject to the 500 ppm 
sulfur content standard.
    (3)(i) The volume of motor vehicle diesel fuel that is produced or 
imported during a compliance period (V500, as provided in 
paragraph (a)(5) of this section, may not exceed the following volume 
limit:
    (A) For the compliance periods prior to the period from July 1, 2009 
through May 31, 2010, 20 percent of the volume of motor vehicle diesel 
fuel that is produced or imported during a compliance period 
(Vt) plus an additional volume of motor vehicle diesel fuel 
represented by credits properly generated and used pursuant to the 
requirements of Sec. Sec. 80.531 and 80.532.
    (B) For the compliance period from July 1, 2009 through May 31, 
2010, 20 percent of the volume of motor vehicle diesel fuel that is 
produced or imported prior to January 1, 2010 during the compliance 
period (Vt), plus an additional volume of motor vehicle 
diesel fuel represented by credits properly generated and used pursuant 
to the requirements of Sec. Sec. 80.531 and 80.532. From January 1, 
2010 through May 31, 2010, the volume of motor vehicle diesel fuel that 
is produced or imported shall not exceed the volume represented by 
credits used pursuant to Sec. 80.532.
    (ii) The terms V500 and Vt have the meaning 
specified in Sec. 80.531(a)(2).
    (4) Compliance with the volume limit in paragraph (a)(3) of this 
section must be determined separately for each refinery. For an 
importer, such compliance must be determined separately for each Credit 
Trading Area (as defined in Sec. 80.531) into which motor vehicle 
diesel fuel is imported. If a party is both a refiner and an importer, 
such compliance shall be determined separately for the refining and 
importation activities.
    (5) Compliance with the volume limit in paragraph (a)(3) of this 
section shall be determined on an annual basis, where the annual 
compliance period is from July 1 through June 30. For the year 2006, 
compliance shall be determined for the period June 1, 2006 through June 
30, 2007. For the year 2010, compliance shall be determined for the 
period of July 1, 2009 through May 31, 2010.
    (6) Any motor vehicle diesel fuel produced or imported above the 
volume limit in paragraph (a)(3) of this section shall be subject to the 
15 ppm sulfur content standard. However, for any compliance period prior 
to the compliance period July 1, 2009 through May 31, 2010, a refiner or 
importer may exceed the volume limit in paragraph (a)(3) of this section 
by no more than 5 percent of the volume of diesel fuel produced or 
imported during the compliance period (Vt), provided that for 
the immediately following compliance period:
    (i) The refiner or importer complies with the volume limit in 
paragraph (a)(3) of this section; and
    (ii) The refiner or importer produces or imports a volume of motor 
vehicle diesel fuel subject to the 15 ppm sulfur standard, or obtains 
credits properly generated and used pursuant to the requirements of 
Sec. Sec. 80.531 and 80.532 that represent a volume of motor vehicle 
diesel fuel, equal to the volume of the exceedance for the prior 
compliance period.
    (b) After May 31, 2010, no refiner or importer may produce or import 
motor vehicle diesel fuel subject to the 500 ppm sulfur content standard 
pursuant to this section.

[69 FR 39172, June 29, 2004]



Sec. 80.531  How are motor vehicle diesel fuel credits generated?

    (a) Generation of credits from June 1, 2006 through December 31, 
2009. (1) A refiner or importer may generate credits during the period 
June 1, 2006 through December 31, 2009, for motor vehicle diesel fuel 
produced or imported that is designated as subject to the 15 ppm sulfur 
content standard under Sec. 80.520(a)(1). Credits may be generated only 
if the volume of motor vehicle diesel fuel designated under Sec. 
80.598(a) as subject to the 15 ppm sulfur standard of Sec. 80.520(a) 
exceeds 80 percent of the total volume of motor vehicle diesel fuel 
produced or imported as described in paragraph (a)(2) of this section.

[[Page 913]]

    (2) The number of motor vehicle diesel fuel credits generated shall 
be calculated for each compliance period (as specified in Sec. 
80.530(a)(5)) as follows:

C = V1515-(0.80 x Vt)

Where:

C = the positive number of motor vehicle diesel fuel credits generated, 
in gallons.
V15 = the total volume in gallons of diesel fuel produced or 
imported that is designated under Sec. 80.598 as motor vehicle diesel 
fuel and subject to the standards of Sec. 80.520(a) during the 
compliance period.
Vtn = V15 + V500
V500 = the total volume in gallons of diesel fuel produced or 
imported that is designated under Sec. 80.598(a) as motor vehicle 
diesel fuel and subject to the 500 ppm sulfur standard under Sec. 
80.520(c) plus the total volume of any other diesel fuel (not including 
V15, diesel fuel that is dyed in accordance with Sec. 
80.520(b) at the refinery or import facility where the diesel fuel is 
produced or imported, or diesel fuel that is designated as NRLM under 
Sec. 80.598(a)) represented as having a sulfur content less than or 
equal to 500 ppm.

    (3) Credits shall be generated and designated as follows:
    (i) Credits shall be generated separately for each refinery of a 
refiner.
    (ii) Credits shall be generated separately for each credit trading 
area (CTA), as defined in paragraph (a)(5) of this section, into which 
motor vehicle diesel fuel is imported by an importer.
    (iii) Credits shall be designated separately by year of generation 
and by CTA of generation. In the case of a refiner, credits shall also 
be designated by refinery, and in the case of an importer, credits shall 
also be designated by port of import.
    (iv) Credits may not be generated by both a foreign refiner and by 
an importer for the same motor vehicle diesel fuel.
    (4) Credits shall be generated by a foreign refiner as provided in 
Sec. 80.620(c) and this section.
    (5) For purposes of this subpart, the CTAs are:
    (i) PADDs I, II, III and IV, as described in Sec. 80.502(f) except 
as provided in paragraph (a)(5)(iv) of this section. The CTAs shall be 
designated as CTA 1, 2, 3, and 4, respectively, and correspond to PADDs 
I, II, III, and IV, respectively;
    (ii) CTA 5 shall correspond to PADD V, as described in Sec. 
80.502(f), except as provided in paragraphs (a)(5)(iii) and (iv) of this 
section;
    (iii) The states of Hawaii and Alaska shall each be treated as a 
separate CTA and not a part of CTA 5. Alaska shall be CTA 6. Hawaii 
shall be CTA 7;
    (iv) If any state (through a waiver of federal preemption under 
Section 211(c)(4) of the Clean Air Act, 42 U.S.C. 7545(c)(4)) implements 
a law or regulation that requires a greater volume of motor vehicle 
diesel fuel to meet a sulfur standard of less than or equal to 15 ppm 
than the volume that is required under this subpart, no motor vehicle 
diesel fuel produced in that state or imported directly into that state 
may generate credits under this subpart, effective on the implementation 
date of the sulfur program under the state statute or regulation that 
implements the more stringent state requirements.
    (v) The U.S. territories specified in Sec. 80.502(f)(6) shall be 
included in CTA 1.
    (6) No credits may be generated under this paragraph (a) after 
December 31, 2009.
    (7) No refinery may generate credits under both this paragraph (a) 
and under paragraph (e) of this section.
    (b) Generation of early credits from June 1, 2001 through May 31, 
2005. (1) Beginning June 1, 2001, a refiner or importer may generate one 
credit for each gallon of motor vehicle diesel fuel meeting the sulfur 
content standard in Sec. 80.520(a)(1) that is used in vehicles with 
engines that are certified to meet the model year 2007 heavy duty engine 
PM standard under 40 CFR 86.007-11, or vehicles with retrofit 
technologies that achieve emission levels equivalent to the 2007 
NOX or PM emission standard verified as part of a retrofit 
program administered by EPA or a state. Such refiners and importers must 
comply with the requirements of paragraphs (b) and (d) of this section.
    (2)(i) Any refiner or importer planning to generate credits under 
this paragraph must provide notice of intent to generate early credits 
at least 120 calendar days prior to the date it begins generating 
credits under this paragraph by submitting such notice to Attn: Early 
Diesel Credits Notice, at the address in Sec. 80.595.

[[Page 914]]

    (ii) The notice shall include a detailed plan that demonstrates that 
the motor vehicle diesel fuel meeting the 15 ppm sulfur standard of 
Sec. 80.520(a)(1) for which credits are generated under this paragraph 
will be used in vehicles with engines that are certified to meet the 
model year 2007 heavy duty engine PM standard under 40 CFR 86.007-11 or 
in vehicles with retrofit technologies that achieve emission levels 
equivalent to the 2007 NOX or PM emission standard verified 
as part of a retrofit program administered by EPA or a state. The notice 
must include the refiner's or importer's detailed plan for ensuring that 
all motor vehicle diesel fuel that generates early credits under this 
paragraph will be segregated from all other motor vehicle diesel fuel 
not meeting the sulfur standard under Sec. 80.520(a)(1), from the 
refinery or import facility to its ultimate use in motor vehicles.
    (3) No credits may be generated under this paragraph (b) after May 
31, 2005.
    (4) A refiner or importer may generate credits under this paragraph 
and also generate credits under paragraph (a) of this section, and a 
small refiner, as defined under Sec. 80.550, may generate credits under 
this paragraph (b) and paragraph (e) of this section.
    (c) Generation of early credits from June 1, 2005 through May 31, 
2006. (1) Beginning June 1, 2005, a refiner or importer may generate one 
credit for each gallon of motor vehicle diesel fuel produced or imported 
that meets the 15 ppm sulfur standard in Sec. 80.520(a)(1) that is 
delivered into the distribution system. Such refiners and importers must 
comply with the requirements of this paragraph (c) and paragraph (d) of 
this section.
    (2)(i) Any refiner or importer planning to generate credits under 
this paragraph must provide notice of intent to generate early credits 
at least 30 calendar days prior to the date it begins generating credits 
under this paragraph (c).
    (ii) [Reserved]
    (3) No credits may be generated under this paragraph after May 31, 
2006.
    (4) A refiner or importer may generate credits under this paragraph 
(c) and also generate credits under paragraph (a) of this section, and a 
small refiner, as defined under Sec. 80.550, may generate credits under 
this paragraph (c) and paragraph (e) of this section.
    (5) Credit transfers for early credits. For early credits generated 
under Sec. 80.531(c), credits may be used in any of the CTAs 1 through 
5 that were generated in any of the CTAs 1 through 7 to achieve 
compliance with the volume limit in Sec. 80.503(a)(3);
    (d) Additional requirements for early credits. Early credits 
generated under paragraphs (b) and (c) of this section are subject to 
the following additional requirements:
    (1) The designation requirements of Sec. 80.598, and all 
recordkeeping and reporting requirements of Sec. Sec. 80.592 (except 
for paragraph (a)(3)), 80.593, 80.594, 80.600, and 80.601.
    (2) Credits generated under paragraphs (b) and (c) of this section 
shall be generated separately by CTA as defined in paragraph (a)(5) of 
this section and must be designated by CTA of generation, and by the 
refiner and refinery, or by importer and port of import, as applicable, 
except as provided under paragraph (c)(5) of this section.
    (3) Credits may not be generated for the same fuel by both a foreign 
refiner and an importer.
    (4) [Reserved]
    (5) In addition to the reporting requirements under paragraph (d)(1) 
of this section, the refiner or importer must submit a report to the 
Administrator no later than August 31, 2005 for the period from June 1, 
2004 through May 31, 2005, or August 31, 2006 for the period from June 
1, 2005 through May 31, 2006, demonstrating that all the motor vehicle 
diesel fuel produced or imported for which credits were generated met 
the applicable requirements of paragraph (b), (c), or (d)(4) of this 
section. If the Administrator finds that such credits did not in fact 
meet the requirements of paragraphs (b)(1) and (c)(1) of this section, 
as applicable, or if the Administrator determines that there is 
insufficient information to determine the validity of such credits, the 
Administrator may deny the credits submitted in whole or in part.
    (e) Credits generated by small refiners. (1) Notwithstanding the 
provisions of paragraph (a) of this section, a small refiner that is 
approved by the EPA as

[[Page 915]]

a small refiner under Sec. 80.551(g) may generate credits under Sec. 
80.552(b). Such a small refiner may generate one credit for each gallon 
of motor vehicle diesel fuel produced that is designated under Sec. 
80.598 as motor vehicle diesel fuel subject to the 15 ppm sulfur 
standard under Sec. 80.520(a)(1).
    (2)(i) Credits may be generated under this paragraph (e) and Sec. 
80.552(b) only during the compliance periods beginning June 1, 2006 and 
ending on May 31, 2010, however diesel fuel produced after December 31, 
2009 shall not generate credits. Credits shall be designated separately 
by refinery, separately by CTA of generation, and separately by annual 
compliance period. The annual compliance period for 2006 shall be June 
1, 2006 through June 30, 2007. The annual compliance period for 2010 
shall be July 1, 2009 through May 31, 2010.
    (ii) The small refiner must meet the requirements of paragraphs 
(d)(1), (d)(2) and (d)(3) of this section, and the recordkeeping and 
reporting requirements of Sec. Sec. 80.592, 80.593 and 80.594.
    (iii) In addition, a foreign refiner that is approved by the 
Administrator to generate credits under Sec. 80.552(b) shall comply 
with the requirements of Sec. 80.620.

[66 FR 5136, Jan. 18, 2001, as amended at 69 FR 39173, June 29, 2004; 70 
FR 40895, July 15, 2005; 70 FR 70510, Nov. 22, 2005; 71 FR 25717, May 1, 
2006]



Sec. 80.532  How are motor vehicle diesel fuel credits used and transferred?

    (a) Credit use stipulations. Motor vehicle diesel fuel credits 
generated under Sec. 80.531 may be used to meet the volume limit of 
Sec. 80.530(a)(3) provided that:
    (1) The motor vehicle diesel fuel credits were generated and 
reported according to the requirements of this subpart; and
    (2) The conditions of this section are met.
    (b) Use of credits generated under Sec. 80.531. Motor vehicle 
diesel fuel credits generated under Sec. 80.531 may be used by a 
refiner or by an importer to comply with Sec. 80.530 by applying one 
credit for every gallon of motor vehicle diesel fuel needed to meet 
compliance with the volume limit of Sec. 80.530(a)(3).
    (c) Credit banking. Motor vehicle diesel fuel credits generated may 
be banked for use or transfer in a later compliance period or may be 
transferred to another refiner or importer for use as provided in 
paragraph (d) of this section.
    (d) Credit transfers. (1) Motor vehicle diesel fuel credits obtained 
from another refiner or from another importer, including early motor 
vehicle diesel fuel credits and small refiner motor vehicle diesel fuel 
credits as described in Sec. 80.531(b) through (e), may be used to 
satisfy the volume limit of Sec. 80.530(a)(3) if all the following 
conditions are met:
    (i) The motor vehicle diesel fuel credits were generated in the same 
CTA as the CTA in which motor vehicle diesel fuel credits are used to 
achieve compliance, except as provided in Sec. 80.531(c)(5);
    (ii) The motor vehicle diesel fuel credits are used in compliance 
with the time period limitations for credit use in this subpart;
    (iii) Any credit transfer takes place no later than the August 31 
following the compliance period when the motor vehicle diesel fuel 
credits are used;
    (iv) No credit may be transferred more than twice, as follows: The 
first transfer by the refiner or importer who generated the credit may 
only be made to a refiner or importer who intends to use the credit; if 
the transferee cannot use the credit, it may make a second and final 
transfer only to a refiner or importer who intends to use the credit. In 
no case may a credit be transferred more than twice before being used or 
terminated;
    (v) The credit transferor must apply any motor vehicle diesel fuel 
credits necessary to meet the transferor's annual compliance 
requirements before transferring motor vehicle diesel fuel credits to 
any other refinery or importer;
    (vi) No motor vehicle diesel fuel credits may be transferred that 
would result in the transferor having a negative credit balance; and
    (vii) Each transferor must supply to the transferee records 
indicating the year the motor vehicle diesel fuel credits were 
generated, the identity of the refiner (and refinery) or importer who 
generated the motor vehicle diesel fuel credits, the CTA of credit 
generation, and the identity of the transferring entity, if it is not 
the same entity who

[[Page 916]]

generated the motor vehicle diesel fuel credits.
    (2) In the case of motor vehicle diesel fuel credits that have been 
calculated or created improperly, or are otherwise determined to be 
invalid, the following provisions apply:
    (i) Invalid motor vehicle diesel fuel credits cannot be used to 
achieve compliance with the transferee's volume requirements regardless 
of the transferee's good faith belief that the motor vehicle diesel fuel 
credits were valid.
    (ii) The refiner or importer who used the motor vehicle diesel fuel 
credits, and any transferor of the motor vehicle diesel fuel credits, 
must adjust their credit records, reports and compliance calculations as 
necessary to reflect the proper motor vehicle diesel fuel credits.
    (iii) Any properly created motor vehicle diesel fuel credits 
existing in the transferor's credit balance after correcting the credit 
balance, and after the transferor applies motor vehicle diesel fuel 
credits as needed to meet the compliance requirements at the end of the 
compliance period, must first be applied to correct the invalid 
transfers before the transferor trades or banks the motor vehicle diesel 
fuel credits.
    (e) Limitations on credit use. (1) Motor vehicle diesel fuel credits 
may not be used to achieve compliance with any requirements of this 
subpart other than the volume limit of Sec. 80.530(a)(3), unless 
specifically approved by the Administrator pursuant to a hardship relief 
petition under Sec. 80.560 or 80.561.
    (2) A refiner or importer possessing motor vehicle diesel fuel 
credits must use all motor vehicle diesel fuel credits in its possession 
prior to applying the credit deficit provisions of Sec. 80.530(a)(6).
    (3) No motor vehicle diesel fuel credits may be used to meet 
compliance with this subpart subsequent to the compliance period ending 
May 31, 2010.

[69 FR 39173, June 29, 2004, as amended at 71 FR 25717, May 1, 2006]



Sec. 80.533  How does a refiner or importer apply for a motor vehicle
or non-highway baseline for the generation of NRLM credits or the 

use of the NRLM small 
          refiner compliance options?

    (a) A refiner or importer wishing to generate credits under Sec. 
80.535 or use the small refiner provisions under Sec. 80.554 must 
submit an application to EPA that includes the information required 
under paragraph (c) of this section by the dates specified in paragraph 
(f) of this section. A refiner must apply for a motor vehicle baseline 
for each refinery in order to generate credits under Sec. 80.535 and 
apply for a non-highway baseline for each refinery to use the provisions 
of Sec. 80.554 (a), (b), or (d).
    (b) The baseline must be sent to the following address: U.S. EPA--
Attn: Nonroad Rule Diesel Fuel Baseline, Transportation and Regional 
Programs Division (6406J), 1200 Pennsylvania Avenue, NW., Washington, DC 
20460 (regular mail) or U.S. EPA, Attn: Nonroad Rule Diesel Fuel 
Baseline, Transportation and Regional Programs Division (6406J), 1310 L 
Street, NW., 6th floor, Washington, DC 20005 (express mail).
    (c) A baseline application must be submitted for each refinery or 
import facility and include the following information:
    (1) A listing of the names and addresses of all refineries or import 
facilities owned by the company for which the refiner or importer is 
applying for a motor vehicle or non-highway baseline.
    (2)(i) For purposes of a motor vehicle baseline volume for use in 
determining early credits per Sec. 80.535(a) and (b) and for purposes 
of a non-highway baseline volume used in determining compliance with the 
provisions of Sec. 80.554(a) or (d), the baseline volume produced 
during the three calendar years beginning January 1, 2003, 2004, and 
2005, as calculated under paragraph (e)(1) of this section.
    (ii) For purposes of a motor vehicle baseline volume for use in 
determining early credits per Sec. 80.535(c) and for purposes of a non-
highway baseline volume used in determining compliance with the 
provisions of Sec. 80.554(b), the baseline volumes produced during the

[[Page 917]]

three calendar years beginning January 1, 2006, 2007, and 2008, as 
calculated under paragraph (e)(2) of this section.
    (iii) For purposes of a total diesel baseline volume for use in 
determining compliance with the provisions of Sec. 80.554(d), the 
baseline volumes of motor vehicle diesel fuel produced during the 
calendar years beginning January 1, 1998 and 1999 (per Sec. Sec. 
80.595(a) and 80.596(a)); and the baseline volumes of non-highway diesel 
fuel produced during the three calendar years beginning January 1, 2003, 
2004, and 2005. This shall be calculated as stated under paragraph (f) 
of this section.
    (3) A letter signed by the president, chief operating officer of the 
company, or his/her delegate, stating that the information contained in 
the motor vehicle or non-highway baseline application is true to the 
best of his/her knowledge.
    (4) Name, address, phone number, facsimile number and e-mail address 
of a corporate contact person.
    (5) For each batch of diesel fuel produced or imported during each 
calendar year:
    (i) The date that production was completed or importation occurred 
for the batch and the batch designation or classification.
    (ii) The batch volume.
    (6) Other appropriate information as requested by EPA.
    (d) Calculation of the Motor vehicle Baseline, BMV. (1) 
Under paragraph (c)(2)(i) of this section, BMV equals the 
average annual volume of motor vehicle diesel fuel produced or imported 
from January 1, 2003 through December 31, 2005.
    (2) Under paragraph (c)(2)(ii) of this section, BMV 
equals the average annual volume of motor vehicle diesel fuel produced 
or imported during the period from January 1, 2006 through December 31, 
2008.
    (3) For purposes of this paragraph, fuel produced for export, jet 
fuel (kerosene), and fuel specifically produced to meet military 
specifications (such as JP-4, JP-8, and F-76), shall not be included in 
baseline calculations.
    (e) Calculation of the Non-highway Baseline, BNRLM. For 
purposes of this paragraph (e), BMV shall only include the 
average annual volume of 2D distillate fuel.
    (1) Under paragraphs (c)(2)(i) and (c)(2)(iii) of this section, 
BNRLM equals the average annual volume of all 2D 
distillate produced or imported from January 1, 2003 through December 
31, 2005, less BMV as determined in paragraph (d)(1) of this 
section.
    (2) Under paragraph (c)(2)(ii) of this section, BNRLM 
equals the average annual volume of MVNRLM produced or imported from 
January 1, 2006 through December 31, 2008, less BMV as 
determined in paragraph (d)(2) of this section.
    (3) For purposes of this paragraph (e), fuel produced for export, 
jet fuel, kerosene, and fuel specifically produced to meet military 
specification (such as JP-4, JP-8, and F-76), shall not be included in 
baseline calculations.
    (f) Calculation of the Total Diesel Baseline, BMVNRLM. 
BMVNRLM equals the sum of BMV (as calculated under 
Sec. 80.596) plus BNRLM (as calculated under paragraph 
(e)(1) of this section).
    (g)(1) Applications submitted under paragraphs (c)(2)(i) and 
(c)(2)(iii) of this section must be postmarked by February 28, 2006.
    (2) Applications submitted under paragraph (c)(2)(ii) of this 
section must be postmarked by February 28, 2009.
    (h)(1) For applications submitted under paragraphs (c)(2)(i) and 
(c)(2)(iii) of this section, EPA will notify refiners or importers by 
June 1, 2006 of approval of the baselines for each of the refiner's 
refineries or importer's import facilities or of any deficiencies in the 
refiner's or importer's application.
    (2) For applications submitted under paragraph (c)(2)(ii) of this 
section, EPA will notify refiners or importers by June 1, 2009 regarding 
approval of the baselines for each of the refiner's refineries or 
importer's import facilities of any deficiencies in the refiner's or 
importer's application.
    (i) If at any time the motor vehicle baseline or non-highway 
baseline submitted in accordance with the requirements of this section 
is determined to be incorrect, EPA will notify the refiner or importer 
of the corrected baseline and any compliance calculations

[[Page 918]]

made on the basis of that baseline will have to be adjusted 
retroactively.

[69 FR 39174, June 29, 2004, as amended at 70 FR 70510, Nov. 22, 2005; 
71 FR 25717, May 1, 2006]



Sec. 80.534  [Reserved]



Sec. 80.535  How are NRLM diesel fuel credits generated?

    (a) Generation of high sulfur NRLM credits from June 1, 2006 through 
May 31, 2007. (1) During the period June 1, 2006 through May 31, 2007, a 
refiner or importer may generate credits pursuant to the provisions of 
this section if all of the following conditions are met:
    (i) The refiner or importer notifies EPA of its intention to 
generate credits and the period during which it will generate credits. 
This notification must be received by EPA at least 30 calendar days 
prior to the date it begins generating credits under this section.
    (ii) Each batch or partial batch of NRLM diesel fuel for which 
credits are claimed shall be subject to all of the provisions of this 
subpart for NRLM diesel fuel as if it had been produced after June 1, 
2007 and before June 1, 2010.
    (iii) The number of high-sulfur NRLM credits (HSC) that are 
generated shall be a positive number.
    (2) The refiner or importer shall choose one of the following 
methods for calculating credits for each calculation period.
    (i) For fuel that is dyed under the provisions of Sec. 80.520, HSC 
equals the volume of fuel in gallons produced or imported during the 
period identified in paragraph (a)(1) of this section that is designated 
as NRLM diesel fuel and that is subject to and complies with the 
provisions of Sec. 80.510(a); or
    (ii) For dyed or undyed fuel that complies with the provisions of 
Sec. 80.598 for a calculation period of June 1, 2006 through May 31, 
2007, determine HSC as follows:

HSC = V510 + V520 - BMV

Where:

V510 = The total volume of NRLM diesel fuel produced or 
imported during the annual calculation period that complies with the 
standards of Sec. 80.510(a) or (b).
V520 = The total volume of motor vehicle diesel fuel produced 
or imported during the annual calculation period that complies with the 
standards of Sec. 80.520(a) or (c).
BMV = As calculated in Sec. 80.533(d)(1).

    (3) High-sulfur NRLM credits shall be generated and designated as 
follows:
    (i) Credits shall be generated separately for each refiner or 
importer.
    (ii) Credits may not be generated by both a foreign refiner and by 
an importer for the same motor vehicle diesel fuel.
    (iii) Credits shall not be generated under both Sec. 80.531 and 
this section for the same diesel fuel.
    (iv) Any credits generated by a foreign refiner shall be generated 
as provided in Sec. 80.620(c) and this section.
    (4) No credits may be generated under this paragraph (a) after May 
31, 2007.
    (5) Any fuel for which a refiner or importer wishes to generate 
credits must be designated as 500 ppm sulfur NRLM diesel fuel when 
delivered to the next entity. The refiner may not designate the fuel as 
500 ppm sulfur with the intent that it be mixed by the next entity with 
a batch of distillate with a higher sulfur level to create a fuel with a 
classification other than 500 ppm sulfur or the classification of the 
fuel it is mixed with (e.g., it cannot mix fuel designated as 500 ppm 
sulfur with fuel classified as high sulfur to produce a fuel classified 
as 2000 ppm sulfur to meet state or local sulfur limits).
    (6) The refiner or importer must submit a report to the 
Administrator no later than July 31, 2007. The report must demonstrate 
that all the NRLM diesel fuel produced or imported which generated 
credits met the applicable requirements of paragraphs (a)(1) through 
(a)(5) of this section. If the Administrator finds that such credits did 
not in fact meet the requirements of paragraphs (a)(1) through (a)(5) of 
this section, as applicable, or if the Administrator determines that 
there is insufficient information to determine the validity of such 
credits, the Administrator may deny the credits submitted in whole or in 
part.
    (b) Generation of high-sulfur NRLM credits by small refiners from 
June 1, 2006

[[Page 919]]

through May 31, 2010. (1) Notwithstanding the dates specified in 
paragraph (a) of this section, during the period from June 1, 2006 
through May 31, 2010, a refiner that is approved by the EPA as a small 
refiner under Sec. 80.551 may generate credits under paragraph (a) of 
this section during any compliance period as specified under Sec. 
80.599(a)(2) for diesel fuel produced or imported that is designated as 
NRLM diesel fuel and complies with the provisions of Sec. 80.510(a).
    (2) The small refiner must submit a report to the Administrator no 
later than August 31 after the end of each calculation period during 
which credits were generated. The report must demonstrate that all the 
NRLM diesel fuel produced or imported which generated credits met the 
applicable requirements of paragraphs (a)(1) through (a)(5) of this 
section. If the Administrator finds that such credits did not in fact 
meet the requirements of paragraphs (a)(1) through (a)(5) of this 
section, as applicable, or if the Administrator determines that there is 
insufficient information to determine the validity of such credits, the 
Administrator may deny the credits submitted in whole or in part.
    (3) In addition, a foreign refiner that is approved by the 
Administrator to generate credits under Sec. 80.554 shall comply with 
the requirements of Sec. 80.620.
    (c) Generation of 500 ppm sulfur NRLM credits from June 1, 2009 
through May 31, 2010. (1) During the period of June 1, 2009 through May 
31, 2010, a refiner or importer may generate credits pursuant to the 
provisions of this section if all of the following conditions are met:
    (i) The refiner or importer notifies EPA of its intention to 
generate credits and the period during which it will generate credits. 
This notification must be received by EPA at least 30 calendar days 
prior to the date it begins generating credits under this section.
    (ii) Each batch or partial batch of NRLM diesel fuel for which 
credits are claimed shall be subject to all of the provisions of this 
subpart for NRLM diesel fuel as if it had been produced after June 1, 
2010.
    (iii) The number of 500 ppm sulfur NRLM credits in gallons that are 
generated, C500, shall be a positive number calculated as 
follows:

C500 = V15-BMV

Where:

V15 = The total volume in gallons of 15 ppm diesel fuel 
produced or imported during the period stated under paragraph (c)(1)(i) 
of this section that is designated as either motor vehicle diesel fuel 
or NRLM diesel fuel.
BMV = As determined in Sec. 80.533(d)(2).

    (2) 500 ppm sulfur NRLM credits shall be generated and designated as 
follows:
    (i) Credits shall be generated separately for each refiner or 
importer.
    (ii) Credits may not be generated by both a foreign refiner and by 
an importer for the same diesel fuel.
    (iii) Credits shall not be generated under both Sec. 80.531 and 
this section for the same diesel fuel.
    (iv) Any credits generated by a foreign refiner shall be generated 
as provided in Sec. 80.620(c) and this section.
    (3) No credits may be generated under this paragraph (c) after May 
31, 2010.
    (4) The refiner or importer must submit a report to the 
Administrator no later than August 31, 2010. The report must demonstrate 
that all the 15 ppm sulfur NRLM diesel fuel produced or imported which 
generated credits met the applicable requirements of paragraphs (c)(1) 
through (c)(3) of this section. If the Administrator finds that such 
credits did not in fact meet the requirements of paragraphs (c)(1) 
through (c)(3) of this section, as applicable, or if the Administrator 
determines that there is insufficient information to determine the 
validity of such credits, the Administrator may deny the credits 
submitted in whole or in part.
    (d) Generation of 500 ppm sulfur NRLM credits by small refiners from 
June 1, 2009 through December 31, 2013. (1) Notwithstanding the dates 
specified in paragraph (c) of this section, during the period from June 
1, 2009 through December 31, 2013, a refiner that is approved by the EPA 
as a small refiner under Sec. 80.551 may generate credits under 
paragraph (c) of this section during any compliance period as specified 
under Sec. 80.599(a)(2) for diesel fuel produced or

[[Page 920]]

imported that is designated as NR or NRLM diesel fuel and complies with 
the provisions of Sec. 80.510(b) or (c).
    (2) The small refiner must submit a report to the Administrator no 
later than August 31 after the end of each calculation period during 
which credits were generated. The report must demonstrate that all the 
15 ppm sulfur NR or NRLM diesel fuel produced or imported for which 
credits were generated met the applicable requirements of paragraphs 
(c)(1) through (c)(3) of this section. If the Administrator finds that 
such credits did not in fact meet the requirements of paragraphs (c)(1) 
through (c)(3) of this section, as applicable, or if the Administrator 
determines that there is insufficient information to determine the 
validity of such credits, the Administrator may deny the credits 
submitted in whole or in part.
    (3) In addition, a foreign refiner that is approved by the 
Administrator to generate credits under Sec. 80.554 shall comply with 
the requirements of Sec. 80.620.

[69 FR 39175, June 29, 2004, as amended at 71 FR 25718, May 1, 2006]



Sec. 80.536  How are NRLM diesel fuel credits used and transferred?

    (a) Credit use stipulations. Credits generated under Sec. 80.535(a) 
and (b) may be used to meet the NRLM diesel fuel sulfur standard of 
Sec. 80.510(a), and credits generated under 80.535(c) and (d) may be 
used to meet the NR and NRLM diesel fuel sulfur standard of 80.510(b) 
and (c), respectively, provided that:
    (1) The credits were generated and reported according to the 
requirements of this subpart; and
    (2) The conditions of this section are met.
    (b) Using credits generated under Sec. 80.535. Credits generated 
under Sec. 80.535 may be used by a refiner or an importer to comply 
with the diesel fuel standards of Sec. 80.510 (a), (b), and (c) by 
applying one credit for every gallon of diesel fuel that does not comply 
with the applicable standard.
    (c) Credit banking. Credits generated may be banked for use at a 
later time or may be transferred to any other refiner or importer 
nationwide for use as provided in paragraph (d) of this section.
    (d) Credit transfers. (1) Credits generated under Sec. 80.535 that 
are obtained from another refiner or importer may be used to comply with 
the diesel fuel sulfur standards of Sec. 80.510(a), (b), and (c) if all 
the following conditions are met:
    (i) The credits are used in compliance with the time period 
limitations for credit use in this subpart;
    (ii) Any credit transfer is completed no later than August 31 
following the compliance period when the credits are used to comply with 
a standard under paragraph (a) of this section;
    (iii) No credit is transferred more than twice, as follows:
    (A) The first transfer by the refiner or importer who generated the 
credit may only be made to a refiner or importer that intends to use the 
credit; if the transferee cannot use the credit, it may make a second 
and final transfer only to a refiner or importer who intends to use the 
credit; and
    (B) In no case may a credit be transferred more than twice before it 
is used or it expires;
    (iv) The credit transferor applies any credits necessary to meet the 
transferor's annual compliance requirements before transferring credits 
to any other refinery or importer;
    (v) No credits are transferred that would result in the transferor 
having a negative credit balance; and
    (vi) Each transferor supplies to the transferee records indicating 
the year the credits were generated, the identity of the refiner (and 
refinery) or importer that generated the credits, and the identity of 
the transferor, if it is not the same party that generated the credits.
    (2) In the case of credits that have been calculated or created 
improperly, or are otherwise determined to be invalid, the following 
provisions apply:
    (i) Invalid credits cannot be used to achieve compliance with the 
transferee's volume requirements regardless of the transferee's good 
faith belief that the credits were valid.
    (ii) The refiner or importer that used the credits, and any 
transferor of the credits, must adjust its credit records,

[[Page 921]]

reports and compliance calculations as necessary to reflect the proper 
credits.
    (iii) Any properly created credits existing in the transferor's 
credit balance after correcting the credit balance, and after the 
transferor applies credits as needed to meet the compliance requirements 
at the end of the calendar year, must first be applied to correct the 
invalid transfers before the transferor trades or banks the credits.
    (e) General limitation on credit use. Credits may not be used to 
achieve compliance with any requirements of this subpart other than the 
standards of Sec. 80.510(a), (b), and (c), unless specifically approved 
by the Administrator pursuant to a hardship relief petition under Sec. 
80.560 or Sec. 80.561.
    (f) Use of high sulfur NRLM credits. (1) High sulfur NRLM credits 
generated under Sec. 80.535(a) or (b) may be used on a one-for-one 
basis to meet the NRLM diesel fuel sulfur standard of Sec. 80.510(a) 
from June 1, 2007 through May 31, 2010. For example, one credit 
generated by the production or importation of one gallon of NRLM diesel 
fuel subject to the NRLM diesel fuel sulfur standard of Sec. 80.510 (a) 
may be used to produce or import one gallon of NRLM diesel fuel that is 
exempt from the sulfur standard of Sec. 80.510(a) during the period 
from June 1, 2007 through May 31, 2010.
    (2) Any high sulfur NRLM diesel fuel produced after June 1, 2007 
through the use of credits must--
    (i) Be dyed red under the provisions of Sec. 80.520 at the point of 
production or importation;
    (ii) Be associated with a product transfer document that bears a 
unique product code as specified in Sec. 80.590; and
    (iii) Not be used to sell or deliver diesel fuel into areas 
specified in Sec. 80.510(g)(1) or (g)(2).
    (3) No high sulfur NRLM credits may be used subsequent to the 
compliance period ending May 31, 2010.
    (4) Any high sulfur NRLM credits not used under the provisions of 
paragraph (f)(1) of this section may be converted into 500 ppm sulfur 
NRLM credits on a one-for-one basis for use under paragraph (g) of this 
section.
    (g) Use of 500 ppm sulfur NRLM credits. (1) 500 ppm sulfur NRLM 
credits generated under Sec. 80.535(c) or (d) or converted from high 
sulfur NRLM credits under paragraph (f)(3) of this section may be used 
on a one-for-one basis to meet the NR or NRLM diesel fuel sulfur 
standards of Sec. 80.510(b) or (c) from June 1, 2010 through May 31, 
2014. For example, one credit generated by the production or importation 
of one gallon of NRLM diesel fuel subject to the NRLM diesel fuel sulfur 
standard of Sec. 80.510 (c) may be used to produce or import one gallon 
of NR diesel fuel that is subject to the sulfur standard of Sec. 
80.510(a) during the period from June 1, 2010 through May 31, 2014.
    (2) Any 500 ppm sulfur NR or NRLM diesel fuel produced or imported 
after June 1, 2010 through the use of these credits must--
    (i) Bear a unique product code as specified in Sec. 80.590; and
    (ii) Not be used to sell or deliver diesel fuel into areas specified 
in Sec. 80.510(g)(1) or (g)(2).
    (3) No 500 ppm sulfur NRLM credits may be used after May 31, 2014.

[69 FR 39176, June 29, 2004]



Sec. Sec. 80.537-80.539  [Reserved]

                     Geographic Phase-In Provisions



Sec. 80.540  How may a refiner be approved to produce gasoline
under the GPA gasoline sulfur standards in 2007 and 2008?

    (a) A refiner that has been approved by EPA under Sec. 80.217 for 
the geographic phase-in area (GPA) gasoline sulfur content standards 
under Sec. 80.216 may apply to EPA for approval to produce gasoline 
subject to the GPA standards in 2007 and 2008. Such application shall be 
submitted to EPA, at the address provided in Sec. 80.595(b), by 
December 31, 2001. A foreign refiner must apply under the provisions of 
paragraph (n) of this section.
    (b) The refiner must submit an application in accordance with the 
provisions of Sec. Sec. 80.595 and 80.596. The application must also 
include information, as provided in Sec. 80.594(c), demonstrating that 
starting no later than June 1, 2006, 95 percent of the motor vehicle 
diesel fuel produced by the refinery for United States use will comply 
with the 15 ppm sulfur standard under Sec. 80.520(a)(1), and that the 
volume of motor vehicle diesel fuel produced will

[[Page 922]]

comply with the volume requirements of paragraph (e) of this section.
    (c) The Administrator may approve a refiner's application to produce 
gasoline subject to the GPA gasoline sulfur content standards in 2007 
and 2008 if the provisions of paragraph (b) of this section are 
satisfied. In approving an application, the Administrator shall 
establish a motor vehicle diesel fuel volume baseline under Sec. Sec. 
80.595 and 80.596.
    (d) From June 1, 2006 through December 31, 2008, 95 percent of the 
motor vehicle diesel fuel produced by a refiner that has been approved 
under paragraph (c) of this section to produce gasoline subject to the 
GPA gasoline sulfur standards in 2007 and 2008, must be accurately 
designated under Sec. 80.598 as meeting the 15 ppm sulfur standard of 
Sec. 80.520(a)(1).
    (e) The total volume of motor vehicle diesel fuel produced for use 
in the United States and designated as meeting the 15 ppm sulfur 
standard under paragraph (d) of this section must meet or exceed 85 
percent of the baseline volume established under paragraph (c) of this 
section, except that for the first compliance period from June 1, 2006 
through June 30, 2007, the total volume must meet or exceed 92 percent 
of the baseline volume.
    (f) Compliance with the volume requirements in paragraph (e) of this 
section shall be determined each compliance period. Annual compliance 
periods shall be from July 1 through June 30. For the year 2006, the 
compliance period shall be from June 1, 2006 through June 30, 2007.
    (g) If a refiner fails to comply with the requirements of paragraph 
(d) of this section, or if the approval of the application, including 
the baseline, was based on false or inaccurate information, the approval 
to produce gasoline subject to the GPA gasoline sulfur content standards 
under this section during the years 2007 and 2008 shall be void ab 
initio, and gasoline produced for use in the GPA must meet the gasoline 
sulfur content standards of subpart H of this Part as if there had been 
no approval to produce gasoline subject to the GPA gasoline sulfur 
content standards in 2007 and 2008.
    (h) If for any compliance period a refiner fails to meet the volume 
requirements in paragraph (e) of this section, the approval to produce 
gasoline subject to the GPA gasoline sulfur content standards shall be 
void for that compliance period and for all succeeding compliance 
periods, and gasoline produced for use in the GPA must meet the gasoline 
sulfur standards under subpart H of this subpart as if there had been no 
approval to produce gasoline subject to the GPA gasoline sulfur content 
standards under this section in 2007 and 2008.
    (i) A refiner that is approved for production of gasoline subject to 
the GPA gasoline sulfur standards under this section in 2007 and 2008 
must meet all applicable recordkeeping and reporting requirements of 
Sec. Sec. 80.592, 80.593, and 80.594, and shall meet all the 
recordkeeping and reporting requirements under Sec. Sec. 80.219, 80.365 
and 80.370.
    (j) A refiner approved to produce gasoline subject to the GPA 
gasoline sulfur standards under this section in 2007 and 2008 may not 
generate or use credits under Sec. 80.531(a) or (e), or Sec. 80.532 
unless the approval is vacated as provided in paragraph (k) of this 
section.
    (k) A refiner may petition the Administrator to vacate approval to 
produce gasoline subject to the GPA gasoline sulfur content standards in 
2007 and 2008. EPA may grant such a petition, effective January 1 of the 
compliance period following EPA's receipt of such petition (or effective 
June 1, in 2006, if applicable). Upon such effective date and 
thereafter, gasoline produced for use in the GPA must meet the gasoline 
sulfur content standards under subpart H of this Part as if there had 
been no approval to produce gasoline subject to the GPA gasoline sulfur 
content standards under this section in 2007 and 2008. Upon such 
effective date, the refiner shall not be subject to the requirements of 
this section.
    (l) The provisions of this section shall apply separately for each 
refinery of a refiner.
    (m) If any refinery is approved for production of gasoline subject 
to GPA gasoline sulfur content standards under this section in 2007 and 
2008, the GPA downstream gasoline sulfur standard under Sec. 
80.220(a)(2) shall apply as follows:

[[Page 923]]

    (1) During the period of February 1, 2005 through January 31, 2009, 
the sulfur content of GPA gasoline at any downstream location other than 
at a retail outlet or wholesale purchaser-consumer facility shall not 
exceed 326 ppm.
    (2) During the period of March 1, 2005 through February 28, 2009, 
the sulfur content of GPA gasoline at any downstream location shall not 
exceed 326 ppm.
    (n) A foreign refiner may apply to the Administrator to produce 
gasoline that is subject to the gasoline sulfur standards for GPA 
gasoline under Sec. 80.216 for the compliance years 2007 and 2008. Such 
application must be submitted to the EPA, at the address in Sec. 
80.595(b), by December 31, 2001.
    (1) The Administrator may approve such interim GPA gasoline sulfur 
standards for the foreign refiner provided that the foreign refiner 
applies for a gasoline sulfur baseline under paragraph (n)(2) of this 
section and complies with:
    (i) The requirements of paragraphs (b) through (l) of this section;
    (ii) The requirements for the import of motor vehicle diesel fuel 
under Sec. 80.620; and
    (iii) All applicable gasoline requirements for refiners under 
subpart H of this Part, including the foreign refiner requirements under 
Sec. 80.410, the attest requirements of Sec. 80.415, the recordkeeping 
and reporting requirements of Sec. Sec. 80.365 and 80.370, the 
designation and product transfer document requirements of Sec. 80.219, 
the sampling and testing requirements of Sec. 80.330, and the sample 
retention requirements of Sec. 80.335.
    (2) The refiner must submit an application for a gasoline sulfur 
baseline under the provisions of Sec. Sec. 80.216(a), 80.295, and 
80.410(b).
    (3) After review of the foreign refiner's individual refinery 
gasoline sulfur baseline, its individual refinery motor vehicle diesel 
fuel baseline, and other information submitted with the application, the 
Administrator may approve such baselines and the application for GPA 
gasoline sulfur standards for 2007 and 2008.
    (o) An importer is not eligible for approval to import gasoline 
subject to the GPA standards in 2007 or 2008 under this section.

[66 FR 5136, Jan. 18, 2001, as amended at 69 FR 39177, June 29, 2004]



Sec. Sec. 80.541-80.549  [Reserved]

                    Small Refiner Hardship Provisions



Sec. 80.550  What is the definition of a motor vehicle diesel fuel
small refiner or a NRLM diesel fuel small refiner under this subpart?

    (a) A motor vehicle diesel fuel small refiner is defined as any 
person, as defined by 42 U.S.C. 7602(e), who--
    (1) Produces diesel fuel at a refinery by processing crude oil 
through refinery processing units; and
    (2) Employed an average of no more than 1,500 people, based on the 
average number of employees for all pay periods from January 1, 1999, to 
January 1, 2000; and
    (3) Had an average crude oil capacity less than or equal to 155,000 
barrels per calendar day (bpcd) for 1999; or
    (4) Has been approved by EPA as a small refiner under Sec. 80.235 
and continues to meet the criteria of a small refiner under Sec. 
80.225.
    (b) A NRLM diesel fuel small refiner is defined as any person, as 
defined by 42 U.S.C. 7602(e), who--
    (1) Produces diesel fuel at a refinery by processing crude oil 
through refinery processing units;
    (2) Employed an average of no more than 1,500 people, based on the 
average number of employees for all pay periods from January 1, 2002, to 
January 1, 2003; and
    (3) Had an average crude oil capacity less than or equal to 155,000 
barrels per calendar day (bpcd) for 2002.
    (c) Determine the number of employees and crude oil capacity under 
paragraphs (a) or (b) of this section, as follows:
    (1) The refiner shall include the employees and crude oil capacity 
of any subsidiary companies, any parent company and subsidiaries of the 
parent company in which the parent has 50 percent or greater ownership, 
and any joint venture partners.
    (2) For any refiner owned by a governmental entity, the number of 
employees and total crude oil capacity as

[[Page 924]]

specified in paragraph (a) of this section shall include all employees 
and crude oil production of the government to which the governmental 
entity is a part.
    (3) Any refiner owned and controlled by an Alaska Regional or 
Village Corporation organized pursuant to the Alaska Native Claims 
Settlement Act (43 U.S.C. 1601) is not considered an affiliate of such 
entity, or with other concerns owned by such entity solely because of 
their common ownership.
    (d)(1) Notwithstanding the provisions of paragraph (a) of this 
section, a refiner that acquires or reactivates a refinery that was shut 
down or non-operational between January 1, 1999, and January 1, 2000, 
may apply for motor vehicle diesel fuel small refiner status in 
accordance with the provisions of Sec. 80.551(c)(1)(ii).
    (2) Notwithstanding the provisions of paragraph (b) of this section, 
a refiner that acquires or reactivates a refinery that was shutdown or 
non-operational between January 1, 2002, and January 1, 2003, may apply 
for NRLM diesel fuel small refiner status in accordance with the 
provisions of Sec. 80.551(c)(2)(ii).
    (e) The following are ineligible for the small refiner provisions:
    (1)(i) For motor vehicle diesel fuel, refiners with refineries built 
or started up after January 1, 2000.
    (ii) For NRLM diesel fuel, refiners with refineries built or started 
up after January 1, 2003.
    (2)(i) For motor vehicle diesel fuel, persons who exceed the 
employee or crude oil capacity criteria under this section on January 1, 
2000, but who meet these criteria after that date, regardless of whether 
the reduction in employees or crude oil capacity is due to operational 
changes at the refinery or a company sale or reorganization.
    (ii) For NRLM diesel fuel, persons who exceed the employee or crude 
oil capacity criteria under this section on January 1, 2003, but who 
meet these criteria after that date, regardless of whether the reduction 
in employees or crude oil capacity is due to operational changes at the 
refinery or a company sale or reorganization.
    (3) Importers.
    (4) Refiners who produce motor vehicle diesel fuel or NRLM diesel 
fuel other than by processing crude oil through refinery processing 
units.
    (f)(1)(i) Refiners who qualify as motor vehicle diesel fuel small 
refiners under this section and subsequently cease production of diesel 
fuel from processing crude oil through refinery processing units, or 
employ more than 1,500 people or exceed the 155,000 bpcd crude oil 
capacity limit after January 1, 2004 as a result of merger with or 
acquisition of or by another entity, are disqualified as small refiners, 
except as provided for under paragraph (f)(4) of this section. If 
disqualification occurs, the refiner shall notify EPA in writing no 
later than 20 days following this disqualifying event.
    (ii) Except as provided under paragraph (f)(3) of this section, any 
refiner whose status changes under this paragraph shall meet the 
applicable standards of Sec. 80.520 within a period of up to 30 months 
from the disqualifying event for any of its refineries that were 
previously subject to the small refiner standards of Sec. 80.552, but 
no later than the May 31, 2010.
    (2)(i) Refiners who qualify as NRLM diesel fuel small refiners under 
this section and subsequently cease production of diesel fuel from crude 
oil, or employ more than 1,500 people or exceed the 155,000 bpcd crude 
oil capacity limit after January 1, 2004 as a result of merger with or 
acquisition of or by another entity, are disqualified as small refiners, 
except as provided for under paragraph (f)(4) of this section. If 
disqualification occurs, the refiner shall notify EPA in writing no 
later than 20 days following this disqualifying event.
    (ii) Except as provided under paragraph (f)(3) of this section, any 
refiner whose status changes under this paragraph shall meet the 
applicable standards of Sec. 80.510 within a period of up to 30 months 
of the disqualifying event for any of its refineries that were 
previously subject to the small refiner standards of Sec. 80.552, but 
no later than the dates specified in Sec. 80.554(a) or (b), as 
applicable.
    (3) A refiner may apply to EPA for up to an additional six months to 
comply with the standards of Sec. 80.510 or Sec. 80.520 if more than 
30 months would be required for the necessary engineering,

[[Page 925]]

permitting, construction, and start-up work to be completed. Such 
applications must include detailed technical information supporting the 
need for additional time. EPA will base a decision to approve additional 
time on information provided by the refiner and on other relevant 
information. In no case will EPA extend the compliance date beyond May 
31, 2010 for a motor vehicle diesel fuel small refiner or beyond the 
dates specified in Sec. 80.554(a) or (b), as applicable, for a NRLM 
diesel fuel small refiner.
    (4) Disqualification under paragraphs (f)(1) or (f)(2) of this 
section shall not apply in the case of a merger between two previously 
approved small refiners.
    (5) During the period of time up to 30 months provided under 
paragraph (f)(1)(ii) of this section, and any extension provided under 
paragraph (f)(3) of this section, the refiner may not generate motor 
vehicle diesel fuel sulfur credits under Sec. 80.531(e). During the 
period of time up to 30 months provided under paragraph (f)(2)(ii) of 
this section, and any extension provided under paragraph (f)(3) of this 
section, the refiner may not generate NRLM diesel fuel sulfur credits 
under Sec. 80.535(b) or (d).
    (g) Notwithstanding the criteria in paragraph (a) of this section, 
any small refiner that has been approved by EPA as a small refiner under 
Sec. 80.235 and meets the criteria of paragraph (a)(1) of this section, 
will be considered a small refiner under this section as well, for as 
long as they are a small refiner under Sec. 80.225. The provisions of 
paragraph (f) of this section apply to any such refiner.

[66 FR 5136, Jan. 18, 2001, as amended at 69 FR 39177, June 29, 2004; 70 
FR 40896, July 15, 2005]



Sec. 80.551  How does a refiner obtain approval as a small refiner
under this subpart?

    (a)(1)(i) Applications for motor vehicle diesel fuel small refiner 
status must be submitted to EPA by December 31, 2001.
    (ii) Applications for NRLM diesel fuel small refiner status must be 
submitted to EPA by December 31, 2004.
    (2)(i) In the case of a refiner who acquires or reactivates a 
refinery that was shutdown or non-operational between January 1, 1999, 
and January 1, 2000, the application for motor vehicle diesel fuel small 
refiner status must be submitted to EPA by June 1, 2003.
    (ii) In the case of a refiner who acquires or reactivates a refinery 
that was shutdown or non-operational between January 1, 2002, and 
January 1, 2003, the application for NRLM diesel fuel small refiner 
status must be submitted to EPA by June 1, 2006.
    (b) Applications for small refiner status must be sent via certified 
mail with return receipt or express mail with return receipt to: U.S. 
EPA--Attn: Diesel Small Refiner Status (6406J), 1200 Pennsylvania 
Avenue, NW., Washington, DC 20460 (certified mail/return receipt) or 
Attn: Diesel Small Refiner Status, Transportation and Regional Programs 
Division, 1310 L Street, NW., 6th floor, Washington, DC 20005 (express 
mail/return receipt).
    (c) The small refiner status application must contain the following 
information for the company seeking small refiner status, plus any 
subsidiary companies, any parent company and subsidiaries of the parent 
company in which the parent has 50 percent or greater ownership, and any 
joint venture partners:
    (1) For motor vehicle diesel fuel small refiners--
    (i) A listing of the name and address of each location where any 
employee worked during the 12 months preceding January 1, 2000; the 
average number of employees at each location based upon the number of 
employees for each pay period for the 12 months preceding January 1, 
2000; and the type of business activities carried out at each location; 
or
    (ii) In the case of a refiner who acquires or reactivates a refinery 
that was shutdown or non-operational between January 1, 1999, and 
January 1, 2000, a listing of the name and address of each location 
where any employee of the refiner worked since the refiner acquired or 
reactivated the refinery; the average number of employees at any such 
acquired or reactivated refinery during each calendar year since the 
refiner acquired or reactivated the refinery; and the type of business 
activities carried out at each location.

[[Page 926]]

    (2) For NRLM diesel fuel small refiners--
    (i) A listing of the name and address of each location where any 
employee worked during the 12 months preceding January 1, 2003; the 
average number of employees at each location based upon the number of 
employees for each pay period for the 12 months preceding January 1, 
2003; and the type of business activities carried out at each location; 
or
    (ii) In the case of a refiner who acquires or reactivates a refinery 
that was shutdown or non-operational between January 1, 2002, and 
January 1, 2003, a listing of the name and address of each location 
where any employee of the refiner worked since the refiner acquired or 
reactivated the refinery; the average number of employees at any such 
acquired or reactivated refinery during each calendar year since the 
refiner acquired or reactivated the refinery; and the type of business 
activities carried out at each location.
    (3) The total corporate crude oil capacity of each refinery as 
reported to the Energy Information Administration (EIA) of the U.S. 
Department of Energy (DOE) for the most recent 12 months of operation. 
The information submitted to EIA is presumed to be correct. In cases 
where a company disagrees with this information, the company may 
petition EPA with appropriate data to correct the record when the 
company submits its application for small refiner status. EPA may accept 
such alternate data at its discretion.
    (4) For motor vehicle diesel fuel, an indication of whether the 
refiner, for each refinery, is applying for--
    (i) The ability to produce motor vehicle diesel fuel subject to the 
500 ppm sulfur standard under Sec. 80.520(c) or generate credits under 
Sec. 80.531, pursuant to the provisions of Sec. 80.552(a) or (b); or
    (ii) An extension of the duration of its small refiner gasoline 
sulfur standard under Sec. 80.553, pursuant to the provisions of Sec. 
80.552(c).
    (5) For NRLM diesel fuel, an indication of whether the refiner, for 
each refinery, is applying for--
    (i) The ability to delay compliance under Sec. 80.554(a) or (b), or 
to generate NRLM diesel sulfur credits under Sec. 80.535(b) or (d), 
pursuant to the provisions of Sec. 80.554(c); or
    (ii) An adjustment to its small refiner gasoline sulfur standards 
under Sec. 80.240(a), pursuant to the provisions of Sec. 80.554(d).
    (6) A letter signed by the president, chief operating or chief 
executive officer of the company, or his/her designee, stating that the 
information contained in the application is true to the best of his/her 
knowledge.
    (7) Name, address, phone number, facsimile number and e-mail address 
(if available) of a corporate contact person.
    (d) For joint ventures, the total number of employees includes the 
combined employee count of all corporate entities in the venture.
    (e) For government-owned refiners, the total employee count includes 
all government employees.
    (f) Approval of small refiner status for refiners who apply under 
Sec. 80.550(d) will be based on all information submitted under 
paragraph (c)(ii) of this section, except as provided in Sec. 
80.550(e).
    (g) EPA will notify a refiner of approval or disapproval of small 
refiner status by letter. If disapproved, the refiner must comply with 
the sulfur standards in Sec. 80.510 or 80.520, as appropriate, except 
as otherwise provided in this subpart.
    (h) If EPA finds that a refiner provided false or inaccurate 
information on its application for small refiner status, upon notice 
from EPA the refiner's small refiner status will be void ab initio.
    (i) Upon notification to EPA, an approved small refiner may withdraw 
its status as a small refiner. Effective on January 1 of the year 
following such notification, the small refiner will become subject to 
the sulfur standards in Sec. 80.510 or 80.520, as appropriate, unless 
one of the other hardship provisions of this subpart apply.

[69 FR 39178, June 29, 2004, as amended at 70 FR 40896, July 15, 2005]

    Editorial Note: At 71 FR 25718, May 1, 2006, Sec. 80.551 was 
amended by adding paragraph (f); however, the paragraph already exists 
in this section. For the convenience of the user, the added text is set 
forth as follows:

[[Page 927]]



Sec. 80.551  How does a refiner obtain approval as a small refiner 
          under this subpart?

                                * * * * *

    (f) Approval of small refiner status for refiners who apply under 
Sec. 80.550(e) will be based on all information submitted under 
paragraph (c) of this section, except as provided in Sec. 80.550(e).

                                * * * * *



Sec. 80.552  What compliance options are available to motor vehicle 
diesel fuel small refiners?

    (a) A refiner that has been approved by EPA as a motor vehicle 
diesel fuel small refiner under Sec. 80.551(g) may produce motor 
vehicle diesel fuel subject to the 500 ppm sulfur standard pursuant to 
the provisions of Sec. 80.530, except that the volume limits of Sec. 
80.530(a)(3) shall only apply to that volume of diesel fuel that is 
produced or imported during an annual compliance period that exceeds 105 
percent of the baseline volume established under Sec. 80.595 
(V500). The annual compliance period shall be from July 1 
through June 30. For the year 2006, the compliance period shall be from 
June 1, 2006 through June 30, 2007, and the volume limits shall only 
apply to that volume V500 that exceeds 113 percent of the 
baseline volume.
    (b) A refiner that has been approved by EPA as a motor vehicle 
diesel fuel small refiner under Sec. 80.551(g) may generate motor 
vehicle diesel fuel credits pursuant to the provisions of Sec. 80.531, 
except that for purposes of Sec. 80.531(a), the term ``Credit'' shall 
equal V15, without further adjustment.
    (c) A refiner that has been approved by EPA as a motor vehicle 
diesel fuel small refiner under Sec. 80.551(g) may apply for an 
extension of the duration of its small refiner gasoline sulfur standards 
pursuant to Sec. 80.553.
    (d) A refiner that produces motor vehicle diesel fuel under the 
provisions of paragraph (a) of this section or generates credits under 
the provisions of paragraph (b) of this section may not receive an 
extension of its small refiner gasoline sulfur standard under the 
provisions of paragraph (c) of this section. A refiner that receives an 
extension of its small refiner gasoline sulfur standard under the 
provisions of paragraph (c) of this section may not produce motor 
vehicle diesel fuel under the provisions of paragraph (a) of this 
section and may not generate credits under the provisions of paragraph 
(b) of this section.
    (e) The provisions of this section shall apply separately for each 
refinery owned or operated by a motor vehicle diesel fuel small refiner.

[66 FR 5136, Jan. 18, 2001, as amended at 69 FR 39179, June 29, 2004]



Sec. 80.553  Under what conditions may the small refiner gasoline 
sulfur standards be extended for a small refiner of motor 

vehicle diesel fuel?

    (a) A refiner that has been approved by EPA for small refiner 
gasoline sulfur standards under Sec. 80.240 may apply, under Sec. 
80.551, for an extension of the duration of its small refiner gasoline 
sulfur standards through the calendar year 2010 annual averaging period.
    (b) As part of its application, the refiner must submit an 
application for a motor vehicle diesel fuel baseline in accordance with 
the provisions of Sec. Sec. 80.595 and 80.596. The application must 
also include information, as provided in Sec. 80.594, demonstrating 
that starting no later than June 1, 2006, 95 percent of the motor 
vehicle diesel fuel produced by the refiner will comply with the 15 ppm 
sulfur content standard under Sec. 80.520(a)(1), and that the volume of 
motor vehicle diesel fuel produced will comply with the volume 
requirements of paragraph (e) of this section.
    (c) The Administrator may approve an application for extension of 
the small refiner gasoline sulfur standards if the provisions of 
paragraph (b) of this section and Sec. Sec. 80.595 and 80.596 are 
satisfied. In approving an application for extension, the Administrator 
shall establish a motor vehicle diesel fuel volume baseline under 
Sec. Sec. 80.595 and 80.596.
    (d) Beginning June 1, 2006, and continuing through December 31, 
2010, 95 percent of the motor vehicle diesel fuel produced by a refiner 
that has received an extension of its small refiner gasoline sulfur 
standards under this section must be accurately designated under Sec. 
80.598 as meeting the 15 ppm sulfur content standard under Sec. 
80.520(a)(1).

[[Page 928]]

    (e) The total volume of motor vehicle diesel fuel produced for use 
in the United States and designated as meeting the 15 ppm sulfur content 
standard under paragraph (d) of this section must meet or exceed 85 
percent of the baseline volume established under paragraph (c) of this 
section, except that for the first compliance period from June 1, 2006 
through June 30, 2007, the total volume must meet or exceed 92 percent 
of the baseline volume.
    (f) Compliance with the volume requirements in paragraph (e) of this 
section shall be determined each compliance period. Annual compliance 
periods shall be from July 1 through June 30. For the year 2006, the 
compliance period shall be from June 1, 2006 through June 30, 2007 and 
for the year 2009 the compliance period shall be from July 1, 2009 
through May 31, 2010.
    (g) If a refiner fails to comply with the requirements of paragraph 
(d) of this section, or if approval of the application, including the 
baseline, was based on false or inaccurate information, the extension of 
the applicable small refiner gasoline sulfur standards under this 
section shall be void ab initio, and all gasoline produced by the 
refinery must meet the gasoline sulfur standards under subpart H of this 
Part as if there had been no extension of the small refiner gasoline 
sulfur standards.
    (h) If for any compliance period a refiner fails to meet the volume 
requirements in paragraph (e) of this section, the extension of the 
small refiner gasoline sulfur standards shall be void for that 
compliance period and for all succeeding compliance periods and all 
gasoline produced by the refinery must meet the gasoline sulfur 
standards under subpart H of this part as if there had been no extension 
of the small refiner gasoline sulfur standards under this section for 
such compliance periods.
    (i) A refiner that is approved for an extension of the interim small 
refiner gasoline sulfur standards under this section must meet all 
applicable recordkeeping and reporting requirements of Sec. Sec. 
80.592, 80.593, and 80.594, and shall meet all the recordkeeping and 
reporting requirements under Sec. Sec. 80.210, 80.365 and 80.370. Any 
foreign refiner shall meet all additional requirements under Sec. Sec. 
80.620 and 80.410.
    (j) A refiner approved for the small refiner gasoline sulfur 
standards extension under this section may not generate or use credits 
under Sec. 80.531(a) or (e), or Sec. 80.532.
    (k) A refiner may petition the Administrator to vacate an extension 
of the small refiner gasoline sulfur content standards. EPA may grant 
such a petition, effective July 1 of the compliance period following 
receipt of such petition (or effective June 1, 2006, if applicable). 
Upon such effective date, all gasoline produced by the refiner must meet 
the gasoline sulfur content standards under subpart H of this part as if 
there had been no extension of the small refiner gasoline sulfur content 
standards under this section. Upon such effective date, the refiner 
shall not be subject to the requirements of this section.
    (l) The provisions of this section shall apply separately for each 
refinery of a refiner.

[66 FR 5136, Jan. 18, 2001, as amended at 69 FR 39179, June 29, 2004; 71 
FR 25718, May 1, 2006]



Sec. 80.554  What compliance options are available to NRLM diesel
fuel small refiners?

    (a) Option 1: A refiner that has been approved by EPA as a NRLM 
diesel fuel small refiner under Sec. 80.551(g) may produce NRLM diesel 
fuel from crude oil from June 1, 2007 through May 31, 2010, that is 
exempt from the standards under Sec. 80.510(a), but only for a refinery 
located outside the areas specified under Sec. 80.510(g)(1).
    (1) The volume of NRLM diesel fuel that is exempt from Sec. 
80.510(a) must be less than or equal to 105 percent of BNRLM 
as defined under Sec. 80.533, less any volume of heating oil produced.
    (2) Any volume of NRLM diesel fuel in excess of the volume allowed 
under (a)(1) of this section will be subject to the 500 ppm sulfur 
standard under Sec. 80.510(a).
    (3) High-sulfur NRLM produced under this paragraph must--
    (i) Be dyed red pursuant to the provisions of Sec. 80.520 at the 
point of production or importation;

[[Page 929]]

    (ii) Be associated with a product transfer document that bears a 
unique product code as specified under Sec. 80.590; and
    (iii) Not be delivered into areas specified under Sec. 
80.510(g)(1).
    (4) From June 1, 2007 through May 31, 2010, a refiner that has been 
approved by EPA as a NRLM diesel fuel small refiner under Sec. 
80.551(g) may produce at a refinery located in 80.510(g)(2) NRLM diesel 
fuel that is exempt from the standards under Sec. 80.510(a) only if the 
refiner first obtains approval from the Administrator for a compliance 
plan. The compliance plan must detail how the refiner will segregate any 
fuel produced that does not meet the standards under Sec. 80.510(a) 
from the refinery through to the ultimate consumer from fuel having any 
other designations and from fuel produced by any other refiner. The 
compliance plan must also identify all ultimate consumers to whom the 
refiner supplies the fuel that does not meet the standards under Sec. 
80.510(a).
    (b) Option 2: A refiner that has been approved by EPA as a NRLM 
diesel fuel small refiner under Sec. 80.551(g) may produce NR diesel 
fuel from crude oil from June 1, 2010, through May 31, 2014, and NRLM 
diesel fuel from crude oil from June 1, 2012 through May 31, 2014 that 
is subject to the standards under Sec. 80.510(a), but only for a 
refinery located outside the areas specified under Sec. 80.510(g)(1).
    (1) The volume of NR diesel fuel that may be subject to the 500 ppm 
sulfur standard from June 1, 2010 through June 30, 2011 must be less 
than or equal to 113 percent of BNRLM, and from July 1, 2011 
through May 31, 2012 must be less than or equal to 96 percent of 
BNRLM, as defined under Sec. 80.533, less any volume of 
locomotive and marine diesel fuel produced.
    (2) The volume of NRLM diesel fuel that may be subject to the 500 
ppm sulfur standard from June 1, 2012 through June 30, 2013 must be less 
than or equal to 113 percent of BNRLM, and from July 1, 2013 
through May 31, 2014 must be less than or equal to 96 percent of 
BNRLM, as defined under Sec. 80.533.
    (3) NRLM diesel fuel produced in excess of the volume allowed under 
paragraph (b)(1) of this section will be subject to the standards under 
Sec. 80.510(b) and (c).
    (4) 500 ppm sulfur NRLM diesel fuel produced under this paragraph 
must--
    (i) Bear a unique product code as specified under Sec. 80.590; and
    (ii) Not be sold or delivered into areas specified under Sec. 
80.510(g)(1).
    (5) From June 1, 2010 through May 31, 2012, for NR diesel fuel, and 
from June 1, 2012 through May 31, 2014 for NRLM diesel fuel, a refiner 
that has been approved by EPA as a NRLM diesel fuel small refiner under 
Sec. 80.551(g) may produce, at a refinery located in Alaska, NR and 
NRLM diesel fuel, as applicable, from crude oil that is subject to the 
standards of Sec. 80.510(a), only if the refiner first obtains approval 
from the Administrator for a compliance plan. The compliance plan must 
detail how the refiner will segregate any fuel produced subject to the 
standards under Sec. 80.510(a) from the refinery through to the 
ultimate consumer from fuel having any other designations and from fuel 
produced by any other refiner. The compliance plan must also identify 
all ultimate consumers to whom the refiner supplies the fuel that does 
not meet the standards under Sec. 80.510(a).
    (c) Option 3: A refiner that has been approved by EPA as a NRLM 
diesel fuel small refiner under Sec. 80.551(g) may generate diesel fuel 
credits under the provisions of Sec. 80.535(b) and (d), except as 
provided in paragraph (d)(1) of this section.
    (d) Option 4: (1) In lieu of Options 1, 2, and 3 of this section, a 
refiner that has been approved by EPA as a NRLM diesel fuel small 
refiner under Sec. 80.551(g) may choose to adjust its small refiner 
gasoline sulfur standards, subject to the following conditions:
    (i) From June 1, 2006 until the expiration of the refiner's small 
refiner gasoline sulfur standards (through December 31, 2007 or 2010) 95 
percent of the total MVNRLM diesel fuel produced by the refiner must be 
accurately designated under Sec. 80.598(a) as meeting the 15 ppm sulfur 
standard of Sec. 80.510(b).
    (ii) The refiner must produce MVNRLM diesel fuel each year or 
partial year under paragraph (d)(1)(i) of this section at a volume that 
is equal to or greater than 85 percent of

[[Page 930]]

BMVNRLM, as defined in Sec. 80.533, calculated on an annual 
basis.
    (2)(i) For a refiner meeting the conditions of paragraph (d)(1) of 
this section, beginning January 1, 2004, the applicable small refiner's 
annual average and per-gallon cap gasoline sulfur standards will be the 
standards of Sec. 80.240(a) increased by a factor of 1.20 for the 
duration of the refiner's small refiner gasoline sulfur standards under 
Sec. 80.240(a) or Sec. 80.553 (i.e., through calendar years 2007 or 
2010).
    (ii) In no case may the per-gallon cap exceed 450 ppm.
    (3)(i) If the refiner fails to produce the necessary volume of 15 
ppm sulfur MVNRLM diesel fuel by June 1, 2006 and every year thereafter 
through the deadlines specified under paragraph (d)(1)(i) of this 
section, the refiner must report this in its annual report under Sec. 
80.604, and the adjustment of gasoline sulfur standards under paragraph 
(d)(2)(i) of this section will be considered void as of January 1, 2004.
    (ii) If such a refiner had produced gasoline above its interim 
gasoline sulfur standard of Sec. 80.240(a) prior to June 1, 2006, such 
fuel will not be considered in violation of the small refiner standards 
under Sec. 80.240(a), provided the refiner obtains and uses a quantity 
of gasoline sulfur credits equal to the volume of gasoline exceeding the 
small refiner standards multiplied by the number of parts per million by 
which the gasoline exceeded the small refiner standards.
    (e) Multiple refineries. The provisions of this section shall apply 
separately for each refinery owned or operated by a NRLM diesel fuel 
small refiner.
    (f) Other provisions. From June 1, 2007 through May 31, 2010, a 
refiner who is an approved motor vehicle diesel fuel small refiner under 
Sec. 80.550(a) but does not qualify as a NRLM diesel fuel small refiner 
under Sec. 80.550(b) may produce NRLM diesel fuel that is exempt from 
the per-gallon sulfur standard and the cetane or aromatics standard of 
Sec. 80.510(a). This exemption does not apply to diesel fuel sold or 
intended for sale in the areas listed in Sec. 80.510(g)(1) or (g)(2). 
From June 1, 2010 through May 31, 2012, NR and LM diesel fuel produced 
by such refiners is subject to the standards under Sec. 80.510(b) and 
beginning June 1, 2012, all NRLM diesel fuel is subject to the standards 
under Sec. 80.510(c).

[69 FR 39179, June 29, 2004, as amended at 71 FR 25718, May 1, 2006]



Sec. 80.555  What provisions are available to a large refiner that
acquires a small refiner or one or more of its refineries?

    (a) In the case of a refiner without approved small refiner status 
who acquires a refinery from a refiner with approved status as a motor 
vehicle diesel fuel small refiner or a NRLM diesel fuel small refiner 
under Sec. 80.551(g), the applicable small refiner provisions of 
Sec. Sec. 80.552 and 80.554 may apply to the acquired refinery for a 
period of up to 30 months from the date of acquisition of the refinery. 
In no case shall this period extend beyond May 31, 2010 for a refinery 
acquired from a motor vehicle diesel fuel small refiner or beyond the 
dates specified in Sec. 80.554(a) or (b), as applicable, for a refinery 
acquired from a NRLM diesel fuel small refiner.
    (b) A refiner may apply to EPA for up to an additional six months to 
comply with the standards of Sec. 80.510 or 80.520 for the acquired 
refinery if more than 30 months would be required for the necessary 
engineering, permitting, construction, and start-up work to be 
completed. Such applications must include detailed technical information 
supporting the need for additional time. EPA will base a decision to 
approve additional time on information provided by the refiner and on 
other relevant information. In no case will EPA extend the compliance 
date beyond May 31, 2010 for a refinery acquired from a motor vehicle 
diesel fuel small refiner or beyond the dates specified in Sec. 
80.554(a) or (b), as applicable, for a refinery acquired from a NRLM 
diesel fuel small refiner.
    (c) Refiners who acquire a refinery from a refiner with approved 
status as a motor vehicle diesel fuel small refiner or a NRLM diesel 
fuel small refiner under Sec. 80.551(g), shall notify EPA in writing no 
later than 20 days following the acquisition.

[69 FR 39180, June 29, 2004]

[[Page 931]]



Sec. Sec. 80.556-80.559  [Reserved]

                        Other Hardship Provisions



Sec. 80.560  How can a refiner seek temporary relief from the 
requirements of this subpart in case of extreme

hardship circumstances?

    (a) EPA may, at its discretion, grant a refiner of crude oil that 
processes crude oil through refinery processing units, for one or more 
of its refineries, temporary relief from some or all of the provisions 
of this subpart. Such relief shall be no less stringent than the small 
refiner compliance options specified in Sec. 80.552 for motor vehicle 
diesel fuel and Sec. 80.554 for NRLM diesel fuel. EPA may grant such 
relief provided that the refiner demonstrates that--
    (1) Unusual circumstances exist that impose extreme hardship and 
significantly affect the refiner's ability to comply by the applicable 
date; and
    (2) It has made best efforts to comply with the requirements of this 
subpart.
    (b)(1) For motor vehicle diesel fuel, applications must be submitted 
to EPA by June 1, 2002 to the following address: U.S. EPA--Attn: Diesel 
Hardship, Transportation and Regional Programs Division (6406J), 1200 
Pennsylvania Avenue, NW., Washington, DC 20460 (certified mail/return 
receipt) or Attn: Diesel Hardship, Transportation and Regional Programs 
Division, 1310 L Street, NW., 6th floor, Washington, DC 20005 (express 
mail/return receipt). EPA reserves the right to deny applications for 
appropriate reasons, including unacceptable environmental impact. 
Approval to distribute motor vehicle diesel fuel not subject to the 15 
ppm sulfur standard may be granted for such time period as EPA 
determines is appropriate, but shall not extend beyond May 31, 2010.
    (2) For NRLM diesel fuel, applications must be submitted to EPA by 
June 1, 2005 to the following address: U.S. EPA--Attn: Diesel Hardship, 
Transportation and Regional Programs Division (6406J), 1200 Pennsylvania 
Avenue, NW., Washington, DC 20460 (certified mail/return receipt) or 
Attn: Diesel Hardship, Transportation and Regional Programs Division, 
1310 L Street, NW., 6th floor, Washington, DC 20005 (express mail/return 
receipt). EPA reserves the right to deny applications for appropriate 
reasons, including unacceptable environmental impact. Approval to 
distribute NRLM diesel fuel not subject to the 500 ppm sulfur standard 
may be granted for such time period as EPA determines is appropriate, 
but shall not extend beyond May 31, 2010 for NR diesel fuel and May 31, 
2012 for NRLM diesel fuel. Approval to distribute NRLM diesel fuel not 
subject to the 15 ppm sulfur standard may be granted for such time 
period as EPA determines is appropriate, but shall not extend beyond May 
31, 2014.
    (c) Applications must include a plan demonstrating how the refiner 
will comply with the requirements of this subpart as expeditiously as 
possible. The plan shall include a showing that contracts are or will be 
in place for engineering and construction of desulfurization equipment a 
plan for applying for and obtaining any permits necessary for 
construction or operation, projected timeline for beginning and 
completing construction, and for beginning actual operation of such 
equipment, and a description of plans to obtain necessary capital, and a 
detailed estimate of when the requirements of this subpart will be met.
    (d) Applicants must provide, at a minimum, the following 
information:
    (1) Detailed description of efforts to obtain capital for refinery 
investments and efforts made to obtain credits for compliance under 
Sec. 80.531 for motor vehicle diesel fuel or Sec. Sec. 80.535 through 
80.536 for NRLM diesel fuel;
    (2) Bond rating of entity that owns the refinery (in the case of 
joint ventures, include the bond rating of the joint venture entity and 
the bond ratings of all partners; in the case of corporations, include 
the bond ratings of any parent or subsidiary corporations); and
    (3) Estimated capital investment needed to comply with the 
requirements of this subpart by the applicable date.
    (e) In addition to the application requirements of paragraph (b) 
through (d) of this section, a refiner's application for temporary 
relief under this paragraph (e) must also include a compliance plan. 
Such compliance plan shall demonstrate how the refiner will engage in a 
quality assurance testing

[[Page 932]]

program, where appropriate, to ensure that the following conditions are 
met:
    (1)(i) Its motor vehicle diesel fuel subject solely to the sulfur 
standards under Sec. 80.520(c) has not caused motor vehicle diesel fuel 
subject to the 15 ppm sulfur standard Sec. 80.520(a)(1) to fail to 
comply with that standard; or
    (ii) Its NRLM diesel fuel subject solely to the 500 ppm sulfur 
standard under Sec. 80.510(a) has not caused NRLM diesel fuel subject 
to the 15 ppm sulfur standard under Sec. 80.510(b) or (c) to fail to 
comply with that standard.
    (2) The quality assurance program must at least include periodic 
sampling and testing at the party's own facilities and at downstream 
facilities in the refiner's or importer's diesel fuel distribution 
system, to determine compliance with the applicable sulfur standards for 
both categories of motor vehicle diesel fuel; examination at the party's 
own facilities and at applicable downstream facilities, of product 
transfer documents to confirm appropriate transfers and deliveries of 
both products; and inspection of retailer and wholesale purchaser-
consumer pump stands for the presence of the labels and warning signs 
required under this section. Any violations that are discovered shall be 
reported to EPA within 48 hours of discovery.
    (f) Applications under this section must be accompanied by:
    (1) A letter signed by the president, chief operating or chief 
executive officer of the company, or his/her designee, stating that the 
information contained in the application is true to the best of his/her 
knowledge.
    (2) The name, address, phone number, facsimile number and e-mail 
address of a corporate contact person.
    (g) Applicants must also provide any other relevant information 
requested by EPA.
    (h) Refiners who are granted a hardship relief standard for any 
refinery and importers of fuel subject to temporary foreign refiner 
relief standards, must comply with the requirements of Sec. 80.561(f).
    (i) EPA may impose any reasonable conditions on waivers under this 
section, including limitations on the refinery's volume of motor vehicle 
diesel fuel and NRLM diesel fuel subject to temporary refiner relief 
standards.
    (j) The provisions of this section are available only to refineries 
that produce diesel fuel from crude.
    (k) The individual refinery sulfur standard and the compliance plan 
will be approved or disapproved by the Administrator, and approval will 
be effective when the refiner receives an approval letter from EPA. 
Unless approved, the refiner or, where applicable, the importer must 
comply with the motor vehicle diesel fuel standard under Sec. 
80.520(a)(1) by the appropriate compliance date specified in Sec. 
80.500 or the NRLM diesel fuel standards and compliance dates under 
Sec. 80.510(a), (b), and (c) as applicable.
    (l) If EPA finds that a refiner provided false or inaccurate 
information on its application for hardship relief, EPA's approval of 
the refiners application will be void ab initio.

[66 FR 5136, Jan. 18, 2001, as amended at 69 FR 39181, June 29, 2004]



Sec. 80.561  How can a refiner or importer seek temporary relief 
from the requirements of this subpart in case of extreme unforseen

circumstances?

    In appropriate extreme, unusual, and unforseen circumstances (for 
example, natural disaster or refinery fire) which are clearly outside 
the control of the refiner or importer and which could not have been 
avoided by the exercise of prudence, diligence, and due care, EPA may 
permit a refiner or importer, for a brief period, to distribute motor 
vehicle diesel fuel or NRLM diesel fuel which does not meet the 
requirements of this subpart if:
    (a) It is in the public interest to do so (e.g., distribution of the 
nonconforming diesel fuel is necessary to meet projected shortfalls 
which cannot otherwise be compensated for);
    (b) The refiner or importer exercised prudent planning and was not 
able to avoid the violation and has taken all reasonable steps to 
minimize the extent of the nonconformity;
    (c) The refiner or importer can show how the requirements for motor 
vehicle diesel fuel or NRLM diesel fuel will be expeditiously achieved;

[[Page 933]]

    (d) The refiner or importer agrees to make up any air quality 
detriment associated with the nonconforming motor vehicle diesel fuel or 
NRLM diesel fuel, where practicable;
    (e) The refiner or importer pays to the U.S. Treasury an amount 
equal to the economic benefit of the nonconformity minus the amount 
expended pursuant to paragraph (d) of this section, in making up the air 
quality detriment; and
    (f)(1) In the case of motor vehicle diesel fuel distributed under 
this section that does not meet the 15 ppm sulfur standard under Sec. 
80.520(a)(1), such diesel fuel shall not be distributed for use in model 
year 2007 or later motor vehicles, and must meet all the requirements 
and prohibitions of this subpart applicable to diesel fuel meeting the 
sulfur standard under Sec. 80.520(c), or to diesel fuel that is not 
motor vehicle diesel fuel, as applicable.
    (2) In the case of NRLM diesel fuel distributed under this section 
from June 1, 2007 through May 31, 2010 that does not meet the 500 ppm 
sulfur standard under Sec. 80.510(a), such diesel fuel must meet the 
requirements and prohibitions applicable to high sulfur NRLM credit fuel 
under Sec. 80.536(f)(1)(i) and (ii).
    (3) In the case of NR diesel fuel distributed under this section 
after May 31, 2010 that does not meet the 15 ppm sulfur standard under 
Sec. 80.510(b), such diesel fuel shall not be distributed for use in 
model year 2011 or later nonroad engines, and must meet all the 
requirements and prohibitions of this subpart applicable to diesel fuel 
meeting the sulfur standard under Sec. 80.510(a) for NRLM diesel fuel.
    (4) In the case of NRLM diesel fuel distributed under this section 
after May 31, 2012 that does not meet the 15 ppm sulfur standard under 
Sec. 80.510(c), such diesel fuel shall not be distributed for use in 
model year 2011 or later nonroad engines, and must meet all the 
requirements and prohibitions of this subpart applicable to diesel fuel 
meeting the sulfur standard under Sec. 80.510(a) for NRLM diesel fuel.

[66 FR 5136, Jan. 18, 2001, as amended at 69 FR 39181, June 29, 2004]



Sec. Sec. 80.562-80.569  [Reserved]

                          Labeling Requirements



Sec. 80.570  What labeling requirements apply to retailers and
wholesale purchaser-consumers of diesel fuel beginning June 1, 2006?

    (a) From June 1, 2006 through May 31, 2010, any retailer or 
wholesale purchaser-consumer who sells, dispenses, or offers for sale or 
dispensing, motor vehicle diesel fuel subject to the 15 ppm sulfur 
standard of Sec. 80.520(a)(1), must affix the following conspicuous and 
legible label, in block letters of no less than 24-point bold type, and 
printed in a color contrasting with the background, to each pump stand:

      ULTRA-LOW SULFUR HIGHWAY DIESEL FUEL (15 ppm Sulfur Maximum)

    Required for use in all model year 2007 and later highway diesel 
vehicles and engines.
    Recommended for use in all diesel vehicles and engines.

    (b) From June 1, 2006 through September 30, 2010, any retailer or 
wholesale purchaser-consumer who sells, dispenses, or offers for sale or 
dispensing, motor vehicle diesel fuel subject to the 500 ppm sulfur 
standard of Sec. 80.520(c), must prominently and conspicuously display 
in the immediate area of each pump stand from which motor vehicle fuel 
subject to the 500 ppm sulfur standard is offered for sale or 
dispensing, the following legible label, in block letters of no less 
than 24-point bold type, printed in a color contrasting with the 
background:

         LOW SULFUR HIGHWAY DIESEL FUEL (500 ppm Sulfur Maximum)

                                 WARNING

    Federal law prohibits use in model year 2007 and later highway 
vehicles and engines.
    Its use may damage these vehicles and engines.

    (c) From June 1, 2006 through May 31, 2007, any retailer or 
wholesale purchaser-consumer who sells, dispenses, or offers for sale or 
dispensing, diesel fuel for non-motor vehicle equipment that does not 
meet the standards for motor vehicle diesel fuel, must affix the 
following conspicuous and legible label, in block letters of no less 
than 24-point bold type, and printed in a

[[Page 934]]

color contrasting with the background, to each pump stand:

           NON-HIGHWAY DIESEL FUEL (May Exceed 500 ppm Sulfur)

                                 WARNING

    Federal law prohibits use in highway vehicles or engines.
    Its use may damage these vehicles and engines.

    (d) The labels required by paragraphs (a) through (c) of this 
section must be placed on the vertical surface of each pump housing and 
on each side that has gallon and price meters. The labels shall be on 
the upper two-thirds of the pump, in a location where they are clearly 
visible.
    (e) Alternative labels to those specified in paragraphs (a) through 
(c) of this section may be used as approved by EPA.

[69 FR 39182, June 29, 2004, as amended at 71 FR 25718, May 1, 2006]



Sec. 80.571  What labeling requirements apply to retailers and 
wholesale purchaser-consumers of NRLM diesel fuel or heating 

oil beginning June 1, 2007?

    Any retailer or wholesale purchaser-consumer who sells, dispenses, 
or offers for sale or dispensing nonroad, locomotive or marine (NRLM) 
diesel fuel (including nonroad (NR) and locomotive or marine (LM)), or 
heating oil, must prominently and conspicuously display in the immediate 
area of each pump stand from which non-highway diesel fuel is offered 
for sale or dispensing, one of the following legible labels, as 
applicable, in block letters of no less than 24-point bold type, printed 
in a color contrasting with the background:
    (a) From June 1, 2007 through May 31, 2010, for pumps dispensing 
NRLM diesel fuel meeting the 15 ppm sulfur standard of Sec. 80.510(b):

    ULTRA-LOW SULFUR NON-HIGHWAY DIESEL FUEL (15 ppm Sulfur Maximum)

    Required for use in all model year 2011 and newer nonroad diesel 
engines.
    Recommended for use in all nonroad, locomotive, and marine diesel 
engines.

                                 WARNING

    Federal Law prohibits use in highway vehicles or engines.

    (b) From June 1, 2007 through May 31, 2010, for pumps dispensing 
NRLM diesel fuel meeting the 500 ppm sulfur standard of Sec. 80.510(a):

       LOW SULFUR NON-HIGHWAY DIESEL FUEL (500 ppm Sulfur Maximum)

                                 WARNING

    Federal Law prohibits use in highway vehicles or engines.

    (c) From June 1, 2007 through September 30, 2010, for pumps 
dispensing NRLM diesel fuel not meeting, or not offered as meeting, the 
500 ppm sulfur standard of Sec. 80.510(a) or the 15 ppm sulfur standard 
of Sec. 80.510(b):

     HIGH SULFUR NON-HIGHWAY DIESEL FUEL (May Exceed 500 ppm Sulfur)

                                 WARNING

    Federal law prohibits use in highway vehicles or engines.
    May damage nonroad diesel engines required to use low-sulfur or 
ultra-low sulfur diesel fuel.

    (d) From June 1, 2007 and beyond, for pumps dispensing non-motor 
vehicle diesel fuel for use other than in nonroad, locomotive or marine 
engines, such as for use in stationary diesel engines or as heating oil:

                 HEATING OIL (May Exceed 500 ppm Sulfur)

                                 WARNING

    Federal law prohibits use in highway vehicles or engines, or in 
nonroad, locomotive, or marine diesel engines.
    Its use may damage these diesel engines.

    (e) The labels required by paragraphs (a) through (d) of this 
section must be placed on the vertical surface of each pump housing and 
on each side that has gallon and price meters. The labels shall be on 
the upper two-thirds of the pump, in a location where they are clearly 
visible.
    (f) Alternative labels to those specified in paragraphs (a) through 
(d) of this section may be used as approved by EPA.

[69 FR 39182, June 29, 2004, as amended at 71 FR 25718, May 1, 2006]

[[Page 935]]



Sec. 80.572  What labeling requirements apply to retailers and 
wholesale purchaser-consumers of NR and NRLM diesel fuel and 

heating oil beginning June 1, 2010?

    Any retailer or wholesale purchaser-consumer who sells, dispenses, 
or offers for sale or dispensing nonroad, locomotive or marine (NRLM) 
diesel fuel (including nonroad (NR) and locomotive or marine (LM)), or 
heating oil, must prominently and conspicuously display in the immediate 
area of each pump stand from which non-highway diesel fuel is offered 
for sale or dispensing, one of the following legible labels, as 
applicable, in block letters of no less than 24-point bold type, printed 
in a color contrasting with the background:
    (a) From June 1, 2010 and beyond, any retailer or wholesale 
purchaser-consumer who sells, dispenses, or offers for sale or 
dispensing, motor vehicle diesel fuel subject to the 15 ppm sulfur 
standard of Sec. 80.520(a)(1), must affix the following conspicuous and 
legible label, in block letters of no less than 24-point bold type, and 
printed in a color contrasting with the background, to each pump stand:

      ULTRA-LOW SULFUR HIGHWAY DIESEL FUEL (15 ppm Sulfur Maximum)

    Required for use in all highway diesel vehicles and engines.
    Recommended for use in all diesel vehicles and engines.

    (b) From June 1, 2010 through May 31, 2012, for pumps dispensing NR 
diesel fuel subject to the 15 ppm sulfur standard of Sec. 80.510(b):

    ULTRA-LOW SULFUR NON-HIGHWAY DIESEL FUEL (15 ppm Sulfur Maximum)

    Required for use in all model year 2011 and later nonroad diesel 
engines.
    Recommended for use in all other non-highway diesel engines.

                                 WARNING

    Federal law prohibits use in highway vehicles or engines.

    (c) From June 1, 2010 through September 30, 2014, for pumps 
dispensing NRLM diesel fuel subject to the 500 ppm sulfur standard of 
Sec. 80.510(a):

       LOW SULFUR NON-HIGHWAY DIESEL FUEL (500 ppm Sulfur Maximum)

                                 WARNING

    Federal law prohibits use in all model year 2011 and newer nonroad 
engines.
    May damage model year 2011 and newer nonroad engines.
    Federal law prohibits use in highway vehicles or engines.

    (d) From June 1, 2010 through September 30, 2012, for pumps 
dispensing LM diesel fuel subject to the 500 ppm sulfur standard of 
Sec. 80.510(a):

  LOW SULFUR LOCOMOTIVE AND MARINE DIESEL FUEL (500 ppm Sulfur Maximum)

                                 WARNING

    Federal law prohibits use in nonroad engines or in highway vehicles 
or engines.

    (e) The labels required by paragraphs (a) through (d) of this 
section must be placed on the vertical surface of each pump housing and 
on each side that has gallon and price meters. The labels shall be on 
the upper two-thirds of the pump, in a location where they are clearly 
visible.
    (f) Alternative labels to those specified in paragraphs (a) through 
(d) of this section may be used as approved by EPA.

[69 FR 39183, June 29, 2004, as amended at 71 FR 25718, May 1, 2006]



Sec. 80.573  What labeling requirements apply to retailers and 
wholesale purchaser-consumers of NRLM diesel fuel and heating

oil beginning June 1, 2012?

    Any retailer or wholesale purchaser-consumer who sells, dispenses, 
or offers for sale or dispensing nonroad, locomotive or marine (NRLM) 
diesel fuel (including nonroad (NR) and locomotive or marine (LM)), or 
heating oil, must prominently and conspicuously display in the immediate 
area of each pump stand from which non-highway diesel fuel is offered 
for sale or dispensing, one of the following legible labels, as 
applicable, in block letters of no less than 24-point bold type, printed 
in a color contrasting with the background:
    (a) From June 1, 2012 through May 31, 2014, for pumps dispensing 
NRLM diesel fuel subject to the 15 ppm sulfur standard of Sec. 
80.510(c):

[[Page 936]]

    ULTRA-LOW SULFUR NON-HIGHWAY DIESEL FUEL (15 ppm Sulfur Maximum)

    Required for use in all model year 2011 and later nonroad diesel 
engines.
    Recommended for use in all other non-highway diesel engines.

                                 WARNING

    Federal law prohibits use in highway vehicles or engines.

    (b) The labels required by paragraph (a) of this section must be 
placed on the vertical surface of each pump housing and on each side 
that has gallon and price meters. The labels shall be on the upper two-
thirds of the pump, in a location where they are clearly visible.
    (c) Alternative labels to those specified in paragraph (a) of this 
section may be used as approved by EPA.

[69 FR 39183, June 29, 2004, as amended at 71 FR 25718, May 1, 2006]



Sec. 80.574  What labeling requirements apply to retailers and 
wholesale purchaser-consumers of NRLM diesel fuel, or heating

oil beginning June 1, 2014?

    Any retailer or wholesale purchaser-consumer who sells, dispenses, 
or offers for sale or dispensing nonroad, locomotive or marine (NRLM) 
diesel fuel (including nonroad (NR) and locomotive or marine (LM)), or 
heating oil, must prominently and conspicuously display in the immediate 
area of each pump stand from which non-highway diesel fuel is offered 
for sale or dispensing, one of the following legible labels, as 
applicable, in block letters of no less than 24-point bold type, printed 
in a color contrasting with the background:
    (a) From June 1, 2014 and beyond, for pumps dispensing NRLM diesel 
fuel subject to the 15 ppm sulfur standard of Sec. 80.510(c):

    ULTRA-LOW SULFUR NON-HIGHWAY DIESEL FUEL (15 ppm Sulfur Maximum)

    Required for use in all nonroad diesel engines.
    Recommended for use in all locomotive and marine diesel engines.

                                 WARNING

    Federal law prohibits use in highway vehicles or engines.

    (b) From June 1, 2014 and beyond, for pumps dispensing LM diesel 
fuel subject to the 500 ppm sulfur standard of Sec. 80.510(a):

  LOW SULFUR LOCOMOTIVE OR MARINE DIESEL FUEL (500 ppm Sulfur Maximum)

                                 WARNING

    Federal law prohibits use in nonroad engines or in highway vehicles 
or engines.
    Its use may damage these engines.

    (c) The labels required by paragraphs (a) and (b) of this section 
must be placed on the vertical surface of each pump housing and on each 
side that has gallon and price meters. The labels shall be on the upper 
two-thirds of the pump, in a location where they are clearly visible.
    (d) Alternative labels to those specified in paragraphs (a) and (b) 
of this section may be used as approved by EPA.

[69 FR 39183, June 29, 2004, as amended at 71 FR 25719, May 1, 2006]



Sec. Sec. 80.575-80.579  [Reserved]

                          Sampling and Testing



Sec. 80.580  What are the sampling and testing methods for sulfur?

    The sulfur content of diesel fuel and diesel fuel additives is to be 
determined in accordance with this section.
    (a) Sampling method. The applicable sampling methodology is provided 
in Sec. 80.330(b).
    (b) Test method for sulfur. (1) [Reserved]
    (2) For motor vehicle diesel fuel and diesel fuel additives subject 
to the 500 ppm sulfur standard of Sec. 80.520(c), and NRLM diesel fuel 
subject to the 500 ppm sulfur standard of Sec. 80.510(a)(1), sulfur 
content may be determined using ASTM D 2622-03.
    (3) Beginning August 30, 2004, for motor vehicle diesel fuel and 
diesel fuel additives subject to the 15 ppm sulfur standard of Sec. 
80.520(a)(1), sulfur content may be determined using any test method 
approved under Sec. 80.585.
    (4) Beginning August 30, 2004, for NRLM diesel fuel and diesel fuel 
additives subject to the 15 ppm standard of Sec. 80.510(b), sulfur 
content may be determined using any test method approved under Sec. 
80.585.
    (c) Alternative test methods for sulfur. (1) [Reserved]

[[Page 937]]

    (2) Options for testing sulfur content of 500 ppm diesel fuel. (i) 
For motor vehicle diesel fuel and diesel fuel additives subject to the 
500 ppm sulfur standard of Sec. 80.520(c), and for NRLM diesel fuel 
subject to the 500 ppm sulfur standard of Sec. 80.510(a), sulfur 
content may be determined using ASTM D 4294-03, ASTM D 5453-03a, or ASTM 
D 6920-03, provided that the refiner or importer test result is 
correlated with the appropriate method specified in paragraph (b)(2) of 
this section; or
    (ii) For motor vehicle diesel fuel and diesel fuel additives subject 
to the 500 ppm sulfur standard of Sec. 80.520(c), and for NRLM diesel 
fuel subject to the 500 ppm sulfur standard of Sec. 80.510(a), sulfur 
content may be determined using any test method approved under Sec. 
80.585.
    (d) Adjustment factor for downstream test results. (1) Except as 
specified in paragraph (d)(1)(i) of this section, an adjustment factor 
of negative two ppm sulfur shall be applied to the test results from any 
testing of motor vehicle diesel fuel or NRLM diesel fuel downstream of 
the refinery or import facility, to account for test variability, but 
only for testing of motor vehicle diesel fuel or NRLM diesel fuel 
identified as subject to the 15 ppm sulfur standard of Sec. 80.510(b) 
or Sec. 80.520(a)(1).
    (i) Prior to October 15, 2008 an adjustment factor of negative three 
ppm sulfur shall be applied to the test results, to account for test 
variability, but only for testing of motor vehicle diesel fuel or NRLM 
diesel fuel identified as subject to the 15 ppm sulfur standard of Sec. 
80.510(b) or Sec. 80.520(a)(1).
    (ii) [Reserved]
    (2) In addition to the adjustment factor provided in paragraph 
(d)(1)(i) of this section, prior to September 1, 2006, an adjustment 
factor of negative 7 ppm shall be applied to the test results from any 
testing of motor vehicle diesel fuel downstream of the refinery or 
import facility, to facilitate the transition to ULSD fuel, but only for 
testing of motor vehicle diesel fuel identified as subject to the 15 ppm 
sulfur standard of Sec. 80.520(a)(1).
    (3) In addition to the adjustment factor provided in paragraph 
(d)(1)(i) of this section, prior to October 15, 2006, an adjustment 
factor of negative 7 ppm shall be applied to the test results from any 
testing of motor vehicle diesel fuel at any retail outlet or wholesale 
purchaser-consumer facility, to facilitate the transition to ULSD fuel, 
but only for testing of motor vehicle diesel fuel identified as subject 
to the 15 ppm sulfur standard of Sec. 80.520(a)(1).
    (e) Materials incorporated by reference. The Director of the Federal 
Register approved the incorporation by reference of the documents listed 
in this section as prescribed in 5 U.S.C. 552(a) and 1 CFR part 51. 
Anyone may inspect copies at the U.S. EPA, Air and Radiation Docket and 
Information Center, 1301 Constitution Ave., NW., Room B102, EPA West 
Building, 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.
    (1) ASTM material. Anyone may purchase copies of these materials 
from the American Society for Testing and Materials, 100 Barr Harbor 
Dr., West Conshohocken, PA 19428.
    (i) ASTM D 2622-03, Standard Test Method for Sulfur in Petroleum 
Products by Wavelength Dispersive X-ray Fluorescence Spectrometry.
    (ii) ASTM D 3120-03a, Standard Test Method for Trace Quantities of 
Sulfur in Light Liquid Petroleum Hydrocarbons by Oxidative 
Microcoulometry.
    (iii) ASTM D 4294-03, Standard Test Method for Sulfur in Petroleum 
and Petroleum Products by Energy-Dispersive X-ray Fluorescence 
Spectrometry.
    (iv) ASTM D 5453-03a, Standard Test Method for Determination of 
Total Sulfur in Light Hydrocarbons, Motor Fuels and Motor Oils by 
Ultraviolet Fluorescence.
    (v) D 6920-03, Standard Test Method for Total Sulfur in Naphthas, 
Distillates, Reformulated Gasolines, Diesels, Biodiesels, and Motor 
Fuels by Oxidative Combustion and Electrochemical Detection.
    (2) [Reserved]

[69 FR 39184, June 29, 2004, as amended at 70 FR 40896, July 15, 2005; 
70 FR 70510, Nov. 22, 2005; 71 FR 16500, Apr. 3, 2006; 71 FR 25719, May 
1, 2006]

[[Page 938]]



Sec. 80.581  What are the batch testing and sample retention 
requirements for motor vehicle and NRLM diesel fuel?

    (a) Beginning on June 1, 2006 or earlier pursuant to Sec. 80.531 
for motor vehicle diesel fuel, and beginning June 1, 2010 or earlier 
pursuant to Sec. 80.535 for NRLM diesel fuel, each refiner and importer 
shall collect a representative sample from each batch of motor vehicle 
or NRLM diesel fuel produced or imported and subject to the 15 ppm 
sulfur content standard. Batch, for the purposes of this section, means 
batch as defined under Sec. 80.2 but without the reference to transfer 
of custody from one facility to another facility.
    (b) Except as provided in paragraph (c) of this section, the refiner 
or importer shall test each sample collected pursuant to paragraph (a) 
of this section to determine its sulfur content for compliance with the 
requirements of this subpart prior to the diesel fuel leaving the 
refinery or import facility, using an appropriate sampling and testing 
method as specified in Sec. 80.580.
    (c)(1) Any refiner who produces motor vehicle or NRLM diesel fuel 
using computer-controlled in-line blending equipment, including the use 
of an on-line analyzer test method that is approved under the provisions 
of Sec. 80.580, and who, subsequent to the production of the diesel 
fuel batch tests a composited sample of the batch under the provisions 
of Sec. 80.580 for purposes of designation and reporting, is exempt 
from the requirement of paragraph (b) of this section to obtain the test 
result required under this section prior to the diesel fuel leaving the 
refinery, provided that the refiner obtains approval from EPA. The 
requirement of this paragraph (c)(1) that the in-line blending equipment 
must include an on-line analyzer test method that is approved under the 
provisions of Sec. 80.580 is effective beginning June 1, 2006.
    (2) To obtain an exemption from paragraph (b) of this section, the 
refiner must submit to EPA all the information required under Sec. 
80.65(f)(4)(i)(A). A letter signed by the president, chief operating or 
chief executive officer of the company, or his/her designee, stating 
that the information contained in the submission is true to the best of 
his/her belief must accompany any submission under this paragraph 
(c)(2).
    (3) Refiners who seek an exemption under paragraph (c)(2) of this 
section must comply with any request by EPA for additional information 
or any other requirements that EPA includes as part of the exemption.
    (4) Within 60 days of EPA's receipt of a submission under paragraph 
(c)(2) of this section, EPA will notify the refiner if the exemption is 
not approved or of any deficiencies in the refiner's submission, or if 
any additional information is required or other requirements are 
included in the exemption pursuant to paragraph (c)(3) of this section. 
In the absence of such notification from EPA, the effective date of an 
exemption under this paragraph (c) is 60 days from EPA's receipt of the 
refiner's submission.
    (5) EPA reserves the right to modify the requirements of an 
exemption under this paragraph (c), in whole or in part, at any time, if 
EPA determines that the refiner's operation does not effectively or 
adequately control, monitor or document the sulfur content of the 
refinery's diesel fuel production, or if EPA determines that any other 
circumstances exist which merit modification of the requirements of an 
exemption, such as advancements in the state of the art for in-line 
blending measurement which allow for additional control or more accurate 
monitoring or documentation of sulfur content. If EPA finds that a 
refiner provided false or inaccurate information in any submission 
required for an exemption under this section, upon notification from 
EPA, the refiner's exemption will be void ab initio.
    (d) All test results under this section shall be retained for five 
years and must be provided to EPA upon request.
    (e) Samples collected under this section must be retained for at 
least 30 days and provided to EPA upon request.

[69 FR 39184, June 29, 2004, as amended at 71 FR 25719, May 1, 2006]



Sec. 80.582  What are the sampling and testing methods for
the fuel marker?

    For heating oil and NRLM diesel fuel subject to the fuel marker 
requirement

[[Page 939]]

in Sec. 80.510(d), (e), or (f), the identification of the presence and 
concentration of the fuel marker in diesel fuel may be determined using 
the test procedures qualified in accordance with the requirements in 
this section.
    (a) Sampling and testing for methods for the fuel marker. The 
sampling, sample preparation, and testing methods qualified for use in 
accordance with the requirements of this section may involve the use of 
hazardous materials, operations and equipment. This section does not 
address the associated safety problems which may exist. It is the 
responsibility of the user of the procedures specified in this section 
to establish appropriate safety and health practices prior to their use. 
It is also the responsibility of the user to dispose of any byproducts 
which might result from conducting these procedures in a manner 
consistent with applicable safety and health requirements.
    (b) What are the precision and accuracy criteria for qualification 
of fuel marker test methods?--(1) Precision. A standard deviation of 
less than 0.10 milligrams per liter is required, computed from the 
results of a minimum of 20 repeat tests made over 20 days on samples 
taken from a homogeneous commercially available diesel fuel which meets 
the applicable industry consensus and federal regulatory specifications 
and which contains the fuel marker at a concentration in the range of 
0.10 to 8 milligrams per liter. In order to qualify, the 20 results must 
be a series of tests on the same material and there must be a sequential 
record of the analysis with no omissions. A laboratory facility may 
exclude a given sample or test result only if the exclusion is for a 
valid reason under good laboratory practices and it maintains records 
regarding the sample and test results and the reason for excluding them.
    (2) Accuracy. (i) The arithmetic average of a continuous series of 
at least 10 tests performed on a commercially available marker solvent 
yellow 124 standard in the range of 0.10 to 1 milligrams per liter shall 
not differ from the ARV of that standard by more than 0.05 milligrams 
per liter.
    (ii) The arithmetic average of a continuous series of at least 10 
tests performed on a commercially available marker solvent yellow 124 
standard in the range of 4 to 10 milligrams per liter shall not differ 
from the ARV of that standard by more than 0.05 milligrams per liter.
    (iii) In applying the tests of paragraphs (b)(2)(i) and (ii) of this 
section, individual test results shall be compensated for any known 
chemical interferences.
    (c) What process must a test facility follow in order to qualify a 
test method for determining the fuel marker content of distillate fuels 
and how will EPA qualify or decline to qualify a test method?--(1) 
Qualification of test methods approved by voluntary consensus-based 
standards bodies. Any standard test method developed by a Voluntary 
Consensus-Based Standards Body, such as the American Society for Testing 
and Materials (ASTM) or International Standards Organization (ISO), 
shall be considered a qualified test method for determining the fuel 
marker content of distillate fuel provided that it meets the precision 
and accuracy criteria under paragraph (b) of this section. The 
qualification of a test method is limited to the single test facility 
that performed the testing for accuracy and precision. The individual 
facility must submit the accuracy and precision results for each method, 
including information on the date and time of each test measurement used 
to demonstrate precision, following procedures established by the 
Administrator.
    (2) Qualification of test methods that have not been approved by a 
voluntary consensus-based standards body. A test method that has not 
been approved by a voluntary consensus-based standards body may be 
qualified upon approval by the Administrator. The following information 
must be submitted in the application for approval by each test facility, 
for each test method that it wishes to have approved:
    (i) Full test method documentation, including a description of the 
technology and/or instrumentation that makes the method functional.
    (ii) Information demonstrating that the test method meets the 
accuracy and precision criteria under paragraph (b) of this section, 
including information on the date and time of each test

[[Page 940]]

measurement used to demonstrate precision.
    (iii) Samples used for precision and accuracy determination must be 
retained for 90 days.
    (iv) If requested by the Administrator, test results utilizing the 
method and performed on a sample of commercially available distillate 
fuel which meets the applicable industry consensus and federal 
regulatory specifications and which contains the fuel marker.
    (v) Any additional information requested by the Administrator and 
necessary to render a decision as to qualification of the test method.
    (vi) The qualification of a test method is limited to the single 
test facility that performed the testing for accuracy and precision and 
any other required testing.
    (3)(i) Within 90 days of receipt of all materials required to be 
submitted under paragraph (c)(1) or (c)(2) of this section, the 
Administrator shall determine whether to qualify the test method under 
this section. The Administrator shall qualify the test method if all 
materials required under this section are received and the test method 
meets the accuracy and precision criteria of paragraph (b) of this 
section.
    (ii) If the Administrator denies approval of the test method, within 
90 days of receipt of all materials required to be submitted under this 
section, the Administrator will notify the applicant of the reasons for 
not approving the method. If the Administrator does not notify the 
applicant within 90 days of receipt of the application, that the test 
method is not approved, then the test method shall be deemed approved.
    (iii) If the Administrator finds that an individual test facility 
has provided false or inaccurate information under this section, upon 
notice from the Administrator, the qualification shall be void ab 
initio.
    (iv) The qualification of any test method under this paragraph (c) 
shall be valid for the duration of the period during which the fuel 
marker requirements remain applicable under this subpart.
    (d) Quality control procedures for fuel marker measurement 
instrumentation. A test shall not be considered a test using a qualified 
test method unless the following quality control procedures are 
performed separately for each instrument used to make measurements:
    (1) Follow all mandatory provisions of ASTM D 6299-02 and construct 
control charts from the mandatory quality control testing prescribed in 
paragraph 7.1 of the reference method, following guidelines under A 
1.5.1 for individual observation charts and A 1.5.2 for moving range 
charts. The Director of the Federal Register approved the incorporation 
by reference of ASTM D 6299-02, Standard Practice for Applying 
Statistical Quality Assurance Techniques to Evaluate Analytical 
Measurement System Performance, as prescribed in 5 U.S.C. 552(a) and 1 
CFR part 51. Anyone may purchase copies of this standard from the 
American Society for Testing and Materials, 100 Barr Harbor Dr., West 
Conshohocken, PA 19428. Anyone may inspect copies at the U.S. EPA, Air 
and Radiation Docket and Information Center, 1301 Constitution Ave., 
NW., Room B102, EPA West Building, 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.
    (2) Follow paragraph 7.3.1 of ASTM D 6299-02 to check standards 
using a reference material at least monthly or following any major 
change to the laboratory equipment or test procedure. Any deviation from 
the accepted reference value of a check standard greater than 0.10 
milligrams per liter must be investigated.
    (3) Samples of tested batches must be retained for 30 days or the 
period equal to the interval between quality control sample tests, 
whichever is longer.
    (4) Upon discovery of any quality control testing violation of 
paragraph A 1.5.1.3 or A 1.5.2.1 of ASTM D 6299-02, or any check 
standard deviation greater than 0.10 milligrams per liter, conduct an 
investigation into the cause of such violation or deviation and, after

[[Page 941]]

restoring method performance to statistical control, retest retained 
samples from batches originally tested since the last satisfactory 
quality control material or check standard testing occasion.
    (5) Retain results of quality control testing and retesting of 
retained samples under paragraph (d)(3) of this section for five years.

[69 FR 39185, June 29, 2004]



Sec. 80.583  What alternative sampling and testing requirements apply
to importers who transport motor vehicle diesel fuel or NRLM diesel

fuel by truck or rail 
          car?

    Importers who import diesel fuel subject to the 15 ppm sulfur 
standard under Sec. 80.510(b) or (c) or 80.520(a) into the United 
States by truck or by rail car may comply with the following 
requirements instead of the requirements to sample and test each batch 
of fuel designated as subject to the 15 ppm sulfur standard under Sec. 
80.581 otherwise applicable to importers:
    (a) Terminal testing. For purposes of determining compliance with 
the 15 ppm sulfur standard, the importer may use test results for sulfur 
content testing conducted by the foreign truck-loading or rail car-
loading terminal operator for diesel fuel contained in the storage tank 
from which trucks or rail cars used to transport diesel fuel designated 
as subject to the 15 ppm sulfur content standard into the United States 
are loaded, provided the following conditions are met:
    (1) The sampling and testing shall be performed after each receipt 
of diesel fuel into the storage tank, or immediately before each 
transfer of diesel fuel to the importer's truck or rail car.
    (2) The sampling and testing shall be performed according to Sec. 
80.580.
    (3) At the time of each transfer of diesel fuel to the importer's 
truck or rail car for import to the U.S., the importer must obtain a 
copy of the terminal test result that indicates the sulfur content of 
the truck or rail car load, or truck or rail car compartment load, as 
applicable.
    (b) Quality assurance program. The importer must conduct a quality 
assurance program, as specified in this paragraph (b), for each truck or 
rail car loading terminal.
    (1) Quality assurance samples must be obtained from the truck-
loading or rail car loading terminal and tested by the importer, or by 
an independent laboratory, and the terminal operator must not know in 
advance when samples are to be collected.
    (2) The sampling and testing must be performed using the methods 
specified in Sec. 80.580.
    (3) The frequency of the quality assurance sampling and testing must 
be at least one sample for each 50 of an importer's trucks or rail cars 
that are loaded at a terminal, or one sample per month, whichever is 
more frequent.
    (c) Party required to conduct quality assurance testing. The quality 
assurance program under paragraph (b) of this section shall be conducted 
by the importer. In the alternative, this testing may be conducted by an 
independent laboratory that meets the criteria under Sec. 
80.65(f)(2)(iii), provided the importer receives copies of all results 
of tests conducted no later than 21 days after the sample was taken.
    (d) Alternative batch designations. For purposes of maintaining 
batch records under Sec. Sec. 80.592, 80.600, and 80.602, designation 
of batches under Sec. 80.598, and reporting under Sec. Sec. 80.593, 
80.601, and 80.604:
    (1) In lieu of treating each portion of a tank truck compartment 
delivered to a different facility as a different batch, a truck importer 
may treat each compartment as a batch, if all the fuel in the 
compartment is delivered only to retail outlets, wholesale purchaser-
consumers or other end users. Where different compartments contain 
homogeneous product of identical designations, the total volume of those 
compartments may be treated as a single batch, if the entire volume is 
delivered only to retail outlets, wholesale purchaser-consumers or other 
ultimate consumers.
    (2) Each portion of a rail car (or rail cars) delivery of a 
different designation or each delivery to a different facility is 
considered to be a separate batch.
    (e) EPA inspections of terminals. EPA inspectors or auditors must be 
given full and immediate access to the truck or rail car-loading 
terminal and any

[[Page 942]]

laboratory at which samples of diesel fuel collected at the terminal are 
analyzed, and must be allowed to conduct inspections, review records, 
collect diesel fuel samples and perform audits. These inspections or 
audits may be either announced or unannounced.
    (f) Certified DFR-Diesel. This section does not apply to Certified 
DFR-Diesel as defined in Sec. 80.620.
    (g) Effect of noncompliance. If any of the requirements of this 
section are not met, all motor vehicle diesel fuel and NRLM diesel fuel 
imported by the truck or rail car importer during the time the 
requirements are not met is deemed in violation of the 15 ppm sulfur 
diesel fuel standards in Sec. 80.510(b) or (c) or Sec. 80.520(a), as 
applicable. Additionally, if any requirement is not met, EPA may notify 
the importer of the violation, and, if the requirement is not fulfilled 
within 10 days of notification, the truck importer may not in the future 
use the sampling and testing provisions in this section in lieu of the 
provisions in Sec. 80.581.

[69 FR 39186, June 29, 2004]



Sec. 80.584  What are the precision and accuracy criteria for approval
of test methods for determining the sulfur content of motor

vehicle and NRLM diesel 
          fuel?

    (a) Precision. (1) For motor vehicle diesel fuel and diesel fuel 
additives subject to the 15 ppm sulfur standard of Sec. 80.520(a)(1) 
and NRLM diesel fuel and diesel fuel additives subject to the 15 ppm 
sulfur standard of Sec. 80.510(b) and (c), a standard deviation less 
than 0.72 ppm, computed from the results of a minimum of 20 repeat tests 
made over 20 days on samples taken from a single homogeneous 
commercially available diesel fuel with a sulfur content in the range of 
5-15 ppm. The 20 results must be a series of tests with a sequential 
record of the analyses and no omissions. A laboratory facility may 
exclude a given sample or test result only if the exclusion is for a 
valid reason under good laboratory practices and it maintains records 
regarding the sample and test results and the reason for excluding them.
    (2) For motor vehicle diesel fuel subject to the 500 ppm sulfur 
standard of Sec. 80.520(c), and for NRLM diesel fuel subject to the 500 
ppm sulfur standard of Sec. 80.510(a), of a standard deviation less 
than 9.68 ppm, computed from the results of a minimum of 20 repeat tests 
made over 20 days on samples taken from a single homogeneous 
commercially available diesel fuel with a sulfur content in the range of 
200-500 ppm. The 20 results must be a series of tests with a sequential 
record of the analyses and no omissions. A laboratory facility may 
exclude a given sample or test result only if the exclusion is for a 
valid reason under good laboratory practices and it maintains records 
regarding the sample and test results and the reason for excluding them.
    (b) Accuracy. (1) For motor vehicle diesel fuel and diesel fuel 
additives subject to the 15 ppm sulfur standard of Sec. 80.520(a)(1) 
and NRLM diesel fuel and diesel fuel additives subject to the 15 ppm 
sulfur standard of Sec. 80.510(b) and (c):
    (i) The arithmetic average of a continuous series of at least 10 
tests performed on a commercially available gravimetric sulfur standard 
in the range of 1-10 ppm sulfur shall not differ from the accepted 
reference value (ARV) of that standard by more than 0.54 ppm sulfur;
    (ii) The arithmetic average of a continuous series of at least 10 
tests performed on a commercially available gravimetric sulfur standard 
in the range of 10-20 ppm sulfur shall not differ from the ARV of that 
standard by more than 0.54 ppm sulfur; and
    (iii) In applying the tests of paragraphs (b)(1)(i) and (ii) of this 
section, individual test results shall be compensated for any known 
chemical interferences.
    (2) For motor vehicle diesel fuel subject to the 500 ppm sulfur 
standard of Sec. 80.520(c), and for NRLM diesel fuel subject to the 500 
ppm sulfur standard of Sec. 80.510(a):
    (i) The arithmetic average of a continuous series of at least 10 
tests performed on a commercially available gravimetric sulfur standard 
in the range of 100-200 ppm sulfur shall not differ from the ARV of that 
standard by more than 7.26 ppm sulfur;
    (ii) The arithmetic average of a continuous series of at least 10 
tests performed on a commercially available

[[Page 943]]

gravimetric sulfur standard in the range of 400-500 ppm sulfur shall not 
differ from the ARV of that standard by more than 7.26 ppm sulfur; and
    (iii) In applying the tests of paragraphs (b)(2)(i) and (ii) of this 
section, individual test results shall be compensated for any known 
chemical interferences.

[69 FR 39187, June 29, 2004]



Sec. 80.585  What is the process for approval of a test method
for determining the sulfur content of diesel?

    (a) Approval of test methods approved by voluntary consensus-based 
standards bodies. For such a method to be approved, the following 
information must be submitted to the Administrator by each test facility 
for each test method that it wishes to have approved: Any test method 
approved by a voluntary consensus-based standards body, such as the 
American Society for Testing and Materials (ASTM) or International 
Standards Organization (ISO), shall be approved as a test method for 
determining the sulfur content of diesel fuel if it meets the applicable 
accuracy and precision criteria under Sec. 80.584. The approval of a 
test method is limited to the single test facility that performed the 
testing for accuracy and precision. The individual facility must submit 
the accuracy and precision results for each method, including 
information on the date and time of each test measurement used to 
demonstrate precision, following procedures established by the 
Administrator.
    (b) Approval of test methods not approved by a voluntary consensus-
based standards body. For such a method to be approved, the following 
information must be submitted to the Administrator by each test facility 
for each test method that it wishes to have approved:
    (1) Full test method documentation, including a description of the 
technology and/or instrumentation that makes the method functional.
    (2) Information demonstrating that the test method meets the 
applicable accuracy and precision criteria of Sec. 80.584, including 
information on the date and time of each test measurement used to 
demonstrate precision.
    (3) If requested by the Administrator, test results from use of the 
method to analyze samples of commercially available fuel provided by 
EPA.
    (4) Any additional information requested by the Administrator and 
necessary to render a decision as to approval of the test method.
    (c) Sample retention. Samples used for precision and accuracy 
determination must be retained for 90 days.
    (d) EPA approval. (1) Within 90 days of receipt of all materials 
required to be submitted under paragraph (a) or (b) of this section, the 
Administrator shall determine whether the test method is approved under 
this section.
    (2) If the Administrator denies approval of the test method, within 
90 days of receipt of all materials required to be submitted under 
paragraph (a) or (b) of this section, the Administrator will notify the 
applicant of the reasons for not approving the method. If the 
Administrator does not notify the applicant within 90 days of receipt of 
the application, that the test method is not approved, then the test 
method shall be deemed approved.
    (3) If the Administrator finds that an individual test facility has 
provided false or inaccurate information under this section, upon notice 
from the Administrator the approval shall be void ab initio.
    (4) The approval of any test method under paragraph (b) of this 
section shall be valid for five years from the date of approval by the 
Administrator and shall not be extended. If the method is later approved 
by a voluntary consensus-based standards body, the approval shall remain 
valid as long as the conditions of paragraph (a) of this section are 
met.
    (e) Quality assurance procedures for sulfur measurement 
instrumentation. A test shall not be considered a test using an approved 
test method unless the following quality control procedures are 
performed separately for each instrument used to make measurements:
    (1) Follow all mandatory provisions of ASTM D 6299-02 and construct 
control charts from the mandatory quality control testing prescribed in 
paragraph 7.1 of the reference method, following guidelines under A 
1.5.1 for individual

[[Page 944]]

observation charts and A 1.5.2 for moving range charts. The Director of 
the Federal Register approved the incorporation by reference of ASTM D 
6299-02, Standard Practice for Applying Statistical Quality Assurance 
Techniques to Evaluate Analytical Measurement System Performance, as 
prescribed in 5 U.S.C. 552(a) and 1 CFR part 51. Anyone may purchase 
copies of this standard from the American Society for Testing and 
Materials, 100 Barr Harbor Dr., West Conshohocken, PA 19428. Anyone may 
inspect copies at the U.S. EPA, Air and Radiation Docket and Information 
Center, 1301 Constitution Ave., NW., Room B102, EPA West Building, 
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.
    (2) Follow paragraph 7.3.1 of ASTM D 6299-02 to check standards 
using a reference material at least monthly or following any major 
change to the laboratory equipment or test procedure. Any deviation from 
the accepted reference value of a check standard greater than 1.44 ppm 
(for diesel fuel subject to the 15 ppm sulfur standard) or 19.36 ppm 
(for diesel fuel subject to the 500 ppm sulfur standard) must be 
investigated.
    (3) Samples of tested batches must be retained for 30 days or the 
period equal to the interval between quality control sample tests, 
whichever is longer.
    (4) Upon discovery of any quality control testing violation of 
paragraph A 1.5.1.3 or A 1.5.2.1 of ASTM D 6299-02, or any check 
standard deviation greater than 1.44 ppm (for diesel fuel subject to the 
15 ppm sulfur standard) or 19.36 ppm (for diesel fuel subject to the 500 
ppm sulfur standard), conduct an investigation into the cause of such 
violation or deviation and, after restoring method performance to 
statistical control, retest retained samples from batches originally 
tested since the last satisfactory quality control material or check 
standard testing occasion.

[69 FR 39187, June 29, 2004]



Sec. 80.586  What are the record retention requirements for test
methods approved under this subpart?

    Each individual test facility must retain records related to the 
establishment of accuracy and precision values, all test method 
documentation, and any quality control testing and analysis under 
Sec. Sec. 80.582, 80.584 and 80.585, for five years.

[69 FR 39188, June 29, 2004]



Sec. Sec. 80.587-80.589  [Reserved]

                Recordkeeping and Reporting Requirements



Sec. 80.590  What are the product transfer document requirements for
motor vehicle diesel fuel, NRLM diesel fuel, heating oil

and other distillates?

    (a) On each occasion that any person transfers custody or title to 
MVNRLM diesel fuel or heating oil, including distillates used or 
intended to be used as MVNRLM diesel fuel or heating oil, except when 
such fuel is dispensed into motor vehicles or nonroad, locomotive, or 
marine equipment, the transferor must provide to the transferee 
documents which include the following information:
    (1) The names and addresses of the transferor and transferee.
    (2) The volume of diesel fuel or distillate which is being 
transferred.
    (3) The location of the diesel fuel or distillate at the time of the 
transfer.
    (4) The date of the transfer.
    (5) For transfers of MVNRLM diesel fuel, the sulfur content standard 
the transferor represents the fuel to meet.
    (6) Beginning June 1, 2006, when an entity transfers custody of a 
distillate fuel designated under Sec. 80.598, the following information 
must also be included:
    (i) The facility registration number of the transferor and 
transferee, for terminals and all parties upstream, under Sec. 80.597, 
if any.
    (ii) An accurate and clear statement of the applicable designation 
and/or classification under Sec. 80.598, for example, 500 ppm sulfur 
NRLM diesel fuel; and whether the fuel is dyed or undyed, and for 
heating oil, whether marked or unmarked.

[[Page 945]]

    (7) For transfers of title or custody from one facility to another 
in the distribution system where diesel fuel or distillates are taxed, 
dyed or marked, and for any subsequent transfers (except when such fuel 
is dispensed into motor vehicles or nonroad, locomotive, or marine 
equipment), an accurate statement on the product transfer document of 
the applicable fuel uses and classifications, as follows (however, in 
instances where space is constrained, substantially similar language may 
be used following approval from EPA):
    (i) Undyed 15 ppm sulfur diesel fuel. For the period from June 1, 
2006 and beyond, ``15 ppm sulfur (maximum) Undyed Ultra-Low Sulfur 
Diesel Fuel. For use in all diesel vehicles and engines.'' From June 1, 
2006 through May 31, 2010, the product transfer document must also state 
whether the diesel fuel is 1D or 2D, or NP diesel.
    (ii) Dyed 15 ppm sulfur diesel fuel. From June 1, 2006 and beyond, 
``15 ppm sulfur (maximum) Dyed Ultra-Low Sulfur Diesel Fuel. For use in 
all nonroad diesel engines. Not for use in highway vehicles or engines 
except for tax-exempt use in accordance with section 4082 of the 
Internal Revenue Code.''
    (iii) Undyed 500 ppm sulfur diesel fuel. From June 1, 2006 through 
September 30, 2010, ``500 ppm sulfur (maximum) Undyed Low Sulfur Diesel 
Fuel. For use in Model Year 2006 and older diesel highway vehicles and 
engines. Also for use in nonroad, locomotive, and marine diesel engines. 
Not for use in model year 2007 and newer highway vehicles or engines.''
    (iv) Dyed 500 ppm sulfur diesel fuel. (A) For the period of June 1, 
2006 through September 30, 2010, ``500 ppm sulfur (maximum) Dyed Low 
Sulfur Nonroad, Locomotive or Marine Diesel Fuel. Not for use in highway 
vehicles or engines except for use in Model Year 2006 and older highway 
diesel vehicles or engines for tax-exempt use in accordance with section 
4082 of the Internal Revenue Code.''
    (B) From June 1, 2010 through September 30, 2014, ``500 ppm sulfur 
(maximum) Dyed Low Sulfur Nonroad Diesel Fuel. For use in model year 
2010 and older nonroad diesel engines. May be used in locomotive and 
marine diesel engines. Not for use in highway vehicles and engines or 
model year 2011 or later nonroad engines other than locomotive or marine 
diesel engines. Not for use in the Northeast/Mid-Atlantic Area.''
    (C) For dyed locomotive and marine diesel fuel beginning June 1, 
2010, ``500 ppm sulfur (maximum) Dyed Low Sulfur Locomotive and Marine 
diesel fuel. Not for use in highway or other nonroad vehicles and 
engines.''
    (v) Dyed High Sulfur NRLM Fuel. From June 1, 2007 through September 
30, 2010, ``High Sulfur Dyed Nonroad, Locomotive, or Marine Engine 
Diesel fuel--sulfur content may exceed 500 ppm sulfur. Not for use in 
highway vehicles or engines. Not for use in any nonroad engines 
requiring Ultra-Low Sulfur Diesel Fuel. Not for use in the Northeast/
Mid-Atlantic Area.''
    (vi) Heating oil. For heating oil produced or imported beginning 
June 1, 2007, ``Heating Oil. Not for use in highway vehicles or engines 
or nonroad, locomotive, or marine engines.''
    (b) The following may be substituted for the descriptions in 
paragraph (a) of this section, as appropriate:
    (1) ``This is high sulfur diesel fuel for use only in Guam, American 
Samoa, or the Northern Mariana Islands.'';
    (2) ``This diesel fuel is for export use only.'';
    (3) ``This diesel fuel is for research, development, or testing 
purposes only.''; or
    (4) ``This diesel fuel is for use in diesel highway vehicles or 
nonroad equipment under an EPA-approved national security exemption 
only.''
    (c) If undyed and/or unmarked distillate fuel is dyed and/or marked 
subsequent to the issuance of a product transfer document, at the time 
the distillate fuel is dyed and/or marked, a new product transfer 
document must be prepared with the language under paragraph (a)(7) of 
this section applicable to the changed fuel and provided to subsequent 
transferees.
    (d) Except for transfers to truck carriers, retailers or wholesale 
purchaser-consumers, product codes may be used to convey the information 
required under this section if such codes are clearly understood by each 
transferee. ``15'', ``500'', or ``greater than 500'' or 
``500'' must appear clearly on the

[[Page 946]]

product transfer document, and may be contained in the product code. If 
the designation is included in the code: codes used to convey the 
statement in paragraphs (a)(7)(i) and (a)(7)(ii) of this section must 
contain the number ``15'', codes used to convey the statement in 
paragraphs (a)(7)(iii) and (a)(7)(iv) of this section must contain the 
number ``500''; codes used to convey the statement in paragraph 
(a)(7)(v) of this section must contain the statement ``greater than 
500'' or ``500''. If another letter, number, or symbol is 
being used to convey any of the statements in paragraphs (a)(7)(i), 
(a)(7)(ii), (a)(7)(iii), (a)(7)(iv), and/or (a)(7)(v) of this section, 
it must be clearly defined and denoted on the product transfer document.
    (e) From June 1, 2001 through May 31, 2005, any transfer subject to 
this section, which is also subject to the early credit provisions of 
Sec. 80.531(b), must comply with all applicable requirements of this 
section.
    (f) From June 1, 2005 through May 31, 2006, any transfer subject to 
this section, which is also subject to the early credit requirements of 
Sec. 80.531(c), must comply with all applicable requirements of this 
section.
    (g) Mobile refuelers. The provisions of this section shall also 
apply to a mobile refueler that dispenses fuel from tanker trucks or 
other vessels into motor vehicles, nonroad diesel engines or nonroad 
diesel engine equipment. Each visit by the mobile refueler to a location 
shall be considered a separate occasion for purposes of paragraph (a) of 
this section. The tank trucks used by mobile refuelers are not subject 
to the labeling requirements in Sec. Sec. 80.570 through 80.574.
    (h) Identifications of fuel designations can be limited to a sub-
designation that accurately identifies the fuel and do not need to also 
include the broader designation. For example, NR diesel fuel does not 
also need to be designated as NRLM or MVNRLM diesel fuel.
    (i) Pipeline Ticketing. For the case where a pipeline delivers a 
batch of ULSD to another facility that contains slight amounts of 
another type of fuel from a preceding or following batch, a clear 
statement must be included on the PTD denoting this. When this occurs, 
the receiving facility must handle the fuel appropriately (e.g., 
redesignate or downgrade any amount of fuel in that batch that does not 
meet the applicable sulfur standard), in accordance with the provisions 
of Sec. Sec. 80.527 and 80.599.

[69 FR 39188, June 29, 2004, as amended at 70 FR 40896, July 15, 2005; 
70 FR 70510, Nov. 22, 2005, as amended at 71 FR 25719, May 1, 2006]



Sec. 80.591  What are the product transfer document requirements for
additives to be used in diesel fuel?

    (a) Except as provided in paragraphs (b) and (d) of this section, on 
each occasion that any person transfers custody or title to a diesel 
fuel additive that is subject to the provisions of Sec. 80.521 to a 
party in the additive distribution system or in the diesel fuel 
distribution system for use downstream of the diesel fuel refiner, the 
transferor must provide to the transferee documents which identify the 
additive, and--
    (1) Identify the name and address of the transferor and transferee; 
the date of transfer; the location at which the transfer took place; the 
volume of additive transferred; and
    (2) Indicate compliance with the 15 ppm sulfur standard by inclusion 
of the following statement: ``The sulfur content of this diesel fuel 
additive does not exceed 15 ppm.''
    (b) On each occasion that any person transfers custody or title to a 
diesel fuel additive subject to the requirements of Sec. 80.521(b), to 
a party in the additive distribution system or in the diesel fuel 
distribution system for use in diesel fuel downstream of the diesel fuel 
refiner, the transferor must provide to the transferee documents which 
identify the additive, and do each of the following:
    (1) Identify the name and address of the transferor and transferee; 
the date of transfer; the location at which the transfer took place; the 
volume of additive transferred.
    (2) Indicate the high sulfur potential of the additive by inclusion 
of the following statement:

    This diesel fuel additive may exceed the federal 15 ppm sulfur 
standard. Improper use of this additive may result in non-complying 
diesel fuel.


[[Page 947]]


    (3) If the additive package contains a static dissipater additive 
and/or red dye having a sulfur content greater than 15 ppm, a statement 
must be included which accurately describes the contents of the additive 
package pursuant to one of the following choices:
    (i) ``This diesel fuel additive contains a static dissipater 
additive having a sulfur content greater than 15 ppm.''
    (ii) ``This diesel fuel additive contains red dye having a sulfur 
content greater than 15 ppm.''
    (iii) ``This diesel fuel additive contains a static dissipater 
additive and red dye having a sulfur content greater than 15 ppm.''
    (4) Include the following information:
    (i) The additive package's maximum sulfur concentration.
    (ii) The maximum recommended concentration in volume percent for use 
of the additive package in diesel fuel.
    (iii) The contribution to the sulfur level of the fuel, in ppm, that 
would result if the additive package is used at the maximum recommended 
concentration.
    (c) Except for transfers of diesel fuel additives to truck carriers, 
retailers or wholesale purchaser-consumers, product codes may be used to 
convey the information required under paragraphs (a) and (b) of this 
section, if such codes are clearly understood by each transferee. Codes 
used to convey the statement in paragraph (a)(2) of this section must 
contain the number ``15'' and codes used to convey the statement in 
paragraph (b)(2) of this section must not contain such number.
    (d) For those diesel fuel additives which are sold in containers for 
use by the ultimate consumer of diesel fuel, each transferor must have 
displayed on the additive container, in a legible and conspicuous 
manner, either of the following statements, as applicable:
    (1) ``This diesel fuel additive complies with the federal low sulfur 
content requirements for use in diesel motor vehicles and nonroad 
engines.''; or
    (2) For those additives sold in containers for use by the ultimate 
consumer, with a sulfur content in excess of 15 ppm the following 
statement: ``This diesel fuel additive does not comply with federal 
ultra-low sulfur content requirements for use in model year 2007 and 
newer diesel motor vehicles or model year 2011 and newer diesel nonroad 
equipment engines.''

[69 FR 39189, June 29, 2004, as amended at 70 FR 40896, July 15, 2005; 
71 FR 25719, May 1, 2006]



Sec. 80.592  What records must be kept by entities in the motor
vehicle diesel fuel and diesel fuel additive distribution systems?

    (a) Records that must be kept by entities in the motor vehicle 
diesel fuel and diesel fuel additive distribution systems. Beginning 
June 1, 2006, or for a refiner or importer, the first compliance period 
in which the refiner or importer is generating early credits under Sec. 
80.531(b) or (c), whichever is earlier, any person who produces, 
imports, sells, offers for sale, dispenses, distributes, supplies, 
offers for supply, stores, or transports motor vehicle diesel fuel 
subject to the provisions of this subpart, must keep all the following 
records:
    (1) The applicable product transfer documents required under 
Sec. Sec. 80.590 and 80.591.
    (2) For any sampling and testing for sulfur content for a batch of 
motor vehicle diesel fuel produced or imported and subject to the 15 ppm 
sulfur standard or any sampling and testing for sulfur content as part 
of a quality assurance testing program, and any sampling and testing for 
cetane index, aromatics content, solvent yellow 124 content or dye 
solvent red 164 content of motor vehicle diesel fuel or motor vehicle 
diesel fuel additives:
    (i) The location, date, time and storage tank or truck 
identification for each sample collected;
    (ii) The name and title of the person who collected the sample and 
the person who performed the testing; and
    (iii) The results of the tests for sulfur content (including, where 
applicable, the test results with and without application of the 
adjustment factor under Sec. 80.580(d)) and for cetane index or 
aromatics content (as applicable), and the volume of product in the 
storage tank or container from which the sample was taken.
    (3) The actions the party has taken, if any, to stop the sale or 
distribution of any motor vehicle diesel fuel found not to be in 
compliance with the sulfur

[[Page 948]]

standards specified in this subpart, and the actions the party has 
taken, if any, to identify the cause of any noncompliance and prevent 
future instances of noncompliance.
    (b) Additional records to be kept by refiners and importers of motor 
vehicle diesel fuel subject to hardship standards, small refiner 
standards and early credit provisions. Beginning June 1, 2006, or for a 
refiner or importer, the first compliance period in which the refiner or 
importer is generating early credits under Sec. 80.531(b) or (c), any 
refiner producing motor vehicle diesel fuel subject to the sulfur 
standard under Sec. 80.520(a)(1), for each of its refineries, and any 
importer importing such motor vehicle diesel fuel, shall keep records 
that include the following information for each batch of motor vehicle 
diesel fuel produced or imported:
    (1) The batch volume.
    (2) The batch number, assigned under the batch numbering procedures 
under Sec. 80.65(d)(3).
    (3) The date of production or import.
    (4) A record designating the batch as motor vehicle diesel fuel 
meeting the 500 ppm sulfur standard or as motor vehicle diesel fuel 
meeting the 15 ppm sulfur standard.
    (5) For foreign refiners, the designations and other records 
required to be kept under Sec. 80.620.
    (6) In the case of importers, the designations and other records 
required under Sec. 80.620(o).
    (7) Information regarding credits, kept separately for each calendar 
year compliance period, kept separately for each refinery and in the 
case of importers, kept separately for imports into each CTA, and 
designated as motor vehicle diesel fuel credits and kept separately from 
NRLM credits, as follows:
    (i) The number of credits in the refiner's or importer's possession 
at the beginning of the calendar year;
    (ii) The number of credits generated;
    (iii) The number of credits used;
    (iv) If any were obtained from or transferred to other parties, for 
each such other party, its name, its EPA refiner or importer 
registration number consistent with Sec. 80.593(d), in the case of 
credits generated by an importer the port and CTA of import of the 
diesel fuel that generated the credits, and the number obtained from, or 
transferred to, the other party;
    (v) The number in the refiner's or importer's possession that will 
carry over into the subsequent calendar year compliance period; and
    (vi) Commercial documents that establish each transfer of credits 
from the transferor to the transferee.
    (8) The calculations used to determine compliance with the volume 
requirements of this subpart.
    (9) The calculations used to determine the number of credits 
generated.
    (10) A copy of reports submitted to EPA under Sec. 80.593.
    (c) Additional records importers must keep. Any importer shall keep 
records that identify and verify the source of each batch of certified 
diesel fuel program foreign refiner DFR-Diesel and non-certified DFR-
Diesel imported and demonstrate compliance with the requirements under 
Sec. 80.620.
    (d) Length of time records must be kept. The records required in 
this section shall be kept for five years from the date they were 
created, except that records relating to credit transfers shall be kept 
by the transferor for 5 years from the date the credits were 
transferred, and shall be kept by the transferee for 5 years from the 
date the credits were transferred, used or terminated, whichever is 
later.
    (e) Make records available to EPA. On request by EPA, the records 
required in this section must be made available to the Administrator or 
the Administrator's representative. For records that are electronically 
generated or maintained, the equipment and software necessary to read 
the records shall be made available, or if requested by EPA, electronic 
records shall be converted to paper documents which shall be provided to 
the Administrator's authorized representative.
    (f) Additional records to be kept by aggregated facilities 
consisting of a refinery and a truck loading terminal. In addition to 
the records required by paragraph (a) of this section, such aggregated 
facilities must also keep the following records beginning June 1, 2006:
    (1) The following information for each batch of motor vehicle diesel 
fuel produced by the refinery and sent over the aggregated facility's 
truck rack:

[[Page 949]]

    (i) The batch volume;
    (ii) The batch number, assigned under the batch numbering procedures 
under Sec. Sec. 80.65(d)(3) and 80.502(d)(1);
    (iii) The date of receipt or import;
    (iv) A record designating the batch as motor vehicle diesel fuel 
meeting the 500 ppm sulfur standard or as motor vehicle diesel fuel 
meeting the 15 ppm sulfur standard; and,
    (v) A record indicating the volumes that were either taxed, dyed, or 
dyed and marked.
    (2) Volume reports for all motor vehicle diesel fuel from external 
sources (i.e., from another refiner or importer), as described in Sec. 
80.601(f)(2), sent over the aggregated facility's truck rack.

[66 FR 5136, Jan. 18, 2001, as amended at 69 FR 39189, June 29, 2004; 70 
FR 70510, Nov. 22, 2005; 71 FR 25719, May 1, 2006]



Sec. 80.593  What are the reporting requirements for refiners and 
importers of motor vehicle diesel fuel subject to temporary refiner

relief standards?

    Beginning with 2006, or the first compliance period during which 
credits are generated under Sec. 80.531(b) or (c), whichever is 
earlier, any refiner or importer who produces or importes motor vehicle 
diesel fuel subject to the 500 ppm sulfur standard under Sec. 
80.520(c), or any refiner or importer who generates, uses, obtains or 
transfers credits under Sec. Sec. 80.530 through 80.532, and continuing 
for each year thereafter, must submit to EPA annual reports that contain 
the information required in this section, and such other information as 
EPA may require:
    (a) Refiners and importers. Refiners and importers must report the 
following information separately for each refinery or CTA, in the case 
of importers, subject to a phase-in sulfur standard, small refiner 
standard or temporary refiner relief sulfur standard, or who generates, 
uses or transfers credits under Sec. Sec. 80.530 through 80.532:
    (1) The refiner's name and the EPA refinery registration number.
    (2) For all motor vehicle diesel fuel produced for use in the United 
States during the compliance period:
    (i) The total volume of motor vehicle diesel fuel produced;
    (ii) The volume, in gallons, that complied with a sulfur content 
standard of 500 ppm; and
    (iii) The volume, in gallons, that complied with the 15 ppm sulfur 
content standard.
    (3) The percentage of the volume of motor vehicle diesel fuel 
produced during the compliance period that met the 15 ppm sulfur 
standard and the percentage that met the 500 ppm sulfur standard prior 
to the application of any volume credits.
    (4) The percentage of volume of motor vehicle diesel fuel produced 
meeting the 15 ppm sulfur standard after the inclusion of any credits.
    (5) Information regarding credits, separately for each refinery and 
for credits or debits related to imported motor diesel fuel, separately 
by importer and separately by CTA of import as follows:
    (i) The CTA of the refiner's refinery or the importer's or the 
foreign refiner's CTA and port of importation;
    (ii) The number of credits at the beginning of the compliance 
period;
    (iii) The number of credits generated;
    (iv) The number of credits used;
    (v) If any credits were obtained from or transferred to other 
refineries or import ports, for each other refinery or importer, its 
name, address (or Port) and CTA, EPA refinery or importer registration 
number, and the number of credits obtained from or transferred to the 
other refinery or importer (by import CTA);
    (vi) The number of credits, if any, that will carry over to the 
subsequent compliance period; and
    (vii) The number of credits in deficit that must be made up for the 
following year;
    (6) The reporting requirements under Sec. 80.620, if applicable.
    (7) For each batch of motor vehicle diesel fuel produced or imported 
during the compliance period:
    (i) The batch number assigned using the batch numbering conventions 
under Sec. 80.65(d)(3) and the appropriate designation under Sec. 
80.598.
    (ii) The date the batch was produced; and
    (iii) The volume of the batch, in gallons.

[[Page 950]]

    (8) When submitting reports under this paragraph (a), any importer 
shall exclude certified DFR-Diesel.
    (b) Additional reporting requirements for importers. Importers of 
motor vehicle diesel fuel subject to the 500 ppm sulfur standard must 
report the following information:
    (1) The importer's name and EPA registration number.
    (2) For each foreign refinery from which motor vehicle diesel fuel 
is imported that is subject to a sulfur standard under Sec. 80.520(c), 
the importer must report, for each batch of diesel fuel imported, the 
information required to be reported under Sec. 80.620(o).
    (c) Report submission. Any annual report required by this section 
shall be:
    (1) Signed and certified as meeting all the applicable requirements 
of this subpart by the owner or a responsible corporate officer of the 
refiner or importer; and
    (2) Submitted to EPA no later than August 31 for the prior annual 
compliance period.

[66 FR 5136, Jan. 18, 2001, as amended at 69 FR 39190, June 29, 2004; 70 
FR 70510, Nov. 22, 2005]



Sec. 80.594  What are the pre-compliance reporting requirements for
motor vehicle diesel fuel?

    (a) Except as provided in paragraph (d) of this section, beginning 
on June 1, 2003, and on June 1, 2004 and June 1, 2005, all refiners and 
importers planning to produce or import motor vehicle diesel fuel 
subject to the provisions of this subpart, shall submit the following 
information to EPA:
    (1) Any changes to the information submitted for the company 
registration;
    (2) Any changes to the information submitted for any refinery or 
import facility registration;
    (3) An estimate of the average daily volumes (in gallons) of each 
sulfur grade of motor vehicle diesel fuel produced (or imported) at each 
refinery (or import facility). These volume estimates must be provided 
both for fuel produced from crude oil, as well as any fuel produced from 
other sources, and must be provided for the periods of June 1, 2006 
through December 31, 2006, January 1, 2007 through December 31, 2007, 
January 1, 2008 through December 31, 2008, January 1, 2009 through 
December 31, 2009, and January 1, 2010 through May 31, 2010, for each 
refinery and import facility;
    (4) If expecting to participate in the temporary compliance options 
provisions and the credit trading program, estimates of the number of 
credits to be generated and/or used each year the program is applicable;
    (5) Information on project schedule by quarter of known or projected 
completion date by the stage of the project, for example, following the 
five project phases described in EPA's June 2002 Highway Diesel Progress 
Review report (EPA420-R-02-016, http://www.epa.gov/otaq/regs/hd2007/
420r02016.pdf): Strategic planning, Planning and front-end engineering, 
Detailed engineering and permitting, Procurement and construction, and 
Commissioning and startup;
    (6) Basic information regarding the selected technology pathway for 
compliance (e.g., conventional hydrotreating vs. other technologies, 
revamp vs. grassroots, etc.);
    (7) Whether capital commitments have been made or are projected to 
be made; and
    (8) The pre-compliance reports due 2004 and 2005 must provide an 
update of the progress in each of these areas.
    (b) Beginning on June 1, 2003, all approved motor vehicle diesel 
fuel small refiners shall submit the following additional information to 
EPA, as applicable:
    (1) In the case of a refinery with an approved application under 
Sec. 80.552(a):
    (i) A showing that sufficient sources of 15 ppm motor vehicle diesel 
fuel will likely be available in its marketing area after June 1, 2006 
and through 2010;
    (ii) If after 2003 the sources of 15 ppm motor vehicle diesel fuel 
decrease, the pre-compliance reports for 2004 and/or 2005 must identify 
this change and must include a supplementary showing that the sources of 
15 ppm motor vehicle diesel fuel are still sufficient.
    (2) In the case of a refinery with an approved application under 
Sec. 80.552(c), a demonstration that by June 1, 2006, 95 percent of its 
motor vehicle diesel fuel will be at 15 ppm sulfur at a volume meeting 
the requirements of Sec. 80.553(e).

[[Page 951]]

    (c) For each refiner and importer approved under Sec. 80.540, a 
demonstration that by June 1, 2006, 95 percent of its motor vehicle 
diesel fuel will be at 15 ppm sulfur at a volume of meeting the 
requirements of Sec. 80.540(e).
    (d) By July 1, 2006, each refiner and importer of motor vehicle 
diesel fuel shall submit a report to EPA stating that the production or 
importation of 15 ppm sulfur motor vehicle diesel fuel commenced by June 
1, 2006.
    (e) The pre-compliance reporting requirements of this section do not 
apply to refineries subject to the provisions of Sec. 80.513.

[66 FR 5136, Jan. 18, 2001, as amended at 69 FR 39190, June 29, 2004; 70 
FR 40896, July 15, 2005]



Sec. 80.595  How does a small or GPA refiner apply for a motor vehicle
diesel fuel volume baseline for the purpose of extending their

gasoline sulfur 
          standards?

    (a) Any small refiner applying for an extension of the duration of 
its small refiner gasoline sulfur standards of Sec. 80.240, under 
Sec. Sec. 80.552(c) and 80.553, any small refiner applying to produce 
MVDF under Sec. 80.552(a), or any refiner applying for an extension of 
the duration of the GPA standards under Sec. 80.540 must apply for a 
motor vehicle diesel fuel volume baseline by December 31, 2001. A 
separate volume baseline must be sought for each refinery for which 
application of the provisions of Sec. 80.553 or Sec. 80.540 is sought.
    (b) The volume baseline must be sent via certified mail with return 
receipt or express mail with return receipt to: U.S. EPA-Attn: Diesel 
Baseline, 1200 Pennsylvania Avenue, NW. (6406J), Washington, DC 20460 
(certified mail/return receipt) or Attn: Diesel Baseline, Transportation 
and Regional Programs Division, 501 3rd Street, NW. (6406J), Washington, 
DC 20001 (express mail/return receipt).
    (c) The motor vehicle diesel fuel volume baseline application must 
include the following information:
    (1) A listing of the names and addresses of all refineries owned by 
the refiner for which the refiner is applying for a motor vehicle diesel 
fuel volume baseline.
    (2) The average annual volume (in gallons) of motor vehicle diesel 
fuel produced for U.S. use in 1998 and 1999, for each refinery for which 
the refiner is applying for such baseline, calculated in accordance with 
Sec. 80.596. The refiner shall follow the procedures, applicable to 
volume baselines and using motor vehicle diesel fuel instead of 
gasoline, specified in Sec. Sec. 80.91 through 80.93 to establish the 
volume of motor vehicle diesel fuel that was produced for U.S. use in 
1998 and 1999 for purposes of establishing a volume baseline under this 
section.
    (3) A letter signed by the president, chief operating, or chief 
executive officer of the company, or his/her delegate, stating that the 
information contained in the volume baseline determination is true to 
the best of his/her knowledge.
    (4) Name, address, phone number, facsimile number, and e-mail 
address (if availabale) of a corporate contact person.
    (5) The following information for each batch of motor vehicle diesel 
fuel produced for U.S. use in 1998 and 1999:
    (i) Batch number assigned to the batch under procedures such as 
those in Sec. 80.65(d) or Sec. 80.101(i), or, if unavailable, such 
other identifying information as is available; and
    (ii) Volume of the batch, in gallons.
    (6) For a refinery that was not in operation during part or all of 
the period 1998 and 1999, the information required under this paragraph 
(c) for the motor vehicle diesel fuel produced for U.S. use during the 
most recent calendar year that the refinery was in operation after the 
refinery was reactivated.
    (d) Within 120 days of receipt of an application under this section, 
EPA will notify the refiner of an approval of the refinery's baseline, 
or of any deficiencies in the application.
    (e) If at any time the baseline submitted in accordance with the 
requirements of this section is determined to be incorrect, EPA will 
notify the refiner of the corrected baseline. The corrected baseline 
shall apply to all applicable compliance calculations under this 
subpart.
    (f)(1) If insufficient information is available for the 
Administrator to establish a baseline under the provisions of paragraph 
(c) of this section and

[[Page 952]]

Sec. 80.596(a), the refiner shall submit additional information 
sufficient for the Administrator to establish a baseline.
    (2) To satisfy the requirements of paragraph (f)(1) of this section, 
the Administrator may require, and consider, any information pertinent 
to establish a baseline, including:
    (i) Motor vehicle diesel fuel production volumes for other years;
    (ii) Crude capacity of the refinery;
    (iii) The ratio, or the typical ratio, for other similarly sized or 
configured refineries, between motor vehicle diesel fuel production and 
gasoline production.

[66 FR 5136, Jan. 18, 2001, as amended at 70 FR 40896, July 15, 2005]



Sec. 80.596  How is a refinery motor vehicle diesel fuel volume
baseline calculated?

    (a) For purposes of this subpart, a refinery's motor vehicle diesel 
fuel volume baseline is calculated using the following equation:
[GRAPHIC] [TIFF OMITTED] TR18JA01.007

Where:

Vbase = Volume baseline value, in gallons.
Vi = Volume of motor vehicle diesel fuel batch i, in gallons.
n = Total number of batches of motor vehicle diesel fuel produced for 
U.S. use during January 1, 1998 through December 31, 1999 (or the total 
number of batches of motor vehicle diesel fuel produced during the most 
recent calendar year the refinery was in operation after being 
reactivated pursuant to Sec. 80.595(c)(6)); or, for a foreign refinery, 
the total number of batches of motor vehicle diesel fuel produced and 
imported into the U.S. during January 1, 1998 through December 31, 1999 
(or the total number of batches of motor vehicle diesel fuel produced 
and imported into the U.S. during the most recent calendar year the 
refinery was in operation after being reactivated pursuant to Sec. 
80.595(c)(6)).
i = Individual batch of motor vehicle diesel fuel produced during 
January 1, 1998 through December 31, 1999 (or individual batch of motor 
vehicle diesel fuel produced during the most recent calendar year the 
refinery was in operation after being reactivated pursuant to Sec. 
80.595(c)(6)); or, for a foreign refinery, individual batch of motor 
vehicle diesel fuel produced and imported into the U.S. during January 
1, 1998 through December 31, 1999 (or individual batch of motor vehicle 
diesel fuel produced and imported into the U.S. during the most recent 
calendar year the refinery was in operation after being reactivated 
pursuant to Sec. 80.595(c)(6)).
m = Number of months in the baseline period (24 except in the case of a 
startup or reactivation).

    (b) If insufficient information is available for the Administrator 
to establish a baseline under paragraph (a) of this section, the 
baseline may be determined under the provisions of Sec. 80.595(f).

[66 FR 5136, Jan. 18, 2001, as amended at 70 FR 40896, July 15, 2005]



Sec. 80.597  What are the registration requirements?

    The following registration requirements apply under this subpart:
    (a) Registration for motor vehicle diesel fuel. Refiners having any 
refinery that is subject to a sulfur standard under Sec. 80.520(a), and 
importers importing such diesel fuel, must provide EPA the information 
under Sec. 80.76, if such information has not been provided under the 
provisions of this part. In addition, for each import facility, the same 
identifying information as required for each refinery under Sec. 
80.76(c) must be provided.
    (b) Registration for NRLM diesel. Refiners and importers that intend 
to produce or supply NRLM diesel fuel by June 1, 2007, must provide EPA 
the information under Sec. 80.76 no later than December 31, 2005, if 
such information has not been provided under the provisions of this 
part. In addition, for each import facility, the same identifying 
information as required for each refinery under Sec. 80.76(c) must be 
provided.
    (c)Entity registration. (1) Except as prescribed in paragraph (c)(5) 
of this section, each entity as defined in Sec. 80.502 that intends to 
deliver or receive custody of any of the following fuels from June 1, 
2006 through May 31, 2010 must register with EPA by December 31, 2005 or 
six months prior to commencement of producing, importing, or 
distributing any distillate listed in paragraphs (c)(1)(i) through 
(c)(1)(iii) of this section:
    (i) Fuel designated as 500 ppm sulfur MVNRLM diesel fuel under Sec. 
80.598 on

[[Page 953]]

which taxes have not been assessed pursuant to IRS code (26 CFR part 
48).
    (ii) Fuel designated as 15 ppm sulfur MVNRLM diesel fuel under Sec. 
80.598 on which taxes have not been assessed pursuant to IRS code (26 
CFR part 48).
    (iii) Fuel designated as NRLM diesel fuel under Sec. 80.598 that is 
undyed pursuant to Sec. 80.520.
    (iv) Fuel designated as California Diesel fuel under Sec. 80.598 on 
which taxes have not been assessed and red dye has not been added (if 
required) pursuant to IRS code (26 CFR part 48) and that is delivered by 
pipeline to a terminal outside of the State of California pursuant to 
the provisions of Sec. 80.617(b).
    (2) Except as prescribed in paragraph (c)(5) of this section, each 
entity as defined in Sec. 80.502 that intends to deliver or receive 
custody of any of the following fuels from June 1, 2007 through May 31, 
2014 must register with EPA by December 31, 2005 or six months prior to 
commencement of producing, importing, or distributing any distillate 
listed in paragraph (c)(1) of this section:
    (i) Fuel designated as 500 ppm sulfur MVNRLM diesel fuel under Sec. 
80.598 on which taxes have not been assessed pursuant to IRS code (26 
CFR part 48).
    (ii) Fuel designated as NRLM diesel fuel under Sec. 80.598 that is 
undyed pursuant to Sec. 80.520.
    (iii) Fuel designated as heating oil under Sec. 80.598 that is 
unmarked pursuant to Sec. 80.510(d) through (f).
    (iv) Fuel designated as LM diesel fuel under Sec. 80.598(a)(2)(iii) 
that is unmarked pursuant to Sec. 80.510(e).
    (3) Registration shall be on forms prescribed by the Administrator, 
and shall include the name, business address, contact name, telephone 
number, e-mail address, and type of production, importation, or 
distribution activity or activities engaged in by the entity.
    (4) Registration shall include the information required under 
paragraph (d) of this section for each facility owned or operated by the 
entity that delivers or receives custody of a fuel described in 
paragraphs (c)(1) and (c)(2) of this section.
    (5) Exceptions for Excluded Liquids. An entity that would otherwise 
be required to register pursuant to the requirements of paragraphs 
(c)(1) and (c)(2) of this section is exempted from the registration 
requirements under this section provided that:
    (i) The only diesel fuel or heating oil that the entity delivers or 
receives on which taxes have not been assessed or which is not received 
dyed pursuant to Internal Revenue Service (IRS) code 26 CFR part 48 is 
an excluded liquid as defined pursuant to IRS code 26 CFR 4081-1(b).
    (ii) The entity does not transfer the excluded liquid to a facility 
which delivers or receives diesel fuel other than an excluded liquid on 
which taxes have not been assessed pursuant to IRS code (26 CFR part 
48).
    (d) Facility registration. (1) List for each separate facility of an 
entity required to register under paragraph (c) of this section, the 
facility name, physical location, contact name, telephone number, e-mail 
address and type of facility. For facilities that are aggregated under 
Sec. 80.502, provide information regarding the nature and location of 
each of the components. If aggregation is changed for any subsequent 
compliance period, the entity must provide notice to EPA prior to the 
beginning of such compliance period.
    (2) If facility records are kept off-site, list the off-site storage 
facility name, physical location, contact name, and telephone number.
    (3) Mobile facilities:
    (i) A description shall be provided in the registration detailing 
the types of mobile vessels that will likely be included and the nature 
of the operations.
    (ii) Entities may combine all mobile operations into one facility; 
or may split the operations by vessel, region, route, waterway, etc. and 
register separate mobile facilities for each.
    (iii) The specific vessels need not be identified in the 
registration, however information regarding specific vessel contracts 
shall be maintained by each registered entity for its mobile facilities, 
pursuant to Sec. 80.602(d).
    (e) Changes to registration information. Any company or entity shall 
submit updated registration information to the Administrator within 30 
days of any occasion when the registration information previously 
supplied for an

[[Page 954]]

entity, or any of its registered facilities, becomes incomplete or 
inaccurate.
    (f) Issuance of registration numbers. EPA will supply a registration 
number to each entity and a facility registration number to each of an 
entity's facilities that is identified, which shall be used in all 
reports to the Administrator.

[69 FR 39190, June 29, 2004, as amended at 70 FR 70510, Nov. 22, 2005; 
71 FR 25720, May 1, 2006]



Sec. 80.598  What are the designation requirements for refiners,
importers, and distributors?

    (a) Designation requirements for refiners and importers. (1) Any 
refiner or importer shall accurately and clearly designate all fuel it 
produces or imports for use in diesel motor vehicles as either motor 
vehicle diesel fuel meeting the 15 ppm sulfur standard under Sec. 
80.520(a)(1) or as motor vehicle diesel fuel meeting the 500 ppm sulfur 
standard under Sec. 80.520(c).
    (2) Subject to the restrictions in paragraph (a)(3) of this section, 
beginning June 1, 2006, any refiner or importer shall accurately and 
clearly designate each batch of diesel fuel or distillate fuel for which 
they transfer custody to another entity, according to the following 
categories, including specifying its volume:
    (i) Designate the fuel as one of the following fuel types:
    (A) Motor vehicle, nonroad, locomotive or marine (MVNRLM) diesel 
fuel;
    (B) Heating oil;
    (C) Jet fuel;
    (D) Kerosene;
    (E) No. 4 fuel;
    (F) Distillate fuel for export only; or
    (G) Exempt distillate fuels such as fuels that are covered by a 
national security exemption under Sec. 80.606, fuels that are used for 
purposes of research and development pursuant to Sec. 80.607, and fuels 
used in the U.S. Territories pursuant to Sec. 80.608 (including 
additional identifying information).
    (ii) From June 1, 2006 through May 31, 2014 any batch designated as 
MVNRLM diesel fuel must also be designated as one of the following:
    (A) Motor vehicle diesel fuel; or
    (B) NRLM diesel fuel.
    (iii) From June 1, 2010 through May 31, 2012 any batch designated as 
NRLM must also be designated as one of the following:
    (A) NR diesel fuel; or
    (B) LM diesel fuel.
    (iv) Until June 1, 2014, any batch designated as MVNRLM diesel fuel 
must also be designated according to one of the following three sulfur 
level specifications:
    (A) 15 ppm if its sulfur content is less than or equal to 15 ppm.
    (B) 500 ppm if its sulfur content is less than or equal to 500 ppm.
    (C) High Sulfur if its sulfur content is greater than 500 ppm.
    (v) From June 1, 2006 through May 31, 2010, any batch designated as 
motor vehicle diesel fuel must also be designated according to one of 
the following two distillation classifications that most accurately 
represents the fuel:
    (A) 1D.
    (B) 2D.
    (C) NP diesel (NP).
    (3) The following restrictions and clarifications apply:
    (i) Prior to June 1, 2006, any batch of MVNRLM not containing 
visible evidence of red dye under Sec. 80.520(b) must be designated as 
motor vehicle diesel fuel.
    (ii) Any distillate fuel containing visible evidence of dye may not 
be designated as motor vehicle diesel fuel unless it is further 
designated as tax exempt motor vehicle diesel fuel.
    (iii) Any distillate containing the marker required pursuant to the 
provisions of Sec. 80.510(d) through (f) must be designated as heating 
oil, except that from June 1, 2010 through May 31, 2012 it may also be 
designated as LM diesel fuel, pursuant to Sec. 80.510(e).
    (iv) Prior to June 1, 2009 all 15 ppm sulfur MVNRLM diesel fuel must 
be designated as motor vehicle diesel fuel. A refiner that has been 
approved as a NRLM diesel fuel small refiner under Sec. 80.551(g) and 
has elected to use the compliance option specified under Sec. 80.554(d) 
may also designate 15 ppm sulfur MVNRLM fuel as NRLM diesel fuel 
beginning June 1, 2006.
    (v) Beginning June 1, 2010 any distillate fuel having a sulfur 
content

[[Page 955]]

greater than 15 ppm may not be designated as motor vehicle diesel fuel.
    (vi) Beginning June 1, 2014, any distillate fuel having a sulfur 
content greater than 15 ppm may not be designated as MVNRLM diesel fuel.
    (vii) Any batch of 1D fuel which is suitable for use as 
MVNRLM and which is also suitable for use as kerosene or jet fuel (i.e., 
commonly referred to as dual use kerosene) may be designated as MVNRLM, 
kerosene, or jet fuel (as applicable).
    (viii) Beginning June 1, 2007, any distillate fuel with a sulfur 
content greater than 500 ppm distributed or intended for distribution in 
the area specified in Sec. 80.510(g)(1), may not be designated as 
MVNRLM diesel fuel.
    (ix) From June 1, 2010 through May 31, 2012, any distillate fuel 
with a sulfur content greater than 15 ppm distributed or intended for 
distribution in the area specified in Sec. 80.510(g)(1), may not be 
designated as NR diesel fuel.
    (x) From June 1, 2012 through May 31, 2014, any distillate fuel with 
a sulfur content greater than 15 ppm distributed or intended for 
distribution in the area specified in Sec. 80.510(g)(1), may not be 
designated as NRLM diesel fuel.
    (xi) Beginning June 1, 2007, any distillate fuel with a sulfur 
content greater than 500 ppm distributed or intended for distribution in 
the area specified in Sec. 80.510(g)(2) may not be designated as NRLM 
diesel fuel unless EPA has first approved a compliance plan for the 
refiner for segregating the fuel from all other types of NRLM diesel 
fuel from the refinery gate to the ultimate consumer, as specified under 
Sec. 80.554(a)(4).
    (xii) From June 1, 2010 through May 31, 2012, any distillate fuel 
with a sulfur content greater than 15 ppm distributed or intended for 
distribution in the area specified in Sec. 80.510(g)(2) may not be 
designated as NR diesel fuel unless EPA has first approved a compliance 
plan for the refiner for segregating the fuel from all other types of 
NRLM diesel fuel from the refinery gate to the ultimate consumer, as 
specified under Sec. 80.554(b)(4).
    (xiii) From June 1, 2012 through May 31, 2014, any distillate fuel 
with a sulfur content greater than 15 ppm distributed or intended for 
distribution in the area specified in Sec. 80.510(g)(2) may not be 
designated as NRLM diesel fuel unless, EPA has first approved a 
compliance plan for the refiner for segregating the fuel from all other 
types of NRLM diesel fuel from the refinery gate to the ultimate 
consumer, as specified under Sec. 80.554(b)(4).
    (xiv) Beginning June 1, 2014, any distillate fuel with a sulfur 
content greater than 15 ppm may not be designated as MVNRLM diesel fuel.
    (b) Designation requirements for fuel distributors. (1) Pursuant to 
the provisions of paragraphs (b)(2) through (b)(9) of this section, 
beginning June 1, 2006, any distributor shall accurately and clearly 
designate each batch of diesel fuel or distillate fuel for which they 
transfer custody to another facility, including specifying its volume, 
as specified in this paragraph (b). Distributors must also accurately 
and clearly classify such diesel fuel and distillate fuel by sulfur 
content, while it is in their custody between receipt and delivery.
    (2) From June 1, 2006 through May 31, 2009, whenever custody of a 
batch of 15 ppm sulfur motor vehicle diesel fuel is transferred to 
another facility, the entity transferring custody must accurately and 
clearly designate the batch as one of the following and specify its 
volume:
    (i) 1D 15 ppm sulfur motor vehicle diesel fuel.
    (ii) 2D 15 ppm sulfur motor vehicle diesel fuel.
    (iii) Fuel that meets the requirements specified in Sec. 80.616 
which is transferred by a pipeline facility to a terminal facility 
outside of the State of California pursuant to Sec. 80.617(b) may be 
designated as California diesel fuel. Such fuel must subsequently be 
redesignated by the receiving terminal as either 1D or 
2D 15 ppm motor vehicle diesel fuel, or segregated for delivery 
by tank truck to a retail or wholesale purchaser consumer facility 
inside the State of California pursuant to Sec. 80.617(b)(2).
    (iv) NP 15 ppm sulfur motor vehicle diesel fuel.
    (3) From June 1, 2009 through May 31, 2010, whenever custody of a 
batch of 15 ppm sulfur MVNRLM diesel fuel is transferred to another 
facility, the entity transferring custody must accurately and clearly 
designate the batch

[[Page 956]]

as one of the following and specify its volume:
    (i) 1D 15 ppm sulfur motor vehicle diesel fuel.
    (ii) 2D 15 ppm sulfur motor vehicle diesel fuel.
    (iii) 15 ppm sulfur NRLM diesel fuel.
    (iv) Fuel that meets the requirements specified in Sec. 80.616 that 
is transferred by a pipeline facility to a terminal facility outside of 
the State of California pursuant to Sec. 80.617(b) may be designated as 
California diesel fuel. Such fuel must either be redesignated by the 
receiving terminal as either 1D or 2D 15 ppm motor 
vehicle diesel fuel as prescribed in paragraph (b)(9)(xvi) of this 
section, or segregated for delivery by tank truck to a retail or 
wholesale purchaser consumer facility inside the State of California 
pursuant to Sec. 80.617(b)(2).
    (v) NP 15 ppm sulfur motor vehicle diesel fuel.
    (4) From June 1, 2006 through May 31, 2010, whenever custody of a 
batch of undyed, 500 ppm sulfur MVNRLM is transferred to another 
facility, the entity transferring custody must accurately and clearly 
designate the batch as one of the following and specify its volume:
    (i) 1D 500 ppm sulfur motor vehicle diesel fuel;
    (ii) 2D 500 ppm sulfur motor vehicle diesel fuel; or
    (iii) 500 ppm sulfur NRLM diesel fuel.
    (iv) NP 500 ppm sulfur motor vehicle diesel fuel.
    (5) From June 1, 2007 through May 31, 2010, whenever custody of a 
batch of distillate fuel (other than jet fuel, kerosene, No. 4 fuel, or 
fuel for export) having a sulfur content greater than 500 ppm is 
transferred to another facility, the entity transferring custody must 
accurately and clearly designate the batch as one of the following and 
specify its volume:
    (i) High sulfur NRLM diesel fuel (HSNRLM);
    (ii) Heating oil; or
    (iii) Exempt distillate fuels such as fuels that are covered by a 
national security exemption under Sec. 80.606, fuels that are used for 
purposes of research and development pursuant to Sec. 80.607, and fuels 
used in the U.S. Territories pursuant to Sec. 80.608 (including 
additional identifying information).
    (6) From June 1, 2010 through May 31, 2012, whenever custody of a 
batch of distillate fuel (other than jet fuel, kerosene, No. 4 fuel, or 
fuel for export) having a sulfur content greater than 15 ppm is 
transferred to another facility, the entity transferring custody must 
accurately and clearly designate the batch as one of the following and 
specify its volume:
    (i) 500 ppm sulfur NR diesel fuel;
    (ii) 500 ppm sulfur LM diesel fuel;
    (iii) Heating oil; or
    (iv) Exempt distillate fuels such as fuels that are covered by a 
national security exemption under Sec. 80.606, fuels that are used for 
purposes of research and development pursuant to Sec. 80.607, and fuels 
used in the U.S. Territories pursuant to Sec. 80.608 (including 
additional identifying information).
    (7) From June 1, 2012 through May 31, 2014, whenever custody of a 
batch of distillate fuel (other than jet fuel, kerosene, No. 4 fuel, or 
fuel for export) having a sulfur content greater than 15 ppm is 
transferred to another facility, the entity transferring custody must 
accurately and clearly designate the batch as one of the following and 
specify its volume:
    (i) 500 ppm sulfur NRLM diesel fuel;
    (ii) Heating oil; or
    (iii) Exempt distillate fuels such as fuels that are covered by a 
national security exemption under Sec. 80.606, fuels that are used for 
purposes of research and development pursuant to Sec. 80.607, and fuels 
used in the U.S. Territories pursuant to Sec. 80.608 (including 
additional identifying information).
    (8) Beginning June 1, 2014, whenever custody of a batch of 
distillate fuel (other than jet fuel, kerosene, No. 4 fuel, or fuel for 
export) having a sulfur content greater than 15 ppm is transferred to 
another facility, the entity transferring custody must accurately and 
clearly designate the batch as one of the following and specify its 
volume:
    (i) 500 ppm sulfur LM diesel fuel;
    (ii) Heating oil; or
    (iii) Exempt distillate fuels such as fuels that are covered by a 
national security exemption under Sec. 80.606, fuels that are used for 
purposes of research and development pursuant to Sec. 80.607,

[[Page 957]]

and fuels used in the U.S. Territories pursuant to Sec. 80.608 
(including additional identifying information).
    (9) The following restrictions and clarifications apply. Subject to 
the provisions of this paragraph (b)(9) and subject to the dye and 
marker provisions of Sec. 80.520(b) and Sec. 80.510(d) through (f), 
when custody of a batch of distillate fuel is transferred, the 
designation provided by the entity transferring custody pursuant to 
paragraphs (b)(1) through (b)(8) of this section may be different from 
the designation of the fuel when that same entity received custody.
    (i) Any 500 ppm sulfur diesel fuel designated under this paragraph 
(b) and containing visible evidence of red dye may not be designated as 
motor vehicle diesel fuel.
    (ii) Any distillate fuel containing greater than or equal to 0.10 
milligrams per liter of marker solvent yellow 124 required under Sec. 
80.510(d), (e), or (f) must be designated as heating oil except that 
from June 1, 2010 through October 1, 2012 it may also be designated as 
LM diesel fuel as specified under Sec. 80.510(e).
    (iii) Any batch of 1D fuel which is suitable for use as 
MVNRLM diesel fuel and which is also suitable for use as kerosene or jet 
fuel (i.e., commonly referred to as dual use kerosene) may be designated 
as either MVNRLM diesel fuel, kerosene, or jet fuel (as applicable).
    (iv) Any MVNRLM diesel fuel with a sulfur content of 500 ppm or less 
in inventory as of June 1, 2007 may be designated as motor vehicle 
diesel fuel.
    (v) Batches or portions of batches of fuel received designated as 15 
ppm sulfur 2D motor vehicle diesel fuel may be re-designated as 
500 ppm sulfur motor vehicle diesel fuel, but only in accordance with 
the limitations of Sec. 80.527(c).
    (vi) Batches or portions of batches received designated as 500 ppm 
sulfur NRLM diesel fuel may be re-designated as 500 ppm sulfur motor 
vehicle diesel fuel by a truck loading terminal only if the terminal 
maintains a neutral or positive balance at the end of each quarterly 
compliance period on their motor vehicle diesel fuel volume from June 1, 
2006 as calculated in Sec. 80.599(b)(4).
    (vii) Batches or portions of batches received designated as 500 ppm 
sulfur NRLM diesel fuel may be re-designated as 500 ppm sulfur motor 
vehicle diesel fuel by a facility other than a truck loading terminal 
only if the following restrictions are met:
    (A) At the end of each annual compliance period, the facility has a 
neutral or positive balance on its motor vehicle diesel fuel volume from 
June 1, 2007 as calculated in Sec. 80.599(b)(4); and
    (B) At the end of each annual compliance period, the facility's 
balance for motor vehicle diesel fuel volume, from the beginning of the 
compliance period must be less than two percent of the total volume of 
motor vehicle diesel fuel received during the compliance period, as 
calculated in Sec. 80.599(b)(5).
    (viii) For facilities in areas other than those specified in Sec. 
80.510(g)(1) and (g)(2), batches or portions of batches of unmarked 
distillate received designated as heating oil may be re-designated as 
NRLM or LM diesel fuel only if the following restrictions are met:
    (A) From June 1, 2007 through May 31, 2010, for any compliance 
period, the volume of high sulfur NRLM diesel fuel delivered from a 
facility cannot be greater than the volume received, unless the volume 
of heating oil delivered from the facility is also greater than the 
volume it received by an equal or greater proportion, as calculated in 
Sec. 80.599(c)(2); and
    (B) Beginning June 1, 2010, for any compliance period, the volume of 
fuel designated as heating oil delivered from a facility cannot be less 
than the volume of fuel designated as heating oil received, as 
calculated in Sec. 80.599(c)(4).
    (ix) For facilities in areas other than those specified in Sec. 
80.510(g)(1) and (g)(2), from June 1, 2010 through May 31, 2012, batches 
or portions of batches received designated as 500 ppm LM diesel fuel may 
be redesignated as 500 ppm NR diesel fuel only if for any compliance 
period the following restrictions are met:
    (A) The volume of fuel designated as 500 ppm sulfur NR diesel fuel 
delivered from the facility cannot be greater

[[Page 958]]

than the volume received as calculated in Sec. 80.599(d)(2)(i); or
    (B) The volume of fuel designated as 500 ppm sulfur NR diesel fuel 
delivered from the facility in relation to the volume received is not a 
greater proportion than the volume of fuel designated as 500 ppm sulfur 
LM diesel fuel delivered from the facility in relation to the volume 
received, as calculated in Sec. 80.599(d)(2)(ii).
    (x) Notwithstanding the provisions of paragraph (b)(5) of this 
section, beginning October 1, 2007,
    (A) No distillate fuel with a sulfur content greater than 500 ppm 
distributed or intended for distribution in the areas specified in Sec. 
80.510(g)(1) and (g)(2), may be designated as NRLM diesel fuel, 
including LM diesel fuel except as provided in paragraph (b)(9)(xiii) of 
this section; and
    (B) Distillate fuel with a sulfur content greater than 500 ppm 
distributed from within the areas specified in Sec. 80.510(g)(1) and 
(g)(2) to areas outside these areas is subject to the provisions of 
paragraph (b)(5) of this section.
    (xi) Notwithstanding the provisions of paragraphs (b)(6) through 
(b)(8) of this section, beginning October 1, 2010--
    (A) No distillate fuel with a sulfur content greater than 15 ppm 
distributed or intended for distribution in the areas specified in Sec. 
80.510(g)(1) and (g)(2), may be designated as NR diesel fuel, except as 
provided in paragraph (b)(9)(xiv) of this section; and
    (B) Distillate fuel with a sulfur content greater than 15 ppm 
distributed from within the areas specified in Sec. 80.510(g)(1) and 
(g)(2) to areas outside these areas is subject to the provisions of 
paragraphs (b)(6) through (b)(7) of this section.
    (xii) Notwithstanding the provisions of paragraphs (b)(7) and (8) of 
this section, beginning October 1, 2012--
    (A) No distillate fuel with a sulfur content greater than 15 ppm 
distributed or intended for distribution in the areas specified in Sec. 
80.510(g)(1) and (g)(2), may be designated as NRLM diesel fuel, 
including LM diesel fuel, except as provided in paragraph (b)(9)(xv) of 
this section; and
    (B) Distillate fuel with a sulfur content greater than 15 ppm 
distributed from within the areas specified in Sec. 80.510(g)(1) and 
(g)(2) to areas outside these areas is subject to the provisions of 
paragraphs (b)(7) and (8) of this section.
    (xiii) From June 1, 2007 through September 30, 2010, in the area 
specified in Sec. 80.510(g)(2) only segregated batches of distillate 
fuel received designated as HSNRLM diesel fuel may be distributed 
designated as HSNRLM diesel fuel and must remain segregated from fuel 
with any other designations unless otherwise approved by EPA in a 
refiner compliance plan under Sec. 80.554(a)(4).
    (xiv) From June 1, 2010 through September 30, 2012, in the area 
specified in Sec. 80.510(g)(2) only segregated batches of distillate 
fuel received designated as 500 ppm sulfur NR diesel fuel may be 
distributed designated as 500 ppm sulfur NR diesel fuel and must remain 
segregated from fuel with any other designations and from any other 500 
ppm sulfur NRLM diesel fuel from any other sources, except as approved 
by EPA in a refiner compliance plan under Sec. 80.554(a)(4).
    (xv) From June 1, 2012 through September 30, 2014, in the area 
specified in Sec. 80.510(g)(2) only segregated batches of distillate 
fuel received designated as 500 ppm sulfur NRLM diesel fuel may be 
distributed designated as 500 ppm sulfur NRLM diesel fuel and must 
remain segregated from fuel with any other designations and from any 
other 500 ppm sulfur NRLM diesel fuel from any other sources, except as 
approved by EPA in a refiner compliance plan under Sec. 80.554(a)(4).
    (xvi) Fuel designated as California diesel fuel under paragraph 
(b)(3)(iv) of this section that is received by a terminal facility 
pursuant to the provisions of Sec. 80.617(b)(1) must be redesignated as 
either 1D or 2D 15 ppm motor vehicle diesel fuel as 
prescribed in paragraph (b)(9)(xvi) of this section, or segregated for 
delivery by tank truck to a retail or wholesale purchaser consumer 
facility inside the State of California pursuant to Sec. 80.617(b)(2).
    (c) Notwithstanding the provisions of paragraph (b) of this section, 
an entity is not required to designate heating oil that is delivered 
from a facility that only receives heating oil which is

[[Page 959]]

marked pursuant to Sec. 80.510(d) through (f).
    (d) Notwithstanding the provisions of paragraph (b)(4) of this 
section, an entity is not required to designate 500 ppm sulfur MVNRLM 
diesel fuel that is delivered from a facility that only receives 500 ppm 
sulfur MVNRLM diesel fuel on which taxes have been paid or into which 
red dye has been added pursuant to Sec. 80.520(b).
    (e) Notwithstanding the provisions of paragraph (b)(6) of this 
section, an entity is not required to designate 500 ppm sulfur LM diesel 
fuel that is delivered from a facility that only receives 500 ppm sulfur 
LM diesel fuel which is marked pursuant to Sec. 80.510(e).
    (f) Any entity that is both a distributor and a refiner or importer 
must comply with the provisions of paragraph (a) of this section for all 
distillate fuel produced or imported, and the provisions of paragraph 
(b) of this section for all distillate fuel for which it acted as 
distributor but not refiner or importer.
    (g) No refiner, importer, or distributor may use the designation 
provisions of this section to circumvent the standards or requirements 
of Sec. 80.510, 80.511, or 80.520.

[69 FR 39191, June 29, 2004, as amended at 70 FR 70511, Nov. 22, 2005; 
71 FR 25720, May 1, 2006]



Sec. 80.599  How do I calculate volume balances for designation purposes?

    (a) Quarterly compliance periods. The quarterly compliance periods 
are shown in the following table:

------------------------------------------------------------------------
  Beginning date of quarterly compliance      Ending date of  quarterly
                  period                          compliance period
------------------------------------------------------------------------
June 1, 2006..............................  September 30, 2006.
October 1, 2006...........................  December 31, 2006.
January 1, 2007...........................  March 31, 2007.
April 1, 2007.............................  May 31, 2007.
June 1, 2007..............................  September 30, 2007.
October 1, 2007...........................  December 31, 2007.
January 1, 2008...........................  March 31, 2008.
April 1, 2008.............................  June 30, 2008.
July 1, 2008..............................  September 30, 2008.
October 1, 2008...........................  December 31, 2008.
January 1, 2009...........................  March 31, 2009.
April 1, 2009.............................  June 30, 2009.
July 1, 2009..............................  September 30, 2009.
October 1, 2009...........................  December 31, 2009.
January 1, 2010...........................  March 31, 2010.
April 1, 2010.............................  May 31, 2010.
June 1, 2010..............................  September 30, 2010.
------------------------------------------------------------------------

    (1) Annual compliance periods. The annual compliance periods before 
theperiod beginning July 1, 2016 are shown in the following table:

------------------------------------------------------------------------
   Beginning date of  annual compliance         Ending date of annual
                  period                          compliance period
------------------------------------------------------------------------
June 1, 2006..............................  May 31, 2007.
June 1, 2007..............................  June 30, 2008.
July 1, 2008..............................  June 30, 2009.
July 1, 2009..............................  May 31, 2010.
June 1, 2010..............................  June 30, 2011.
July 1, 2011..............................  May 31, 2012.
June 1, 2012..............................  June 30, 2013.
July 1, 2013..............................  May 31, 2014.
June 1, 2014..............................  June 30, 2015.
------------------------------------------------------------------------

    (2) The annual compliance periods for the period beginning July 1, 
2015 shall be from July 1, through June 30.
    (b) Volume balance for motor vehicle diesel fuel. (1) A facility's 
motor vehicle diesel fuel volume balance is calculated as follows:

MVB = MVI-MVO-MVINVCHG

Where:

MVB = the volume balance for motor vehicle diesel fuel for the 
compliance period.
MVI = the total volume of all batches of fuel designated as 
motor vehicle diesel fuel received for the compliance period. Any motor 
vehicle diesel fuel produced by or imported into the facility shall also 
be included in this volume.
MVO = the total volume of all batches of fuel designated as 
motor vehicle diesel fuel delivered for the compliance period.
MVINVCHG = the total volume of 15 ppm sulfur and 500 ppm 
sulfur motor vehicle diesel fuel in inventory at the end of the 
compliance period minus the total volume of 15 ppm sulfur and 500 ppm 
sulfur motor vehicle diesel fuel in inventory at the beginning of the 
compliance period, including accounting for any corrections in inventory 
due to volume swell or shrinkage, difference in measurement calibration 
between receiving and delivering meters, and similar matters, where 
corrections that increase inventory are defined as positive.

    (2) Calculate the motor vehicle diesel fuel received, as follows:

MVI = MV15I + MV500I

Where:

MV15I = the total volume of all the batches of fuel 
designated as 15 ppm sulfur motor vehicle diesel fuel received for the 
compliance period. Any motor vehicle diesel fuel produced by or imported 
into the facility shall also be included in this volume. Any untaxed and 
undyed California diesel fuel received by a terminal pursuant to Sec. 
80.617 (b)(1) shall be included in this volume.

[[Page 960]]

MV500I = the total volume of all batches of fuel designated 
as 500 ppm sulfur motor vehicle diesel fuel received for the compliance 
period. Any motor vehicle diesel fuel produced by or imported into the 
facility shall also be included in this volume.

    (3) Calculate the motor vehicle diesel fuel delivered, as follows:

MVO = MV15O + MV500O

Where:

MV15O = the total volume of all batches of fuel designated as 
15 ppm sulfur motor vehicle diesel fuel and delivered during the 
compliance period.
MV500O = the total volume of all batches of fuel designated 
as 500 ppm sulfur motor vehicle diesel fuel and delivered during the 
compliance period.

    (4) The neutral or positive volume balance required for purposes of 
compliance with Sec. 80.598(b)(9)(vi) and (b)(9)(vii)(A) means that the 
net balance of motor vehicle diesel fuel in inventory as of the end of 
the last day of the compliance period (MVNBE) must be greater 
than or equal to zero. MVNBE is defined by the following equation:

MVNBE = MV15BINV + MV500BINV + 
    [Sigma]MVB

Where:

MV15BINV = the total volume of fuel designated as 15 ppm 
sulfur motor vehicle diesel fuel in inventory at the beginning of the 
program on June 1, 2006.
MV500BINV = the total volume of fuel designated as 500 ppm 
sulfur motor vehicle diesel fuel in inventory at the beginning of the 
program on June 1, 2006. Any 2D 500 ppm sulfur MVNRLM in 
inventory at the beginning of the program on June 1, 2006 may be 
designated as motor vehicle diesel fuel.
[Sigma]MVB = the sum of the balances for motor vehicle diesel fuel for 
the current compliance period and previous compliance periods.

    (5) The volume balance required for purposes of compliance with 
Sec. 80.598(b)(9)(vii)(B) means:

-MVB <= 0.02 x MVI

    (6) Calculations in paragraphs (b)(4) and (b)(5) of this section may 
be combined for all facilities wholly owned by an entity.
    (7) For purposes of calculations in paragraphs (b)(1) through (b)(5) 
of this section, for batches of fuel received from facilities without an 
EPA facility ID, any batches of fuel received on which taxes 
have been paid pursuant to IRS code (26 CFR part 48) shall be deemed to 
be MV15I or MV500I as appropriate for purposes of 
this paragraph.
    (c) Volume balance for high sulfur NRLM diesel fuel and heating oil. 
(1) A facility's high sulfur NRLM balance is calculated as follows:

HSNRLMB = HSNRLMII - HSNRLMO - 
    HSNRLMINVCHG

Where:

HSNRLMB = the balance for high sulfur NRLM diesel fuel for the 
compliance period.
HSNRLMI = the total volume of all batches of fuel designated 
as high sulfur NRLM received diesel fuel for the compliance period. Any 
high sulfur NRLM produced by or imported into the facility shall also be 
included in this volume.
HSNRLMO = the total volume of all batches of fuel designated 
as high sulfur NRLM diesel fuel delivered for the compliance period.
HSNRLMINVCHG = the volume of high sulfur NRLM diesel fuel in 
inventory at the end of the compliance period minus the volume of high 
sulfur NRLM diesel fuel in inventory at the beginning of the compliance 
period, including accounting for any corrections in inventory due to 
volume swell or shrinkage, difference in measurement calibration between 
receiving and delivering meters, and similar matters, where corrections 
that increase inventory are defined as positive.

    (2) The volume balance required for purposes of compliance with 
Sec. 80.598(b)(9)(viii)(A) means one of the following:

(i) HSNRLMB = 0

(ii) (HSNRLMO + HSNRLMINVCHG) / HSNRLMI 
    <= (HOO + HOINVCHG) / HOI

    (3) A facility's heating oil volume balance is calculated as 
follows:

HOB = HOI - HOO - HOINVCHG

Where:

HOB = the balance for heating oil for the compliance period.
HOI = the total volume of all batches of fuel designated as 
heating oil received for the compliance period. Any heating oil produced 
by or imported into the facility shall also be included in this volume.
HOO = the total volume of all batches of fuel designated as 
heating oil delivered to all downstream entities for the compliance 
period.

[[Page 961]]

HOINVCHG = the volume of heating oil in inventory at the end 
of the compliance period minus the volume of heating oil in inventory at 
the beginning of the compliance period, including accounting for any 
corrections in inventory due to volume swell or shrinkage, difference in 
measurement calibration between receiving and delivering meters, and 
similar matters, where corrections that increase inventory are defined 
as positive.

    (4) The volume balance required for purposes of compliance with 
Sec. 80.598(b)(9)(viii)(B) means:

HOB <= 0

    (5) Calculations in paragraphs (c)(3) and (c)(4) of this section may 
be combined for all facilities wholly owned by an entity.
    (6) For purposes of calculations in paragraphs (c)(1) through (c)(4) 
of this section, for batches of fuel received from facilities without an 
EPA facility ID, any batches of fuel received marked pursuant 
to Sec. 80.510(d) or (f) shall be deemed to be HOI, any 
batches of fuel received marked pursuant to Sec. 80.510(e) shall be 
deemed to be HOI or LM500I, any diesel fuel with 
less than or equal to 500 ppm sulfur that is dyed pursuant to Sec. 
80.520(b) and not marked pursuant to Sec. 80.510(d) or (f) shall be 
deemed to be NRLM diesel fuel, and any diesel fuel with less than or 
equal to 500 ppm sulfur which is dyed pursuant to Sec. 80.520(b) and 
not marked pursuant to Sec. 80.510(e) shall be deemed to be NR diesel 
fuel.
    (d) Volume balance for NR diesel fuel. (1) A facility's 500 ppm 
nonroad diesel fuel balance is calculated as follows:

NR500B = NR500I - NR500O - NR500INVCHG

Where:

NR500B = the balance for 500 ppm sulfur NR diesel fuel for the 
compliance period.
NR500I = the total volume of all batches of fuel designated 
as 500 ppm sulfur NR diesel fuel received for the compliance period. Any 
500 ppm sulfur NR diesel fuel produced by or imported into the facility 
shall also be included in this volume.
NR500O = the total volume of all batches of fuel designated 
as 500 ppm sulfur NR diesel fuel delivered for the compliance period.
NR500INVCHG = the volume of 500 ppm sulfur NR diesel fuel in 
inventory at the end of the compliance period minus the volume of 500 
ppm sulfur NR diesel fuel in inventory at the beginning of the 
compliance period, and accounting for any corrections in inventory due 
to volume swell or shrinkage, difference in measurement calibration 
between receiving and delivering meters, and similar matters, where 
corrections that increase inventory are defined as positive.

    (2) The volume balance required for purposes of compliance with 
Sec. 80.598(b)(9)(ix) means one of the following:

(i) NR500B = 0

(ii) (NR500O + NR500INVCHG) / NR500I <= 
    (LM500O + LM500INVCHG) / LM500I.

Where:

LM500I = the total volume of all batches of fuel designated 
as 500 ppm sulfur LM diesel fuel received for the compliance period. Any 
500 ppm sulfur LM diesel fuel produced by or imported into the facility 
shall also be included in this volume.
LM500O = the total volume of all batches of fuel designated 
as 500 ppm sulfur LM diesel fuel delivered for the compliance period.
LM500INVCHG = the volume of 500 ppm sulfur LM diesel fuel in 
inventory at the end of the compliance period minus the volume of 500 
ppm sulfur LM diesel fuel in inventory at the beginning of the 
compliance period, and accounting for any corrections in inventory due 
to volume swell or shrinkage, difference in measurement calibration 
between receiving and delivering meters, and similar matters, where 
corrections that increase inventory are defined as positive.

    (e) Anti-downgrading for motor vehicle diesel fuel. (1) A facility 
must satisfy the provisions in either paragraphs (e)(2), (e)(3), (e)(4), 
or (e)(5) of this section to comply with the anti-downgrading limitation 
of paragraph Sec. 80.527(c)(1), for the annual compliance periods 
defined in Sec. 80.527(c)(3).
    (2) The volume of 2D 15 ppm sulfur motor vehicle delivered 
must meet the following requirement:

(2MV15O + 2MV15INVCHG) 
= 0.8 * 2MV15I

Where:

2MV15O = the total volume of fuel delivered during 
the compliance period that is designated as 2D 15 ppm sulfur 
motor vehicle diesel fuel.
2MV15INVCHG = the total volume of diesel fuel 
designated as 2D 15 ppm sulfur motor vehicle diesel fuel in 
inventory at the end of the compliance period minus the total volume of 
2D 15 ppm sulfur motor vehicle diesel fuel in inventory at the 
beginning of the compliance period, and accounting for any corrections 
in inventory due to volume

[[Page 962]]

swell or shrinkage, difference in measurement calibration between 
receiving and delivering meters, and similar matters, where corrections 
that increase inventory are defined as positive.
2MV15I = the total volume of fuel received during 
          the compliance period that is designated as 2D 15 ppm 
          sulfur motor vehicle diesel fuel. Any untaxed and undyed 
          California diesel fuel received by a terminal pursuant to 
          Sec. 80.617(b)(1) shall be included in this volume.

    (3) The volume of 2D 500 ppm sulfur motor vehicle diesel 
fuel delivered must meet the following requirement:

2MV500O <= 2MV500I - 
    2MV500INVCHG + 0.2 * 2MV15I

Where:

2MV500O = the total volume of fuel delivered during 
the compliance period that is designated as 2D 500 ppm sulfur 
motor vehicle diesel fuel.
2MV500I = the total volume of fuel received during 
the compliance period that is designated as 2D 500 ppm sulfur 
motor vehicle diesel fuel.
2MV500INVCHG = the total volume of diesel fuel 
designated as 2D 500 ppm sulfur motor vehicle diesel fuel in 
inventory at the end of the compliance period minus the total volume of 
2D 500 ppm sulfur motor vehicle diesel fuel in inventory at the 
beginning of the compliance period, and accounting for any corrections 
in inventory due to volume swell or shrinkage, difference in measurement 
calibration between receiving and delivering meters, and similar 
matters, where corrections that increase inventory are defined as 
positive.

    (4) The following calculation may be used to account for wintertime 
blending of kerosene and the blending of non-petroleum diesel:

2MV500O < = 2MV500I + 
    2MV500P - 2MV500INVCHG + 0.2 
    * (1MV15I + 2MV15I + 
    NPMV15I)

Where:

1MV15I the total volume of fuel received during the 
compliance period that is designated as 1D 15 ppm sulfur motor 
vehicle diesel fuel. Any motor vehicle diesel fuel produced by or 
imported into the facility shall not be included in this volume.
NPMV15I is the total volume of fuel received during the 
compliance period that is designated as NP15 ppm sulfur motor vehicle 
diesel fuel. Any motor vehicle diesel fuel produced by or imported into 
the facility shall not be included in this volume.
1MV15P = the total volume of fuel produced by or 
imported into the facility during the compliance period that was 
designated as 1D 15 ppm sulfur motor vehicle diesel fuel when 
it was delivered.

    (5) The following calculation may be used to account for wintertime 
blending of kerosene, the blending of non-petroleum diesel, and/or 
changes in the facility's volume balance of motor vehicle diesel fuel 
resulting from a temporary shift of 500 ppm sulfur NRLM diesel fuel to 
500 ppm sulfur motor vehicle diesel fuel during the compliance period:

2MV500O < 2MV500I + 
    2MV500P - 2MV500INVCHG + 0.2 
    * 2MV15I + 1MV15B + 
    2NRLM500S + NPB

Where:

1MV15B = the total volume of fuel received during 
the compliance period that is designated as 1D 15 ppm sulfur 
motor vehicle diesel fuel and that the facility can demonstrate they 
blended into 2D 500 ppm sulfur motor vehicle diesel fuel. Any 
motor vehicle diesel fuel produced by or imported into the facility 
shall not be included in this volume.
2MV500P = the total volume of fuel produced by or 
imported into the facility during the compliance period that was 
designated as 2MV 500 ppm sulfur motor vehicle diesel fuel when 
it was delivered.
2NRLM500S = the total volume of 2D 500 ppm 
sulfur NRLM diesel fuel that the facility can demonstrate they 
redesignated as 2D 500 ppm sulfur motor vehicle diesel fuel 
during the compliance period.
NPB = the total volume of fuel received during the compliance 
period that is designated as NP15 ppm sulfur motor vehicle diesel fuel, 
and/or NP500 ppm sulfur motor vehicle diesel fuel which the facility can 
demonstrate they blended into 2D 500 ppm sulfur motor vehicle 
diesel fuel.

    (f) Inventory adjustments. Adjustments to inventory under this 
section must be based on normal business practices for the industry, 
appropriate physical plant operations and use of good engineering 
judgments.
    (g) Unique circumstances. EPA may, at its discretion, grant a fuel 
distributor's application to modify its inventory of motor vehicle 
diesel fuel, NRLM diesel fuel, or heating oil for a given compliance 
period. EPA may grant an application to address unique circumstances, 
where appropriate, such as the start up of a new pipeline or pipeline 
segment.
    (h) Additional requirements for aggregated facilities consisting of 
a refinery and a truck loading terminal. In addition

[[Page 963]]

to the volume balance requirements required by paragraphs (a) through 
(g) of this section, aggregated facilities consisting of a refinery and 
a truck loading terminal are responsible for balance calculations on the 
volume difference between the total volume of diesel fuel sold over the 
truck loading terminal rack and the production volume from the batch 
reports. Mathematically, the difference will be the volume of fuel 
received from external sources and passed through to another facility.

[69 FR 39194, June 29, 2004, as amended at 70 FR 40896, July 15, 2005; 
70 FR 70511, Nov. 22, 2005; 71 FR 25720, May 1, 2006]



Sec. 80.600  What records must be kept for purposes of the designate
and track provisions?

    (a) In addition to the requirements of Sec. 80.592 and Sec. 
80.602, the following recordkeeping requirements shall apply to refiners 
and importers:
    (1) Any refiner or importer shall maintain the records specified in 
paragraphs (a)(6) through (a)(10) of this section for each batch of 
distillate fuel that it transfers custody of and designates during the 
time period from June 1, 2006 through May 31, 2010, with the following 
categories:
    (i) 1D 15 ppm sulfur motor vehicle diesel fuel;
    (ii) 2D 15 ppm sulfur motor vehicle diesel fuel;
    (iii) 15 ppm sulfur NRLM diesel fuel;
    (iv) 1D 500 ppm sulfur motor vehicle diesel fuel;
    (v) 2D 500 ppm sulfur motor vehicle diesel fuel;
    (vi) 500 ppm sulfur NRLM diesel fuel;
    (vii) NP 15 ppm sulfur motor vehicle diesel fuel;
    (viii) NP 500 ppm sulfur motor vehicle diesel fuel; or,
    (ix) Exempt distillate fuels such as fuels that are covered by a 
national security exemption under Sec. 80.606, fuels that are used for 
purposes of research and development pursuant to Sec. 80.607, and fuels 
used in the U.S. Territories pursuant to Sec. 80.608 (including 
additional identifying information).
    (2) Any refiner or importer shall maintain the records specified in 
paragraphs (a)(6) through (a)(10) of this section for each batch of 
distillate fuel that it transfers custody of and designates during the 
time period from June 1, 2007 through May 31, 2010 with the following 
categories:
    (i) High sulfur NRLM diesel fuel; or
    (ii) Heating oil.
    (3) Any refiner or importer shall maintain the records specified in 
paragraphs (a)(6) through (a)(10) of this section for each batch of 
distillate fuel that it transfers custody of and designates during the 
time period from June 1, 2010 through May 31, 2012 with the following 
categories:
    (i) 500 ppm sulfur NR diesel fuel;
    (ii) 500 ppm sulfur LM diesel fuel;
    (iii) Heating oil; or
    (iv) Exempt distillate fuels such as fuels that are covered by a 
national security exemption under Sec. 80.606, fuels that are used for 
purposes of research and development pursuant to Sec. 80.607, and fuels 
used in the U.S. Territories pursuant to Sec. 80.608 (including 
additional identifying information).
    (4) Any refiner or importer shall maintain the records specified in 
paragraphs (a)(6) through (a)(10) of this section for each batch of 
distillate fuel that it transfers custody of and designates during the 
time period from June 1, 2012 through May 31, 2014 with the following 
categories:
    (i) 500 ppm sulfur NRLM diesel fuel;
    (ii) Heating oil; or
    (iii) Exempt distillate fuels such as fuels that are covered by a 
national security exemption under Sec. 80.606, fuels that are used for 
purposes of research and development pursuant to Sec. 80.607, and fuels 
used in the U.S. Territories pursuant to Sec. 80.608 (including 
additional identifying information).
    (5) Any refiner or importer shall maintain the records specified in 
paragraphs (a)(6) through (a)(10) of this section for each batch of 
heating oil that it transfers custody of and designates during the time 
period from June 1, 2014 and later as belonging to the heating oil 
category.
    (6) The records for each batch with designations identified in 
paragraphs (a)(1) through (a)(5) of this section must clearly and 
accurately identify the batch number (including an indication as to 
whether the batch was received into the facility, produced by the 
facility, imported into the facility,

[[Page 964]]

or delivered from the facility), date and time of day (if multiple 
batches are delivered per day) that custody was transferred, the 
designation, the volume in gallons of the batch, and the name and the 
EPA entity and facility registration number of the facility to whom such 
batch was transferred.
    (7) Any refiner or importer shall, for each of its facilities, 
maintain records that clearly and accurately identify the total volume 
in gallons of designated fuel identified in paragraphs (a)(1) through 
(a)(5) of this section transferred over each compliance period. The 
records shall be maintained separately for each fuel designated in 
paragraphs (a)(1) through (a)(5) of this section, and for each EPA 
entity and facility registration number to whom custody of the fuel was 
transferred.
    (8) Notwithstanding the provisions of paragraphs (a)(6) and (a)(7) 
of this section, records of batches delivered of 500 ppm sulfur motor 
vehicle diesel fuel on which taxes have been paid per Section 4082 of 
the Internal Revenue Code (26 U.S.C. 4082) and of 500 ppm sulfur NRLM 
diesel fuel into which dye has been added per Section 4082 of the 
Internal Revenue Code (26 U.S.C. 4082), and of 500 ppm sulfur LM diesel 
fuel which has been properly marked pursuant to Sec. 80.510(e) are not 
required to be maintained separately for each entity and facility to 
which the fuel was delivered.
    (9) Notwithstanding the provisions of paragraphs (a)(6) and (a)(7) 
of this section, records of heating oil batches delivered that have been 
properly marked pursuant to Sec. 80.510(d) through (f) and records of 
LM diesel fuel batches delivered that have been properly marked pursuant 
to Sec. 80.510(e) are not required to be maintained separately for each 
entity and facility to which the fuel was delivered.
    (10) Any refiner or importer shall maintain copies of all product 
transfer documents required under Sec. 80.590. If all information 
required in paragraph (a)(6) of this section is on the product transfer 
document for a batch, then the provisions of this paragraph (a)(10) 
shall satisfy the requirements of paragraph (a)(6) of this section for 
that batch.
    (11) Any refiner or importer shall maintain records related to 
annual compliance calculations performed under Sec. 80.599 and to 
information required to be reported to the Administrator under Sec. 
80.601.
    (12) Records must be maintained that demonstrate compliance with a 
refiner's compliance plan required under Sec. 80.554, for distillate 
fuel designated as high sulfur NRLM diesel fuel and delivered from June 
1, 2007 through May 31, 2010, for distillate fuel designated as 500 ppm 
sulfur NR diesel fuel and delivered from June 1, 2010 through May 31, 
2012, and for distillate fuel designated as 500 ppm sulfur NRLM diesel 
fuel and delivered from June 1, 2012 through June 1, 2014 in the areas 
specified in Sec. 80.510(g)(2).
    (13) Refiners and importers who also receive fuel from another 
facility must also comply with the requirements of paragraph (b) of this 
section separately for those volumes.
    (b) In addition to the requirements of Sec. 80.592 and Sec. 
80.602, the following recordkeeping requirements shall apply to 
distributors:
    (1) Any distributor shall maintain the records specified in 
paragraphs (b)(2) through (b)(10) of this section for each batch of 
distillate fuel with the following designations for which custody is 
received or delivered as well as any batches produced. Records shall be 
kept separately for each of its facilities.
    (i) For each facility that receives or distributes 2D 15 
ppm sulfur motor vehicle diesel fuel or 2D 500 ppm sulfur motor 
vehicle diesel fuel, records for each batch of diesel fuel with the 
following designations for which custody is received or delivered during 
the time period from June 1, 2006 through May 31, 2007:
    (A) 1D 15 ppm sulfur motor vehicle diesel fuel;
    (B) 2D 15 ppm sulfur motor vehicle diesel fuel;
    (C) 1D 500 ppm sulfur motor vehicle diesel fuel;
    (D) 2D 500 ppm sulfur motor vehicle diesel fuel;
    (E) California diesel fuel as defined in Sec. 80.616 which is 
transferred out of the State of California pursuant to the provisions of 
Sec. 80.617(b);

[[Page 965]]

    (F) NP 15 ppm sulfur motor vehicle diesel fuel;
    (G) NP 500 ppm sulfur motor vehicle diesel fuel; or
    (H) Exempt distillate fuels such as fuels that are covered by a 
national security exemption under Sec. 80.606, fuels that are used for 
purposes of research and development pursuant to Sec. 80.607, and fuels 
used in the U.S. Territories pursuant to Sec. 80.608 (including 
additional identifying information).
    (ii) For each facility, records for each batch of diesel fuel with 
the following designations for which custody is received or delivered as 
well as any batches produced during the time period from June 1, 2007 
through May 31, 2010:
    (A) 1D 15 ppm sulfur motor vehicle diesel fuel;
    (B) 2D 15 ppm sulfur motor vehicle diesel fuel;
    (C) 1D 500 ppm sulfur motor vehicle diesel fuel;
    (D) 2D 500 ppm sulfur motor vehicle diesel fuel;
    (E) 500 ppm sulfur NRLM diesel fuel;
    (F) 15 ppm sulfur NRLM diesel fuel;
    (G) High sulfur NRLM diesel fuel;
    (H) Heating oil;
    (I) California diesel fuel as defined in Sec. 80.616 which is 
transferred out of the State of California pursuant to the provisions of 
Sec. 80.617(b);
    (J) NP 15 ppm sulfur motor vehicle diesel fuel;
    (K) NP 500 ppm sulfur motor vehicle diesel fuel; or
    (L) Exempt distillate fuels such as fuels that are covered by a 
national security exemption under Sec. 80.606, fuels that are used for 
purposes of research and development pursuant to Sec. 80.607, and fuels 
used in the U.S. Territories pursuant to Sec. 80.608 (including 
additional identifying information).
    (iii) For each facility that receives unmarked fuel designated as NR 
diesel fuel, LM diesel fuel or heating oil, records for each batch of 
diesel fuel with the following designations for which custody is 
received or delivered as well as any batches produced during the time 
period from June 1, 2010 through May 31, 2012:
    (A) 500 ppm sulfur NR diesel fuel;
    (B) 500 ppm sulfur LM diesel fuel;
    (C) Heating oil; or
    (D) Exempt distillate fuels such as fuels that are covered by a 
national security exemption under Sec. 80.606, fuels that are used for 
purposes of research and development pursuant to Sec. 80.607, and fuels 
used in the U.S. Territories pursuant to Sec. 80.608 (including 
additional identifying information).
    (iv) For each facility that receives unmarked fuel designated as 
heating oil, records for each batch of diesel fuel with the following 
designations for which custody is received or delivered as well as any 
batches produced during the time period from June 1, 2012 through May 
31, 2014:
    (A) 500 ppm sulfur NRLM diesel fuel;
    (B) Heating oil; or
    (C) Exempt distillate fuels such as fuels that are covered by a 
national security exemption under Sec. 80.606, fuels that are used for 
purposes of research and development pursuant to Sec. 80.607, and fuels 
used in the U.S. Territories pursuant to Sec. 80.608 (including 
additional identifying information).
    (v) For each facility that receives unmarked fuel designated as 
heating oil, records for each batch of diesel fuel with the following 
designations for which custody is received or delivered as well as any 
batches produced during the time period beginning June 1, 2014:
    (A) 500 ppm sulfur LM diesel fuel;
    (B) Heating oil; or
    (C) Exempt distillate fuels such as fuels that are covered by a 
national security exemption under Sec. 80.606, fuels that are used for 
purposes of research and development pursuant to Sec. 80.607, and fuels 
used in the U.S. Territories pursuant to Sec. 80.608 (including 
additional identifying information).
    (vi) From June 1, 2007 through May 31, 2010, for those facilities in 
the areas specified in Sec. 80.510(g)(2) that receive unmarked fuel 
designated as high sulfur NRLM diesel fuel:
    (A) High sulfur NRLM diesel fuel;
    (B) Heating oil; or
    (C) Exempt distillate fuels such as fuels that are covered by a 
national security exemption under Sec. 80.606, fuels that are used for 
purposes of research and development pursuant to Sec. 80.607, and fuels 
used in the U.S. Territories pursuant to Sec. 80.608 (including 
additional identifying information).

[[Page 966]]

    (vii) From June 1, 2010 through May 31, 2012, for those facilities 
in the areas specified in Sec. 80.510(g)(2) that receive unmarked fuel 
designated as 500 ppm sulfur NR diesel fuel, 500 ppm sulfur LM diesel 
fuel, or heating oil:
    (A) 500 ppm sulfur NR diesel fuel;
    (B) 500 ppm sulfur LM diesel fuel;
    (C) Heating oil; or
    (D) Exempt distillate fuels such as fuels that are covered by a 
national security exemption under Sec. 80.606, fuels that are used for 
purposes of research and development pursuant to Sec. 80.607, and fuels 
used in the U.S. Territories pursuant to Sec. 80.608 (including 
additional identifying information).
    (viii) From June 1, 2012 through May 31, 2014, for those facilities 
in the areas specified in Sec. 80.510(g)(2) that receive unmarked fuel 
designated as 500 ppm sulfur NRLM diesel fuel or heating oil.
    (A) 500 ppm sulfur NRLM diesel fuel;
    (B) Heating oil; or
    (C) Exempt distillate fuels such as fuels that are covered by a 
national security exemption under Sec. 80.606, fuels that are used for 
purposes of research and development pursuant to Sec. 80.607, and fuels 
used in the U.S. Territories pursuant to Sec. 80.608 (including 
additional identifying information).
    (2) Records that for each batch clearly and accurately identify the 
batch number (including an indication as to whether the batch was 
received into the facility, produced by the facility, imported into the 
facility, or delivered from the facility), date and time of day (if 
multiple batches are delivered per day) that custody was transferred, 
the designation, the volume in gallons of each batch of each fuel, and 
the name and the EPA entity and facility registration number of the 
facility to whom or from whom such batch was transferred.
    (3) Records that clearly and accurately identify the total volume in 
gallons of each designated fuel identified under paragraph (b)(1) of 
this section transferred over each of the compliance periods, and over 
the periods from June 1, 2006 to the end of each compliance period. The 
records shall be maintained separately for each fuel designated under 
paragraph (b)(1) of this section, and for each EPA entity and facility 
registration number from whom the fuel was received or to whom it was 
delivered. For batches of fuel received from facilities without an EPA 
facility registration number, any batches of fuel received marked 
pursuant to Sec. 80.510(d) or (f) shall be deemed designated as heating 
oil, any batches of fuel received marked pursuant to Sec. 80.510(e) 
shall be deemed designated as heating oil or LM diesel fuel, any batches 
of fuel received on which taxes have been paid pursuant to Section 4082 
of the Internal Revenue Code (26 U.S.C. 4082) shall be deemed designated 
as motor vehicle diesel fuel, any 500 ppm sulfur diesel fuel dyed 
pursuant to Sec. 80.520(b) and not marked pursuant to Sec. 80.510(d) 
or (f) shall be deemed designated as NRLM diesel fuel, and any diesel 
fuel with less than or equal to 500 ppm sulfur which is dyed pursuant to 
Sec. 80.520(b) and not marked pursuant to Sec. 80.510(e) shall be 
deemed to be NR diesel fuel.
    (4) Notwithstanding the provisions of paragraphs (b)(2) and (b)(3) 
of this section, for batches of 500 ppm sulfur motor vehicle diesel fuel 
delivered on which taxes have been paid per Section 4082 of the Internal 
Revenue Code (26 U.S.C. 4082) and 500 ppm sulfur NRLM diesel fuel into 
which red dye has been added per Section 4082 of the Internal Revenue 
Code (26 U.S.C. 4082), records are not required to be maintained 
separately for each entity or facility to whom fuel was delivered.
    (5) Notwithstanding the provisions of paragraphs (b)(2) and (b)(3) 
of this section, for batches of heating oil delivered that are marked 
pursuant to Sec. 80.510(d) through (f), records do not need to identify 
the EPA entity or facility registration number to which fuel was 
delivered.
    (6) Notwithstanding the provisions of paragraphs (b)(2) and (b)(3) 
of this section, for batches of LM diesel fuel delivered that are marked 
pursuant to Sec. 80.510(e), records do not need to identify the EPA 
entity or facility registration number to which fuel was delivered.
    (7) Records that clearly and accurately reflect the beginning and 
ending inventory volume for each of the fuels for which records must be 
kept under paragraph (b)(1) of this section. Such records shall be 
maintained separately

[[Page 967]]

by each entity and facility consistent with the compliance periods 
defined in Sec. Sec. 80.598 and 80.599.
    (8) (i) If adjustments are made to inventory, the records must 
include detailed information related to the amount, type of, and reason 
for such adjustment.
    (ii) If adjustments are made because of measurement error or 
variation, the records must include the adjustment made, the meter or 
gauge or other reading(s), and the name of the person who took such 
reading(s) and or applied the adjustment.
    (9) For distributors that are required to keep records under 
paragraphs (b)(1) through (b)(8) of this section for truck loading 
terminals, records related to quarterly or annual compliance 
calculations, as applicable, performed under Sec. 80.599 and to 
information required to be reported to the Administrator under Sec. 
80.601.
    (10) For distributors that are required to keep records under 
paragraphs (b)(1) through (b)(8) of this section for facilities other 
than truck loading terminals, records related to annual compliance 
calculations performed under Sec. 80.599 and to information required to 
be reported to the Administrator under Sec. 80.601.
    (c) Notwithstanding the provisions of paragraph (b) of this section, 
records of heating oil received are not required to be maintained for 
facilities that do not receive any heating oil which is unmarked 
pursuant to Sec. 80.510(d) through (f), or LM diesel fuel which is 
unmarked pursuant to Sec. 80.510(e).
    (d) Notwithstanding the provisions of paragraph (b) of this section, 
records of 500 ppm sulfur MVNRLM diesel fuel received are not required 
to be maintained for facilities that do not receive any motor vehicle 
diesel fuel for which taxes have not already been paid pursuant to 
Section 4082 of the Internal Revenue Code (26 U.S.C. 4082) or NRLM 
diesel fuel which is undyed pursuant to Sec. 80.520(b).
    (e) The provisions of paragraphs (b)(1)(iii) and (iv) of this 
section do not apply to facilities located in the areas specified in 
Sec. 80.510(g)(1) and (g)(2) unless they deliver marked heating oil or 
LM diesel fuel to areas outside the areas specified in Sec. 
80.510(g)(1) and (g)(2).
    (f) Ultimate consumers that receive any batch of high sulfur NRLM 
diesel fuel beginning June 1, 2007 in areas listed in Sec. 80.510(g)(2) 
must maintain records of each batch of fuel received for use in NRLM 
equipment pursuant to the compliance plan provisions of Sec. 80.554, 
unless otherwise allowed by EPA.
    (g) Ultimate consumers that receive any batch of 500 ppm sulfur NR 
diesel fuel beginning June 1, 2010 or NRLM diesel fuel beginning June 1, 
2012 in the areas listed in Sec. 80.510(g)(2) must maintain records of 
each batch of fuel received for use in NR or NRLM equipment, as 
appropriate, pursuant to the compliance plan provisions of Sec. 80.554, 
unless otherwise allowed by EPA.
    (h) For purposes of this section, each portion of a shipment of 
designated distillate fuel under this section that is differently 
designated from any other portion, even if shipped as fungible product 
having the same sulfur content, shall be a separate batch.
    (i) Additional records that must be kept by mobile facilities. 
Additional records that must be kept by mobile facilities. Any 
registered mobile facility must keep records of all contracts from any 
contracted components (e.g. tank truck, barge, marine tanker, rail car, 
etc.) in each of its registered mobile facilities.
    (j) The records required in this section must be made available to 
the Administrator or the Administrator's designated representative upon 
request.
    (k) Notwithstanding the provisions of this section, product transfer 
documents must be maintained under the provisions of Sec. Sec. 80.590, 
80.592, and 80.602.
    (l) The records required in this section must be kept for five years 
after they are required to be collected.
    (m) Identifications of fuel designations can be limited to a sub-
designation that accurately identifies the fuel and do not need to also 
include the broader designation. For example, NR diesel fuel does not 
also need to be designated as NRLM or MVNRLM diesel fuel.
    (n) Notwithstanding the provisions of paragraphs (b)(2) and (b)(3) 
of this section, for batches of 15 ppm sulfur motor

[[Page 968]]

vehicle diesel fuel or California diesel fuel under Sec. 80.617(b) on 
which taxes have been paid per Section 4082 of the Internal Revenue Code 
(26 U.S.C. 4082), and 15 ppm sulfur NRLM diesel fuel or California 
diesel fuel under Sec. 80.617(b) into which red dye has been added per 
Section 4082 of the Internal Revenue Code (26 U.S.C. 4082), records are 
not required to be maintained separately for each entity or facility to 
whom fuel was delivered.
    (o) In addition to the requirements of Sec. Sec. 80.592 and 80.602, 
the following recordkeeping requirements shall apply to aggregated 
facilities consisting of a refinery and truck loading terminal:
    (1) Any aggregated facility consisting of a refinery and truck 
loading terminal shall maintain records of the following information for 
each batch of distillate fuel produced by the refinery and sent over the 
aggregated facility's truck loading terminal rack:
    (i) The batch volume;
    (ii) The batch number, assigned under the batch numbering procedures 
under Sec. Sec. 80.65(d)(3) and 80.502(d)(1);
    (iii) The date of production;
    (iv) A record designating the batch as distillate fuel meeting 
either the 500 ppm or 15 ppm sulfur standard; and,
    (v) A record indicating the volumes that were either taxed, dyed, or 
dyed and marked.
    (2) Volume reports for all distillate fuel from external sources 
(i.e., from another refiner or importer), as described in Sec. 
80.601(f)(2), sent over the aggregated facility's truck rack.

[69 FR 39196, June 29, 2004, as amended at 70 FR 40898, July 15, 2005; 
70 FR 70511, Nov. 22, 2005; 71 FR 25721, May 1, 2006]



Sec. 80.601  What are the reporting requirements for purposes of the
designate and track provisions?

    (a) Quarterly compliance period reports. Beginning February 28, 2007 
and continuing through August 31, 2010, each entity required to register 
under Sec. 80.597 and to maintain records under Sec. 80.600 must 
report the following information separately for each of its facilities 
to the Administrator as specified in paragraph (d)(1) of this section 
except as provided in paragraph (e) of this section.
    (l) Separately for each fuel designation category specified in 
paragraphs (a)(1)(i) and (a)(1)(ii) of this section and separately for 
each transferee facility, the total volume in gallons of distillate fuel 
designated under Sec. 80.598 for which custody was delivered by the 
reporting facility to any other entity or facility, and the EPA entity 
and facility registration number(s), as applicable, of the transferee.
    (i) Beginning with the first compliance period and continuing up to 
and including the compliance period that starts April 1, 2007, fuel 
designated as 15 ppm or 500 ppm motor vehicle diesel fuel, or California 
diesel fuel as defined in Sec. 80.616 which is distributed outside the 
State of California pursuant to Sec. 80.617(b).
    (ii) Beginning with the compliance period that starts June 1, 2007 
and continuing up to and including the final reporting period, all fuel 
designation categories.
    (2) Separately for each designation category specified in paragraphs 
(a)(2)(i) and (a)(2)(ii) of this section and separately for each 
transferor facility, the total volume in gallons of distillate fuel 
designated under Sec. 80.598 for which custody was received by the 
reporting facility, and the EPA entity and facility registration 
number(s), as applicable, of the transferor.
    (i) Beginning with the first compliance period and continuing up to 
and including the compliance period that starts April 1, 2007, fuel 
designated as 15 ppm or 500 ppm motor vehicle diesel fuel, or California 
diesel fuel as defined in Sec. 80.616 which is distributed outside the 
State of California pursuant to Sec. 80.617(b).
    (ii) Beginning with the compliance period that starts June 1, 2007 
and continuing up to and including the final reporting period, all fuel 
designation categories.
    (3) Any entity that receives custody of distillate fuel from another 
entity or facility that does not have an EPA facility identification 
number must report such batches as follows:
    (i) Any batch of distillate fuel for which custody is received and 
which is marked pursuant to Sec. 80.510(d) or (f) shall be deemed 
designated as heating oil, any batch of distillate fuel for

[[Page 969]]

which custody is received and which is marked pursuant to Sec. 
80.510(e) shall be deemed designated as heating oil or LM diesel fuel as 
applicable, and the report shall include that information under that 
designation.
    (ii) Any batch of distillate fuel for which custody is received and 
for which taxes have been paid pursuant to Section 4082 of the Internal 
Revenue Code (26 U.S.C. 4082) shall be deemed designated as motor 
vehicle diesel fuel and the report shall include it under that 
designation.
    (iii) Any batch of 500 ppm sulfur diesel fuel dyed pursuant to Sec. 
80.520(b) and not marked pursuant to Sec. 80.510(d) and (f), and for 
which custody is received, shall be deemed designated as NRLM diesel 
fuel and the report shall include it under that designation.
    (iv) Any batch of 500 ppm sulfur diesel fuel dyed pursuant to Sec. 
80.520(b) and not marked pursuant to Sec. 80.510(e), and for which 
custody is received, shall be deemed designated as NR diesel fuel and 
the report shall include it under that designation.
    (4) In the case of truck loading terminals, the results of all 
compliance calculations required under Sec. 80.599, and including:
    (i) The total volumes received of each fuel designation required to 
be reported in paragraphs (a)(1) through (a)(3) of this section over the 
quarterly compliance period.
    (ii) The total volumes delivered of each fuel designation required 
to be reported in paragraphs (a)(1) through (a)(3) of this section over 
the quarterly compliance period.
    (iii) The total volumes produced or imported at the facility of each 
fuel designation required to be reported in paragraphs (a)(1) through 
(a)(3) of this section over the quarterly compliance period.
    (iv) Beginning and ending inventories of each fuel designation 
required to be reported in paragraphs (a)(1) through(a)(3) of this 
section over the quarterly compliance period.
    (v) The volume balance under Sec. Sec. 80.599(b)(4) and 
80.598(b)(9)(vi).
    (vi) Beginning with the compliance period starting June 1, 2007, the 
volume balance under Sec. Sec. 80.599(c)(2) and 80.598(b)(9)(viii)(A).
    (b) Annual reports. Beginning August 31, 2007, all entities required 
to register under Sec. 80.597 and to maintain records for batches of 
fuel under Sec. 80.600 must report the following information separately 
for each of its facilities to the Administrator on an annual basis, as 
specified in paragraph (d)(2) of this section except as provided in 
paragraph (e) of this section.
    (1) Separately for each designation category for which records are 
required to be kept under Sec. 80.600 and separately for each 
transferor facility;
    (i) The total volume in gallons of distillate fuel designated under 
Sec. 80.598 for which custody was received by the reporting facility, 
and the EPA entity and facility registration number(s), as applicable, 
of the transferor; and
    (ii) The total volume in gallons of distillate fuel designated under 
Sec. 80.598 which was produced or imported by the reporting facility.
    (2) Separately for each designation category for which records are 
required to be kept under Sec. 80.600 and separately for each 
transferee facility, the total volume in gallons of distillate fuel 
designated under Sec. 80.598 for which custody was delivered by the 
reporting facility to any other entity or facility, and the EPA entity 
and facility registration number(s), as applicable, of the transferee 
except as provided under Sec. 80.600(a)(7), (a)(8), (b)(4), and (b)(5).
    (3) The results of all compliance calculations required under Sec. 
80.599, and including:
    (i) The total volumes in gallons received of each fuel designation 
required to be reported in paragraph (b)(1) of this section over the 
applicable annual compliance period.
    (ii) The total volumes produced or imported at the facility of each 
fuel designation required to be reported in paragraph (b)(1) of this 
section over the quarterly compliance period.
    (iii) The total volumes in gallons delivered of each fuel 
designation required to be reported in paragraph (b)(2) of this section 
over the applicable annual compliance period.
    (iv) Beginning and ending inventories of each fuel designation 
required to be reported in paragraphs (b)(1) and (b)(2) of this section 
for the annual compliance period.

[[Page 970]]

    (v) In the areas specified in Sec. 80.510(g)(2), for fuel 
designated as high sulfur NRLM diesel fuel delivered from June 1, 2007 
through May 31, 2010, for fuel designated as 500 ppm NR diesel fuel 
delivered from June 1, 2010 through May 31, 2012, and for fuel 
designated as 500 ppm sulfur NRLM diesel fuel from June 1, 2012 through 
May 31, 2014, the refiner must report all information required under its 
compliance plan approved pursuant to Sec. 80.554(a)(4) and (b)(4) and 
including the ultimate consumers to whom each batch of fuel was 
delivered and the total delivered to each ultimate consumer for the 
compliance period.
    (vi) Ending with the report due August 31, 2010, the volume balance 
under Sec. 80.598(b)(9)(vi) and Sec. 80.599(b)(4).
    (vii) Ending with the report due August 31, 2010, the volume balance 
under Sec. 80.598(b)(9)(vii) and Sec. 80.599(b)(5), if applicable.
    (viii) Ending with the report due August 31, 2010, the volume 
balance under Sec. 80.598(b)(9)(viii)(A) and Sec. 80.599(c)(2).
    (ix) Beginning with the report due August 31, 2010, the volume 
balance under Sec. 80.598(b)(8)(viii)(B) and Sec. 80.599(c)(4).
    (x) Beginning with the report due August 1, 2011 and ending with the 
report due August 1, 2012, the volume balance under Sec. 
80.598(b)(9)(ix) and Sec. 80.599(d)(2).
    (4) In the case of aggregated facilities consisting of a refinery 
and truck loading terminal, the results of annual compliance 
calculations under Sec. 80.598 for any distillate fuel received from an 
external source on which taxes have not been assessed and is not dyed 
and/or marked that the refinery will be handing off to another party, 
rather than selling over the truck loading terminal rack.
    (c) Additional information. The Administrator may request any 
additional information necessary to determine compliance with the 
requirements of Sec. Sec. 80.598 and 80.599.
    (d) Submission of reports for quarterly and annual compliance 
periods. (1) All quarterly reports shall be submitted to the 
Administrator for the compliance periods defined in Sec. 80.599(a)(1) 
as follows:
    (i) The reports for the first and second quarterly compliance 
periods covering June 1, 2006 to September 30, 2006 and October 1, 2006 
to December 31, 2006 respectively shall be submitted by February 28, 
2007.
    (ii) The reports for the third and fourth quarterly compliance 
periods covering January 1, 2007 to March 31, 2007 and April 1, 2007 to 
May 31, 2007 respectively shall be submitted by August 31, 2007.
    (iii) The report for the fifth quarterly compliance period covering 
June 1, 2007 to September 30, 2007 shall be submitted by November 30, 
2007.
    (iv) The report for the sixth quarterly compliance period covering 
October 1, 2007 to December 31, 2007 shall be submitted by February 28, 
2008.
    (v) The reports for the quarterly compliance periods beginning with 
the first period in 2008 up to and including the first period in 2010 
shall be submitted as follows:
    (A) The report for the period covering January 1 to March 31 shall 
be submitted by the following May 31.
    (B) The report covering the period covering April 1 to June 30 shall 
be submitted by the following August 31.
    (C) The report for the period from July 1 to September 30 shall be 
submitted by the following November 30.
    (D) The report for the quarterly compliance period from October 1 to 
December 31 shall be submitted by the following February 28.
    (vi) The report for the quarterly compliance period from April 1, 
2010 to May 31, 2010 shall be submitted by August 31, 2010.
    (vii) The report for the last quarterly compliance period from June 
1, 2010 to September 30, 2010 shall be submitted by November 30, 2010.
    (2) All annual reports shall be submitted to the Administrator for 
the compliance periods defined in Sec. 80.599(a)(2) by August 31.
    (3) All reports shall be submitted on forms and following procedures 
specified by the Administrator, shall include a statement that volumes 
reported to the Administrator under this section are in substantial 
agreement to volumes reported to the Internal Revenue Service (and if 
these volumes are not in substantial agreement, an explanation must be 
included) and shall be signed and certified by a responsible

[[Page 971]]

corporate officer of the reporting entity.
    (e) Exclusions. Notwithstanding the provisions of this section, an 
entity is not required to report under paragraphs (a) or (b) of this 
section for facilities whose only recordkeeping requirements under Sec. 
80.600 are under Sec. 80.600 (f) or (g) or to maintain records solely 
related to calculating compliance with the downgrading limitation under 
Sec. 80.527, Sec. 80.599(e) and Sec. 80.600(b)(1)(i) and (ii).
    (f) Additional requirements for aggregated facilities consisting of 
a refinery and a truck loading terminal. In addition to the reporting 
requirements listed by paragraphs (a) through (e) of this section, as 
applicable, such aggregated facilities are also subject to the following 
requirements:
    (1) Batch reports. Reports containing the requirements detailed in 
Sec. Sec. 80.592(f) and 80.600(m), must be submitted for all distillate 
produced by the refinery and sent over the truck loading terminal rack.
    (2) Quarterly volume reports. Reports detailing the quarterly totals 
of all designations, including whether the fuel was taxed or contained 
red dye (or red dye and the yellow marker), that left the truck loading 
terminal rack must be submitted for all distillate received from an 
external source or produced by the refinery.
    (3) Quarterly hand-off reports.
    (i) Reports detailing the quarterly totals of all designations of 
fuel received from external refiner/importer sources, if any.
    (ii) Reports detailing the quarterly totals of all undesignated fuel 
received from external refiner/importer sources that entered the 
designate and track system.

[69 FR 39198, June 29, 2004, as amended at 70 FR 40898, July 15, 2005; 
70 FR 70512, Nov. 22, 2005; 71 FR 25722, May 1, 2006]



Sec. 80.602  What records must be kept by entities in the NRLM diesel
fuel and diesel fuel additive production, importation,

and distribution systems?

    (a) Records that must be kept by parties in the NRLM diesel fuel and 
diesel fuel additive production, importation, and distribution systems. 
Beginning June 1, 2007, or June 1, 2006, if that is the first period 
credits are generated under Sec. 80.535, any person who produces, 
imports, sells, offers for sale, dispenses, distributes, supplies, 
offers for supply, stores, or transports nonroad, locomotive or marine 
diesel fuel subject to the provisions of this subpart, must keep the 
following records:
    (1) The applicable product transfer documents required under 
Sec. Sec. 80.590 and 80.591.
    (2) For any sampling and testing for sulfur content for a batch of 
NRLM diesel fuel produced or imported and subject to the 15 ppm sulfur 
standard or any sampling and testing for sulfur content as part of a 
quality assurance testing program, and any sampling and testing for 
cetane index, aromatics content, marker solvent yellow 124 content or 
dye solvent red 164 content of NRLM diesel fuel, NRLM diesel fuel 
additives or heating oil:
    (i) The location, date, time and storage tank or truck 
identification for each sample collected;
    (ii) The name and title of the person who collected the sample and 
the person who performed the testing; and
    (iii) The results of the tests for sulfur content (including, where 
applicable, the test results with and without application of the 
adjustment factor under Sec. 80.580(d)), for cetane index or aromatics 
content, dye solvent red 164, marker solvent yellow 124 (as applicable), 
and the volume of product in the storage tank or container from which 
the sample was taken.
    (3) The actions the party has taken, if any, to stop the sale or 
distribution of any NRLM diesel fuel found not to be in compliance with 
the sulfur standards specified in this subpart, and the actions the 
party has taken, if any, to identify the cause of any noncompliance and 
prevent future instances of noncompliance.
    (b) Additional records to be kept by refiners and importers of NRLM 
diesel fuel. Beginning June 1, 2007, or June 1, 2006, pursuant to the 
provisions of Sec. 80.535 or Sec. 80.554(d), any refiner producing 
diesel fuel subject to a sulfur standard under Sec. 80.510, Sec. 
80.513, Sec. 80.536, Sec. 80.554, Sec. 80.560, or Sec. 80.561, for 
each of its refineries, and any importer importing such diesel fuel 
separately for each facility, shall

[[Page 972]]

keep records that include the following information for each batch of 
NRLM diesel fuel or heating oil produced or imported:
    (1) The batch volume.
    (2) The batch number, assigned under the batch numbering procedures 
under Sec. 80.65(d)(3).
    (3) The date of production or import.
    (4) A record designating the batch as one of the following:
    (i) NRLM diesel fuel, NR diesel fuel, LM diesel fuel, or heating 
oil, as applicable.
    (ii) Meeting the 500 ppm sulfur standard of Sec. 80.510(a) or the 
15 ppm sulfur standard of Sec. 80.510(b) and (c) or other applicable 
standard.
    (iii) Dyed or undyed with visible evidence of solvent red 164.
    (iv) Marked or unmarked with solvent yellow 124.
    (5) For foreign refiners and importers of their fuel, the 
designations and other records required to be kept under Sec. 80.620.
    (6) All of the following information regarding credits, kept 
separately for each compliance period, kept separately for each refinery 
and for each importer facility, kept separately if converted under Sec. 
80.535(a) and (b) or Sec. 80.535(c) and (d), and kept separately from 
motor vehicle diesel fuel credits:
    (i) The number of credits in the refiner's or importer's possession 
at the beginning of the calendar year.
    (ii) The number of credits generated.
    (iii) The number of credits used.
    (iv) If any were obtained from or transferred to other parties, for 
each other party, its name, its EPA refiner or importer registration 
number consistent with Sec. 80.597, and the number obtained from, or 
transferred to, the other party.
    (v) The number in the refiner's or importer's possession that will 
carry over into the subsequent calendar year compliance period.
    (vi) Commercial documents that establish each transfer of credits 
from the transferor to the transferee.
    (7) The calculations used to determine baselines or compliance with 
the volume requirements and volume percentages, as applicable, under 
this subpart.
    (8) The calculations used to determine the number of credits 
generated.
    (9) A copy of reports submitted to EPA under Sec. 80.604.
    (c) Additional records importers must keep. Any importer shall keep 
records that identify and verify the source of each batch of certified 
DFR-Diesel and non-certified DFR-Diesel imported and demonstrate 
compliance with the requirements under Sec. 80.620.
    (d) Additional records that must be kept by mobile facilities. Any 
registered mobile facility must keep records of all contracts from any 
contracted components (e.g. tank truck, barge, marine tanker, rail car, 
etc.) of each of its registered mobile facilities.
    (e) Length of time records must be kept. The records required in 
this section shall be kept for five years from the date they were 
created, except that records relating to credit transfers shall be kept 
by the transferor for five years from the date the credits were 
transferred, and shall be kept by the transferee for five years from the 
date the credits were transferred, used or terminated, whichever is 
later.
    (f) Make records available to EPA. On request by EPA, the records 
required in this section must be made available to the Administrator or 
the Administrator's representative. For records that are electronically 
generated or maintained, the equipment and software necessary to read 
the records shall be made available, or if requested by EPA, electronic 
records shall be converted to paper documents which shall be provided to 
the Administrator's authorized representative.
    (g) Additional records to be kept by aggregated facilities 
consisting of a refinery and a truck loading terminal. In addition to 
the applicable records required by paragraphs (a) through (f) of this 
section, such aggregated facilities must also keep the following 
records:
    (1) The following information for each batch of motor vehicle diesel 
fuel produced by the refinery and sent over the aggregated facility's 
truck rack:
    (i) The batch volume;
    (ii) The batch number, assigned under the batch numbering procedures 
under Sec. Sec. 80.65(d)(3) and 80.502(d)(1);
    (iii) The date of production;

[[Page 973]]

    (iv) A record designating the batch as one of the following:
    (A) NRLM diesel fuel, NR diesel fuel, LM diesel fuel, or heating 
oil, as applicable.
    (B) Meeting the 500 ppm sulfur standard of Sec. 80.510(a) or the 15 
ppm sulfur standard of Sec. 80.510(b) and (c) or other applicable 
standard.
    (C) Dyed or undyed with visible evidence of solvent red 164.
    (D) Marked or unmarked with solvent yellow 124.
    (2) Hand-off reports for all distillate fuel from external sources 
(i.e., from another refiner or importer), as described in Sec. 
80.601(f)(2).

[69 FR 39199, June 29, 2004, as amended at 70 FR 70513, Nov. 22, 2005; 
71 FR 25723, May 1, 2006]



Sec. 80.603  What are the pre-compliance reporting requirements for NRLM diesel fuel?

    (a) Except as provided in paragraph (c) of this section, beginning 
on June 1, 2005, and for each year until June 1, 2011, or until the 
entity produces or imports NR or NRLM diesel fuel meeting the 15 ppm 
sulfur standard of Sec. 80.510(b) or (c), all refiners and importers 
planning to produce or import NR or NRLM diesel fuel, shall submit the 
following information to EPA:
    (1) Any changes to the information submitted for the company 
registration;
    (2) Any changes to the information submitted for any refinery or 
import facility registration;
    (3) Any estimate of the average daily volumes (in gallons) of each 
sulfur grade of motor vehicle and NRLM diesel fuel produced (or 
imported) at each refinery (or import facility). These volume estimates 
must be provided both for fuel produced from crude oil, as well as any 
fuel produced from other sources, and must be provided for the periods 
of June 1, 2010 through December 31, 2010, calendar years 2011 through 
2013, January 1, 2014 through May 31, 2014, and June 1, 2014 through 
December 31, 2014;
    (4) If expecting to participate in the credit trading program, 
estimates of the number of credits to be generated and/or used each year 
the program;
    (5) Information on project schedule by quarter of known or projected 
completion date by the stage of the project, for example, following the 
five project phases described in EPA's June 2002 Highway Diesel Progress 
Review report (EPA420-R-02-016, http://www.epa.gov/otaq/regs/hd2007/
420r02016.pdf): Strategic planning, Planning and front-end engineering, 
Detailed engineering and permitting, Procurement and construction, and 
Commissioning and startup;
    (6) Basic information regarding the selected technology pathway for 
compliance (e.g., conventional hydrotreating vs. other technologies, 
revamp vs. grassroots, etc.);
    (7) Whether capital commitments have been made or are projected to 
be made; and
    (8) The pre-compliance reports due in 2006 and later years must 
provide an update of the progress in each of these areas.
    (b) Reports under this section may be submitted in conjunction with 
reports submitted under Sec. 80.594.
    (c) The pre-compliance reporting requirements of this section do not 
apply to refineries subject to the provisions of Sec. 80.513.

[69 FR 39200, June 29, 2004]



Sec. 80.604  What are the annual reporting requirements for refiners
and importers of NRLM diesel fuel?

    Beginning with the annual compliance period that begins June 1, 
2007, or the first period during which credits are generated, 
transferred or used, or the first period during which NRLM diesel fuel 
or heating oil is produced under a small refiner compliance option under 
this subpart, whichever is earlier, any refiner or importer who produces 
or imports NRLM diesel fuel must submit annual compliance reports for 
each refinery and importer facility that contain the following 
information required, and such other information as EPA may require.
    (a) All refiners and importers. (1) The refiner or importer's 
company name and the EPA company and facility identification number.
    (2) If the refiner is a small refiner, a statement regarding to 
which small refiner option it is subject.

[[Page 974]]

    (b) Small refiners. (1) For each refinery of small refiners subject 
to the provisions of Sec. 80.551(g) and Sec. 80.554(a) for each 
compliance period from June 1, 2007 through May 31, 2010, report the 
following:
    (i) The total volume of diesel fuel produced and designated as NRLM 
diesel fuel.
    (ii) The volume of diesel fuel produced and designated as NRLM 
diesel fuel having a sulfur content less than or equal to the 500 ppm 
sulfur standard under Sec. 80.510(a).
    (iii) The total volume of diesel fuel produced and designated as 
NRLM diesel fuel having a sulfur content greater than the 500 ppm sulfur 
standard under Sec. 80.510(a).
    (iv) The total volume of heating oil produced.
    (v) The baseline under Sec. 80.554(a)(1).
    (vi) The total volume of diesel fuel produced and designated as NRLM 
diesel fuel that is exempt from the 500 ppm sulfur standard of Sec. 
80.510(a).
    (vii) The total volume, if any, of NRLM diesel fuel subject to the 
500 ppm sulfur standard Sec. 80.510(a) that had a sulfur content 
exceeding 500 ppm.
    (2) For each refinery of small refiners subject to the provisions of 
Sec. 80.551(g) and Sec. 80.554(b), for each compliance period between 
June 1, 2010 and May 31, 2012, report the following:
    (i) The total volume of diesel fuel produced and designated as NR 
diesel fuel.
    (ii) The total volume of diesel fuel produced and designated as LM 
diesel fuel.
    (iii) The total volume of diesel fuel produced and designated as NR 
diesel fuel subject to the 500 ppm sulfur standard under Sec. 
80.510(a).
    (iv) The total volume of diesel fuel produced and designated as LM 
diesel fuel subject to the 500 ppm sulfur standard under Sec. 
80.510(a).
    (v) The volume of diesel fuel produced and designated as NR diesel 
fuel having a sulfur content of 15 ppm or less.
    (vi) The baseline under Sec. 80.554(b)(1).
    (vii) The total volume of NRLM diesel fuel produced that is eligible 
for the sulfur standard under Sec. 80.510(a).
    (viii) The total volume, if any, of NRLM diesel fuel subject to the 
15 ppm sulfur standard that had a sulfur content in excess of 15 ppm.
    (3) For each refinery of small refiners subject to the provisions of 
Sec. 80.551(g) and Sec. 80.554(b), for each compliance period between 
June 1, 2012 and May 31, 2014, report the following:
    (i) The total volume of diesel fuel produced and designated as NRLM 
diesel fuel.
    (ii) The total volume diesel fuel produced and designated as NRLM 
diesel fuel subject to the 500 ppm sulfur standard under Sec. 
80.510(a).
    (iii) The total volume of diesel fuel produced and designated as 
NRLM diesel fuel having a sulfur content less than or equal to the 15 
ppm sulfur standard under Sec. 80.510(c).
    (iv) The baseline under Sec. 80.554(b)(1).
    (v) The total volume of NRLM diesel fuel produced that is eligible 
for the 500 ppm sulfur standard under Sec. 80.510(a).
    (vi) The total volume, if any, of NRLM diesel fuel subject to the 15 
ppm sulfur standard that had a sulfur content in excess of 15 ppm.
    (4) For each refinery of a small refiner that elects to produce NRLM 
diesel fuel subject to the 15 ppm sulfur standard of Sec. 80.510(c) 
beginning June 1, 2006 under Sec. 80.551(g) and Sec. 80.554(d), for 
each compliance period report the following:
    (i) The total volume of diesel fuel produced and designated as NRLM 
diesel fuel.
    (ii) The total volume of diesel fuel produced and designated as NRLM 
diesel fuel having a sulfur content less than or equal to 15 ppm.
    (iii) The percentages of NRLM diesel fuel produced and designated 
having a sulfur content less than or equal to 15 ppm under Sec. 
80.554(d)(1)(i) and (ii).
    (iv) The deficit, if any, and the number of credits purchased, if 
any, to cover any deficit as provided in Sec. 80.554(d)(3).
    (v) A report of the small refiner's progress toward compliance with 
the gasoline standards under Sec. Sec. 80.240 and 80.255.
    (c) Credit generation and use. Information regarding the generation, 
use, transfer and retirement of credits, separately by refinery and 
import facility, including the following:

[[Page 975]]

    (1) The number of credits at the beginning of the compliance period.
    (2) The number of credits generated.
    (3) The number of credits used.
    (4) If any credits were obtained from or transferred to other 
refineries or importers, for each other refinery or importer, the name, 
address, the EPA company identification number, and the number of 
credits obtained from or transferred to the other party.
    (5) The number of credits retired.
    (6) The credit balance at the beginning and end of the compliance 
period.
    (d) Batch reports. For each batch of NRLM diesel fuel and heating 
oil (if applicable) produced or imported and delivered during the 
compliance periods under paragraph (b) of this section, include the 
following:
    (1) The batch volume.
    (2) The batch number assigned using the batch numbering conventions 
under Sec. 80.65(d)(3) and the appropriate designation under Sec. 
80.598.
    (3) The date of production or import.
    (4) For each batch provide the information specified in paragraph 
(a)(1) of this section.
    (5) [Reserved]
    (6) Whether the batch was dyed with visible evidence of dye solvent 
red 164 before leaving the refinery or import facility or was undyed.
    (7) Whether the batch was marked with marker solvent yellow 124 
before leaving the refinery or import facility or was unmarked.
    (e) Additional reporting requirements for importers. Importers of 
NRLM diesel fuel are subject to the following additional requirements:
    (1) The reporting requirements under Sec. 80.620, if applicable.
    (2) Importers must exclude certified DFR-Diesel from calculations 
under this section.
    (f) Report submission. Any report required by this section must be--
    (1) On forms and following procedures specified by the Administrator 
of EPA;
    (2) Signed and certified as meeting all the applicable requirements 
of this subpart by the owner or a responsible corporate officer of the 
refiner or importer; and
    (3) Except for small refiners subject to Sec. 80.554(d), submitted 
to EPA no later than August 31 each year for the prior annual compliance 
period. Small refiners subject to the provisions of Sec. 80.554(d), 
reports must be submitted August 31 for the previous reporting period.
    (4) With the exception of reports required under paragraph (b)(3) of 
this section, no reports will be required under this section after 
August 31, 2014.

[69 FR 39200, June 29, 2004, as amended at 70 FR 40899, July 15, 2005]

                               Exemptions



Sec. 80.605  [Reserved]



Sec. 80.606  What national security exemption applies to 
distillate fuel?

    (a) The motor vehicle diesel fuel standards of Sec. 80.520(a)(1), 
(a)(2), and (c) and the nonroad, locomotive or marine diesel fuel 
standards of Sec. 80.510(a), (b), and (c) do not apply to distillate 
fuel that is produced, imported, sold, offered for sale, supplied, 
offered for supply, stored, dispensed, or transported for use in--
    (1) Tactical military motor vehicles or tactical military nonroad 
engines, vehicles or equipment, including locomotive and marine, having 
an EPA national security exemption from the motor vehicle emissions 
standards under 40 CFR 85.1708, or from the nonroad engine emission 
standards under 40 CFR part 89, 40 CFR part 92, 40 CFR part 94, or 40 
CFR part 1068; and
    (2) Tactical military motor vehicles or tactical military nonroad 
engines, vehicles or equipment, including locomotive and marine, that 
are not subject to a national security exemption from vehicle or engine 
emissions standards as described in paragraph (a)(1) of this section 
but, for national security purposes (for purposes of readiness for 
deployment oversees), need to be fueled on the same fuel as the 
vehicles, engines, or equipment for which EPA has granted such a 
national security exemption.
    (b) The exempt fuel must meet the following conditions:
    (1) It must be accompanied by product transfer documents as required 
under Sec. 80.590;
    (2) It must be segregated from non-exempt MVNRLM diesel fuel at all 
points in the distribution system;

[[Page 976]]

    (3) It must be dispensed from a fuel pump stand, fueling truck or 
tank that is labeled with the appropriate designation of the fuel, such 
as ``JP-5'' or ``JP-8''; and
    (4) It may not be used in any motor vehicles or nonroad engines, 
equipment or vehicles, including locomotive and marine, other than the 
vehicles, engines, and equipment referred to in paragraph (a) of this 
section.

[69 FR 39201, June 29, 2004]



Sec. 80.607  What are the requirements for obtaining an exemption
for diesel fuel used for research, development or testing purposes?

    (a) Written request for a research and development exemption. Any 
person may receive an exemption from the provisions of this subpart for 
diesel fuel used for research, development, or testing purposes by 
submitting the information listed in paragraph (c) of this section to:

    Director, Transportation and Regional Programs Division (6406J), 
U.S. Environmental Protection Agency, 1200 Pennsylvania Avenue, NW., 
Washington, DC 20460 (postal mail); or

    Director, Transportation and Regional Programs Division, U.S. 
Environmental Protection Agency, 1310 L Street, NW., 6th floor, 
Washington, DC 20005 (express mail/courier); and

    Director, Air Enforcement Division (2242A), U.S. Environmental 
Protection Agency, Ariel Rios Building, 1200 Pennsylvania Avenue, NW., 
Washington, DC 20460.

    (b) Criteria for a research and development exemption. For a 
research and development exemption to be granted, the person requesting 
an exemption must--
    (1) Demonstrate a purpose that constitutes an appropriate basis for 
exemption;
    (2) Demonstrate that an exemption is necessary;
    (3) Design a research and development program to be reasonable in 
scope; and
    (4) Exercise a degree of control consistent with the purpose of the 
program and EPA's monitoring requirements.
    (c) Information required to be submitted. To demonstrate each of the 
elements in paragraphs (b)(1) through (4) of this section, the person 
requesting an exemption must include the following information in the 
written request required under paragraph (a) of this section:
    (1) A concise statement of the purpose of the program demonstrating 
that the program has an appropriate research and development purpose.
    (2) An explanation of why the stated purpose of the program cannot 
be achieved in a practicable manner without performing one or more of 
the prohibited acts under this subpart.
    (3) To demonstrate the reasonableness of the scope of the program:
    (i) An estimate of the program's duration in time and, if 
appropriate, mileage;
    (ii) An estimate of the maximum number of vehicles or engines 
involved in the program;
    (iii) The manner in which the information on vehicles and engines 
used in the program will be recorded and made available to the 
Administrator upon request; and
    (iv) The quantity of diesel fuel which does not comply with the 
requirements of Sec. Sec. 80.520 and 80.521 for motor vehicle diesel 
fuel or Sec. 80.510 for NRLM diesel fuel.
    (4) With regard to control, a demonstration that the program affords 
EPA a monitoring capability, including the following:
    (i) The site(s) of the program (including facility name, street 
address, city, county, state, and zip code);
    (ii) The manner in which information on vehicles and engines used in 
the program will be recorded and made available to the Administrator 
upon request;
    (iii) The manner in which information on the diesel fuel used in the 
program (including quantity, fuel properties, name, address, telephone 
number and contact person of the supplier, and the date received from 
the supplier), will be recorded and made available to the Administrator 
upon request;
    (iv) The manner in which the party will ensure that the research and 
development fuel will be segregated from motor vehicle diesel fuel or 
NRLM diesel fuel, as applicable, and how fuel

[[Page 977]]

pumps will be labeled to ensure proper use of the research and 
development diesel fuel;
    (v) The name, address, telephone number and title of the person(s) 
in the organization requesting an exemption from whom further 
information on the application may be obtained; and
    (vi) The name, address, telephone number and title of the person(s) 
in the organization requesting an exemption who is responsible for 
recording and making available the information specified in this 
paragraph (c), and the location where such information will be 
maintained.
    (d) Additional requirements. (1) The product transfer documents 
associated with research and development motor vehicle diesel fuel must 
comply with requirements of Sec. 80.590(b)(3).
    (2) The research and development diesel fuel must be designated by 
the refiner or supplier, as applicable, as research and development 
diesel fuel.
    (3) The research and development diesel fuel must be kept segregated 
from non-exempt MVNRLM diesel fuel at all points in the distribution 
system.
    (4) The research and development diesel fuel must not be sold, 
distributed, offered for sale or distribution, dispensed, supplied, 
offered for supply, transported to or from, or stored by a diesel fuel 
retail outlet, or by a wholesale purchaser-consumer facility, unless the 
wholesale purchaser-consumer facility is associated with the research 
and development program that uses the diesel fuel.
    (5) At the completion of the program, any emission control systems 
or elements of design which are damaged or rendered inoperative shall be 
replaced on vehicles remaining in service, or the responsible person 
will be liable for a violation of the Clean Air Act section 203(a)(3) 
(42 U.S.C. 7522 (a)(3)) unless sufficient evidence is supplied that the 
emission controls or elements of design were not damaged.
    (e) Mechanism for granting of an exemption. A request for a research 
and development exemption will be deemed approved by the earlier of 60 
days from the date on which EPA receives the request for exemption, 
(provided that EPA has not notified the applicant of potential 
disapproval by that time), or the date on which the applicant receives a 
written approval letter from EPA.
    (1) The volume of diesel fuel subject to the approval shall not 
exceed the estimated amount under paragraph (c)(3)(iv) of this section, 
unless EPA grants a greater amount in writing.
    (2) Any exemption granted under this section will expire at the 
completion of the test program or three years from the date of approval, 
whichever occurs first, and may only be extended upon re-application 
consistent will all requirements of this section.
    (3) The passage of 60 days will not signify the acceptance by EPA of 
the validity of the information in the request for an exemption. EPA may 
elect at any time to review the information contained in the request, 
and where appropriate may notify the responsible person of disapproval 
of the exemption.
    (4) In granting an exemption the Administrator may include terms and 
conditions, including replacement of emission control devices or 
elements of design, that the Administrator determines are necessary for 
monitoring the exemption and for assuring that the purposes of this 
subpart are met.
    (5) Any violation of a term or condition of the exemption, or of any 
requirement of this section, will cause the exemption to be void ab 
initio.
    (6) If any information required under paragraph (c) of this section 
should change after approval of the exemption, the responsible person 
must notify EPA in writing immediately. Failure to do so may result in 
disapproval of the exemption or may make it void ab initio, and may make 
the party liable for a violation of this subpart.
    (f) Effects of exemption. Motor vehicle diesel fuel or NRLM diesel 
fuel that is subject to a research and development exemption under this 
section is exempt from other provisions of this subpart provided that 
the fuel is used in a manner that complies with the purpose of the 
program under paragraph (c) of this section and the requirements of this 
section.

[[Page 978]]

    (g) Notification of completion. The party shall notify EPA in 
writing within 30 days after completion of the research and development 
program.

[69 FR 39202, June 29, 2004]



Sec. 80.608  What requirements apply to diesel fuel for use 
in the Territories?

    The sulfur standards of Sec. 80.520(a)(1) and (c) related to motor 
vehicle diesel fuel, and of Sec. 80.510(a), (b), and (c) related to 
NRLM diesel fuel, do not apply to diesel fuel that is produced, 
imported, sold, offered for sale, supplied, offered for supply, stored, 
dispensed, or transported for use in the Territories of Guam, American 
Samoa or the Commonwealth of the Northern Mariana Islands, provided that 
such diesel fuel is--
    (a) Designated by the refiner or importer as high sulfur diesel fuel 
only for use in Guam, American Samoa, or the Commonwealth of the 
Northern Mariana Islands;
    (b) Used only in Guam, American Samoa, or the Commonwealth of the 
Northern Mariana Islands;
    (c) Accompanied by documentation that complies with the product 
transfer document requirements of Sec. 80.590(b)(1); and
    (d) Segregated from non-exempt MVNRLM diesel fuel at all points in 
the distribution system from the point the diesel fuel is designated as 
exempt fuel only for use in Guam, American Samoa, or the Commonwealth of 
the Northern Mariana Islands, while the exempt fuel is in the United 
States but outside these Territories.

[69 FR 39203, June 29, 2004]



Sec. 80.609  [Reserved]

                          Violation Provisions



Sec. 80.610  What acts are prohibited under the diesel fuel sulfur program?

    No person shall--
    (a) Standard, dye, marker or product violation. (1) Produce, import, 
sell, offer for sale, dispense, supply, offer for supply, store or 
transport motor vehicle diesel fuel, NRLM diesel fuel, or heating oil 
that does not comply with the applicable standards, dye, marking or any 
other product requirements under this subpart I and 40 CFR part 69.
    (2) Beginning June 1, 2007, produce, import, sell, offer for sale, 
dispense, supply, offer for supply, store or transport any diesel fuel 
for use in motor vehicle or nonroad engines that contains greater than 
0.10 milligrams per liter of solvent yellow 124, except for 500 ppm 
sulfur diesel fuel produced or imported from June 1, 2010 through 
September 30, 2012 for use only in locomotive or marine diesel engines 
that is marked under the provisions of Sec. 80.510(e).
    (3) Beginning June 1, 2007, produce, import, sell, offer for sale, 
dispense, supply, offer for supply, store or transport heating oil for 
use in any nonroad diesel engine, including any locomotive or marine 
diesel engine.
    (b) Designation and volume balance violation. Produce, import, sell, 
offer for sale, dispense, supply, offer for supply, store or transport 
motor vehicle diesel, NRLM diesel fuel, heating oil or other distillate 
that does not comply with the applicable designation or volume balance 
requirements under Sec. Sec. 80.598 and 80.599.
    (c) Additive violation. (1) Produce, import, sell, offer for sale, 
dispense, supply, offer for supply, store or transport any motor vehicle 
diesel fuel additive or NRLM diesel fuel additive for use at a 
downstream location that does not comply with the applicable 
requirements of Sec. 80.521.
    (2) Blend or permit the blending into motor vehicle diesel fuel or 
NRLM diesel fuel at a downstream location, or use, or permit the use, in 
motor vehicle diesel fuel or NRLM diesel fuel, of any additive that does 
not comply with the applicable requirements of Sec. 80.521.
    (d) Used motor oil violation. Introduce into the fuel system of a 
model year 2007 or later diesel motor vehicle or model year 2011 or 
later nonroad diesel engine (except for locomotive or marine engines) or 
other nonroad diesel engine certified for the use of 15 ppm sulfur 
content fuel, or permit the introduction into the fuel system of such 
vehicle or nonroad engine of used motor oil, or used motor oil blended 
with diesel fuel, that does not comply with the requirements of Sec. 
80.522.
    (e) Improper fuel usage violation. (1) Introduce, or permit the 
introduction of,

[[Page 979]]

fuel into model year 2007 or later diesel motor vehicles, and beginning 
December 1, 2010 into any diesel motor vehicle, that does not comply 
with the standards and dye requirements of Sec. 80.520(a) and (b);
    (2) Introduce, or permit the introduction of, fuel into any nonroad 
diesel engine (including any locomotive or marine diesel engine) that 
does not comply with the applicable standards, dye and marking 
requirements of Sec. 80.510(a), (d), and (e) and Sec. 80.520(b) 
beginning on the following dates:
    (i) This prohibition begins December 1, 2007 in the areas specified 
in Sec. 80.510(g)(1) and (g)(2), except as specified in paragraph 
(e)(2)(ii) of this section.
    (ii) This prohibition begins December 1, 2010 in the area specified 
in Sec. 80.510(g)(2) for NRLM diesel fuel that is produced in 
accordance with a compliance plan approved under Sec. 80.554.
    (iii) This prohibition begins December 1, 2010 in all other areas.
    (3) Introduce, or permit the introduction of, fuel into any nonroad 
diesel engine (other than locomotive and marine diesel engines) that 
does not comply with the applicable standards, dye and marking 
requirements of Sec. 80.510(b) and (e) beginning on the following 
dates:
    (i) This prohibition begins December 1, 2010 in the areas specified 
in Sec. 80.510(g)(1) and (g)(2), except as specified paragraph 
(e)(3)(ii) of this section.
    (ii) This prohibition begins December 1, 2014 in the area specified 
in Sec. 80.510(g)(2) for NRLM diesel fuel that is produced in 
accordance with a compliance plan approved under Sec. 80.554.
    (iii) This prohibition begins beginning December 1, 2014 in all 
other areas.
    (4) Introduce, or permit the introduction of, fuel into any 
locomotive and marine diesel engine which does not comply with the 
applicable standards, dye and marking requirements of Sec. 80.510(c) 
and Sec. 80.510(f) in the following areas beginning on the following 
dates:
    (i) This prohibition begins December 1, 2012 in the areas specified 
in Sec. 80.510(g)(1) and (g)(2), except as specified in paragraph 
(e)(4)(ii) of this section.
    (ii) This prohibition does not apply in the area specified in Sec. 
80.510(g)(2) for NRLM diesel fuel that is produced in accordance with a 
compliance plan approved under Sec. 80.554.
    (iii) This prohibition does not apply in any other areas.
    (5) Introduce, or permit the introduction of, fuel into any model 
year 2011 or later nonroad diesel engine certified for use on 15 ppm 
sulfur content fuel, diesel fuel which does not comply with the 
applicable standards, dye and marking requirements of Sec. 80.510(b) 
through (f).
    (f) Cause another party to violate. Cause another person to commit 
an act in violation of paragraphs (a) through (e) of this section.
    (g) Cause violating fuel or additive to be in the distribution 
system. Cause motor vehicle diesel fuel, or NRLM diesel fuel, to be in 
the diesel fuel distribution system which does not comply with the 
applicable standard, dye or marker requirements or the product 
segregation requirements of this Subpart I, or cause any diesel fuel 
additive to be in the diesel fuel additive distribution system which 
does not comply with the applicable sulfur standards under Sec. 80.521.

[69 FR 39203, June 29, 2004]



Sec. 80.611  What evidence may be used to determine compliance with
the prohibitions and requirements of this subpart and liability

for violations of this 
          subpart?

    (a) Compliance with sulfur, cetane, and aromatics standards, dye and 
marker requirements. Compliance with the standards, dye, and marker 
requirements in Sec. Sec. 80.510, 80.511, 80.520, and 80.521 shall be 
determined based on the level of the applicable component or parameter, 
using the sampling methodologies specified in Sec. 80.330(b), as 
applicable, and an approved testing methodology under the provisions of 
Sec. Sec. 80.580 through 80.586 for sulfur; Sec. 80.2(w) for cetane 
index; Sec. 80.2(z) for aromatic content; and Sec. 80.582 for fuel 
marker. Any evidence or information, including the exclusive use of such 
evidence or information, may be used to establish the level of the 
applicable component or parameter in the diesel fuel or additive, or 
motor oil to be used in diesel

[[Page 980]]

fuel, if the evidence or information is relevant to whether that level 
would have been in compliance with the standard if the regulatory 
sampling and testing methodology had been correctly performed. Such 
evidence may be obtained from any source or location and may include, 
but is not limited to, test results using methods other than the 
compliance methods in this paragraph (a), business records, and 
commercial documents.
    (b) Compliance with other requirements. Determination of compliance 
with the requirements and prohibitions of this subpart other than the 
standards described in paragraph (a) of this section and in Sec. Sec. 
80.510, 80.511, 80.520, and 80.521, and determination of liability for 
any violation of this subpart, may be based on information obtained from 
any source or location. Such information may include, but is not limited 
to, business records and commercial documents.

[69 FR 39204, June 29, 2004]



Sec. 80.612  Who is liable for violations of this subpart?

    (a) Persons liable for violations of prohibited acts--(1) Standard, 
dye, marker, additives, used motor oil, heating oil, fuel introduction, 
and other product requirement violations. (i) Any refiner, importer, 
distributor, reseller, carrier, retailer, wholesale purchaser-consumer 
who owned, leased, operated, controlled or supervised a facility where a 
violation of any provision of Sec. 80.610(a) through (e) occurred, or 
any other person who violates any provision of Sec. 80.610(a) through 
(e), is deemed liable for the applicable violation, except that 
distributors who receive diesel fuel or distillate from the point where 
it is taxed, dyed or marked, and retailers and wholesale purchaser-
consumers are not deemed liable for any violation of Sec. 80.610(b).
    (ii) Any person who causes another person to violate Sec. 80.610(a) 
through (e) is liable for a violation of Sec. 80.610(f).
    (iii) Any refiner, importer, distributor, reseller, carrier, 
retailer, or wholesale purchaser-consumer who produced, imported, sold, 
offered for sale, dispensed, supplied, offered to supply, stored, 
transported, or caused the transportation or storage of, diesel fuel or 
distillate that violates Sec. 80.610(a), is deemed in violation of 
Sec. 80.610(f).
    (iv) Any person who produced, imported, sold, offered for sale, 
dispensed, supplied, offered to supply, stored, transported, or caused 
the transportation or storage of a diesel fuel additive which is used in 
motor vehicle diesel fuel or NRLM diesel fuel that is found to violate 
Sec. 80.610(a), is deemed in violation of Sec. 80.610(f).
    (2) Cause violating diesel fuel or additive to be in the 
distribution system. Any refiner, importer, distributor, reseller, 
carrier, retailer, or wholesale purchaser-consumer or any other person 
who owned, leased, operated, controlled or supervised a facility from 
which distillate fuel or additive was released into the distribution 
system which does not comply with the applicable standards, marking or 
dye requirements of this Subpart I is deemed in violation of Sec. 
80.610(g).
    (3) Branded refiner/importer liability. Any refiner or importer 
whose corporate, trade, or brand name, or whose marketing subsidiary's 
corporate, trade, or brand name appeared at a facility where a violation 
of Sec. 80.610(a) or (b) occurred, is deemed in violation of Sec. 
80.610(a) or (b), as applicable.
    (4) Carrier causation. In order for a distillate fuel or diesel fuel 
additive carrier to be liable under paragraph (a)(1)(ii), (a)(1)(iii), 
or (a)(1)(iv) of this section, as applicable, EPA must demonstrate, by 
reasonably specific showing by direct or circumstantial evidence, that 
the carrier caused the violation.
    (5) Parent corporation. Any parent corporation is liable for any 
violations of this subpart that are committed by any subsidiary.
    (6) Joint venture. Each partner to a joint venture is jointly and 
severally liable for any violation of this subpart that occurs at the 
joint venture facility or is committed by the joint venture operation.
    (b) Persons liable for failure to comply with other provisions 
ofthis subpart. Any person who:
    (1) Fails to comply with the requirements of a provision of this 
subpart not

[[Page 981]]

addressed in paragraph (a) of this section is liable for a violation of 
that provision; or
    (2) Causes another person to fail to comply with the requirements of 
a provision of this subpart not addressed in paragraph (a) of this 
section, is liable for causing a violation of that provision.

[66 FR 5136, Jan. 18, 2001, as amended at 69 FR 39204, June 29, 2004]



Sec. 80.613  What defenses apply to persons deemed liable for a
violation of a prohibited act under this subpart?

    (a) Presumptive liability defenses. (1) Any person deemed liable for 
a violation of a prohibition under Sec. 80.612(a)(1)(i), (a)(1)(iii), 
(a)(2), or (a)(3), will not be deemed in violation if the person 
demonstrates all of the following, as applicable:
    (i) The violation was not caused by the person or the person's 
employee or agent;
    (ii) Product transfer documents account for fuel or additive found 
to be in violation and indicate that the violating product was in 
compliance with the applicable requirements when it was under the 
person's control;
    (iii) The person conducted a quality assurance sampling and testing 
program, as described in paragraph (d) of this section, except for those 
persons subject to the provisions of paragraph (a)(1)(iv), (a)(1)(v), or 
(a)(1)(vi) of this section or Sec. 80.614. A carrier may rely on the 
quality assurance program carried out by another party, including the 
party who owns the diesel fuel in question, provided that the quality 
assurance program is carried out properly. Retailers, wholesale 
purchaser-consumers, and ultimate consumers of diesel fuel are not 
required to conduct quality assurance programs;
    (iv) For refiners and importers of diesel fuel subject to the 15 ppm 
sulfur standard under Sec. 80.510(b) or (c), or Sec. 80.520(a)(1), or 
the 500 ppm sulfur standard under Sec. 80.510(a) or 80.520(c), test 
results that--
    (A) Were conducted according to an appropriate test methodology 
approved or designated under Sec. Sec. 80.580 through 80.586, 80.2(w), 
or 80.2(z), as appropriate; and
    (B) Establish that, when it left the party's control, the fuel did 
not violate the sulfur, cetane or aromatics standard, or the dye or 
marking provisions of Sec. Sec. 80.510 or 80.511, as applicable;
    (v) For any truck loading terminal or any other person who delivers 
heating oil for delivery to the ultimate consumer and is subject to the 
requirement to mark heating oil or LM diesel fuel under Sec. 80.510(d) 
through (f), data which demonstrates that when it left the truck loading 
terminal or other facility, the concentration of marker solvent yellow 
124 was equal to or greater than six milligrams per liter. In lieu of 
testing for marker solvent yellow 124 concentration, evidence may be 
presented of an oversight program, including records of marker 
inventory, purchase and additization, and records of periodic inspection 
and calibration of additization equipment that ensures that marker is 
added to heating oil or LM diesel fuel, as applicable, under Sec. 
80.510(d) through (f) in the required concentration;
    (vi) Except as provided in Sec. 80.614, for any person who, at a 
downstream location, blends a diesel fuel additive subject to the 
requirements of Sec. 80.521(b) into motor vehicle diesel fuel or NRLM 
diesel fuel subject to the 15 ppm sulfur standard under Sec. 80.520(a) 
or Sec. 80.510(b) or (c), except a person who blends additives into 
fuel tanker trucks at a truck loading rack subject to the provisions of 
paragraph (d)(2) of this section, test results which are conducted 
subsequent to the blending of the additive into the fuel, and which 
comply with the requirements of paragraphs (a)(1)(iv)(A) and (B) of this 
section; and
    (vii) Any person deemed liable for a designation or volume balance 
provisions violation under Sec. 80.610(b) and 80.612(a) will not be 
deemed in violation if the person demonstrates, through product transfer 
documents, records, reports and other evidence that the diesel fuel or 
distillate was properly designated and volume balance requirements were 
met.
    (2) Any person deemed liable for a violation under Sec. 
80.612(a)(1)(iv), in regard to a diesel fuel additive subject to the 
requirements of Sec. 80.521(a), will not be deemed in violation if the 
person demonstrates that--

[[Page 982]]

    (i) Product transfer document(s) account for the additive in the 
fuel found to be in violation, which comply with the requirements under 
Sec. 80.591(a), and indicate that the additive was in compliance with 
the applicable requirements while it was under the party's control; and
    (ii) For the additive's manufacturer or importer, test results which 
accurately establish that, when it left the party's control, the 
additive in the diesel fuel determined to be in violation did not have a 
sulfur content greater than or equal to 15 ppm.
    (A) Analysis of the additive sulfur content pursuant to this 
paragraph (a)(2) may be conducted at the time the batch was manufactured 
or imported, or on a sample of that batch which the manufacturer or 
importer retains for such purpose for a minimum of two years from the 
date the batch was manufactured or imported.
    (B) After two years from the date the additive batch was 
manufactured or imported, the additive manufacturer or importer is no 
longer required to retain samples for the purpose of complying with the 
testing requirements of this paragraph (a)(2).
    (C) The analysis of the sulfur content of the additive must be 
conducted pursuant to the requirements of Sec. 80.580.
    (3) Any person who is deemed liable for a violation under Sec. 
80.612(a)(1)(iv) with regard to a diesel fuel additive subject to the 
requirements of Sec. 80.521(b), will not be deemed in violation if the 
person demonstrates that--
    (i) The violation was not caused by the party or the party's 
employee or agent;
    (ii) Product transfer document(s) which comply with the additive 
information requirements under Sec. 80.591(b), account for the additive 
in the fuel found to be in violation, and indicate that the additive was 
in compliance with the applicable requirements while it was under the 
party's control; and
    (iii) For the additive's manufacturer or importer, test results 
which accurately establish that, when it left the party's control, the 
additive in the diesel fuel determined to be in violation was in 
conformity with the information on the additive product transfer 
document pursuant to the requirements of Sec. 80.591(b). The testing 
procedures applicable under paragraph (a)(2) of this section, also apply 
under this paragraph (a)(3).
    (b) Branded refiner defenses. In the case of a violation found at a 
facility operating under the corporate, trade or brand name of a refiner 
or importer, or a refiner's or importer's marketing subsidiary, the 
refiner or importer must show, in addition to the defense elements 
required under paragraph (a)(1) of this section, that the violation was 
caused by:
    (1) An act in violation of law (other than the Clean Air Act or this 
Part 80), or an act of sabotage or vandalism;
    (2) The action of any refiner, importer, retailer, distributor, 
reseller, oxygenate blender, carrier, retailer or wholesale purchaser-
consumer in violation of a contractual agreement between the branded 
refiner or importer and the person designed to prevent such action, and 
despite periodic sampling and testing by the branded refiner or importer 
to ensure compliance with such contractual obligation; or
    (3) The action of any carrier or other distributor not subject to a 
contract with the refiner or importer, but engaged for transportation of 
diesel fuel, despite specifications or inspections of procedures and 
equipment which are reasonably calculated to prevent such action.
    (c) Causation demonstration. Under paragraph (a)(1) of this section 
for any person to show that a violation was not caused by that person, 
or under paragraph (b) of this section to show that a violation was 
caused by any of the specified actions, the person must demonstrate by 
reasonably specific showing, by direct or circumstantial evidence, that 
the violation was caused or must have been caused by another person and 
that the person asserting the defense did not contribute to that other 
person's causation.
    (d) Quality assurance and testing program. To demonstrate an 
acceptable quality assurance program under paragraph (a)(1)(iii) of this 
section, a person must present evidence of the following:
    (1) A periodic sampling and testing program to ensure the diesel 
fuel or additive the person sold, dispensed, supplied, stored, or 
transported, meets the

[[Page 983]]

applicable standards and requirements, including the requirements 
relating to the presence of marker solvent yellow 124.
    (2) For those parties who, at a downstream location, blend diesel 
fuel additives subject to the requirements of Sec. 80.521(b) into fuel 
trucks at a truck loading rack, the periodic sampling and testing 
program required under this paragraph (d) must ensure, by taking into 
account the greater risk of noncompliance created through use of a high 
sulfur additive, that the diesel fuel into which the additive was 
blended meets the applicable standards subsequent to the blending.
    (3) On each occasion when diesel fuel or additive is found not in 
compliance with the applicable standard:
    (i) The person immediately ceases selling, offering for sale, 
dispensing, supplying, offering for supply, storing or transporting the 
non-complying product.
    (ii) The person promptly remedies the violation and the factors that 
caused the violation (for example, by removing the non-complying product 
from the distribution system until the applicable standard is achieved 
and taking steps to prevent future violations of a similar nature from 
occurring).
    (4) For any carrier who transports diesel fuel or additive in a tank 
truck, the quality assurance program required under this paragraph (d) 
need not include its own periodic sampling and testing of the diesel 
fuel or additive in the tank truck, but in lieu of such tank truck 
sampling and testing, the carrier shall demonstrate evidence of an 
oversight program for monitoring compliance with the requirements of 
this subpart relating to the transport or storage of such product by 
tank truck, such as appropriate guidance to drivers regarding compliance 
with the applicable sulfur standard, product segregation and product 
transfer document requirements, and the periodic review of records 
received in the ordinary course of business concerning diesel fuel or 
additive quality and delivery.

[66 FR 5136, Jan. 18, 2001, as amended at 69 FR 39204, June 29, 2004; 70 
FR 40899, July 15, 2005]



Sec. 80.614  What are the alternative defense requirements in 
lieu of Sec. 80.613(a)(1)(vi)?

    Any person who blends a MVNRLM diesel fuel additive package into 
MVNRLM diesel fuel subject to the 15 ppm sulfur standards of Sec. 
80.510(b) or (c) or Sec. 80.520(a) which contains a static dissipater 
additive that has a sulfur content greater than 15 ppm but whose 
contribution to the sulfur content of the MVNRLM diesel fuel is less 
than 0.4 ppm at its maximum recommended concentration, and/or red dye 
that has a sulfur content greater than 15 ppm but whose contribution to 
the sulfur content of the MVNRLM diesel fuel is less than 0.04 ppm at 
its maximum recommended concentration, and which contains no other 
additives with a sulfur content greater than 15 ppm must establish all 
the following in order to use this section as an alternative to the 
defense element under Sec. 80.613(a)(1)(vi):
    (a)(1) The blender of the additive package has a sulfur content test 
result for the MVNRLM diesel fuel prior to blending of the additive 
package that indicates that the additive package, when added, will not 
cause the MVNRLM diesel fuel sulfur content to exceed 15 ppm sulfur.
    (2) In cases where the storage tank that contains MVNRLM diesel fuel 
prior to additization contains multiple fuel batches, the blender of the 
additive package must have sulfur test results on each batch of MVNRLM 
diesel fuel that was added to the storage tank during the current and 
previous volumetric accounting reconciliation (VAR) periods, which 
indicates that the additive package, when added to the component MVNRLM 
diesel fuel batch in the storage tank with the highest sulfur level 
would not cause that component batch to exceed 15 ppm sulfur.
    (b) The VAR standard is attained as determined under the provisions 
of this section. The VAR reconciliation standard is attained when the 
actual concentration of the additive package used per the VAR formula 
record under paragraph (f) of this section is less than the 
concentration that would have caused any batch of MVNRLM diesel fuel to 
exceed a sulfur content of

[[Page 984]]

15 ppm given the maximum sulfur test result on any MVNRLM diesel fuel 
batch described in paragraph (a) of this section that is additized with 
the additive package during the VAR period.
    (c) The product transfer document complies with the applicable 
sulfur information requirements of Sec. 80.591.
    (d) If more than one additive package containing a static dissipater 
additive and/or red dye is used during a VAR period, then a separate VAR 
formula record must be created for MVNRLM diesel fuel additized for each 
of the additive packages used. In such cases, the amount of the each 
additive package used must be accurately and separately measured, either 
through the use of a separate storage tank, a separate meter, or some 
other measurement system that is able to accurately distinguish its use.
    (e) Recorded volumes of MVNRLM diesel fuel and the additive package 
must be expressed to the nearest gallon (or smaller units), except that 
additive package volumes of five gallons or less must be expressed to 
the nearest tenth of a gallon (or smaller units). However, if the 
blender's equipment cannot accurately measure to the nearest tenth of a 
gallon, then such volumes must be rounded upward to the next higher 
gallon for purposes of determining compliance with this section.
    (f) Each VAR formula record must also contain the following 
information:
    (1) Automated blending facilities. In the case of an automated 
additive package blending facility, for each VAR period, for each 
storage system for an additive package containing a static dissipater 
additive and/or red dye, and each additive package in that storage 
system, the following must be recorded:
    (i)(A) The manufacturer and commercial identifying name of the 
package being reconciled, the maximum recommended treatment level, the 
potential contribution to the sulfur content of the finished fuel that 
might result when the additive package is used at its maximum 
recommended treatment level, the intended treatment level, and the 
contribution to the sulfur content of the finished fuel that would 
result when the additive package is used at its intended treatment 
level. The intended treatment level is the treatment level that the 
additive injection equipment is set to.
    (B) The maximum recommended treatment level and the intended 
treatment level must be expressed in terms of gallons of the additive 
package per thousand gallons of MVNRLM diesel fuel, and expressed to 
four significant figures. If the additive package storage system which 
is the subject of the VAR formula record is a proprietary system under 
the control of a customer, this fact must be indicated on the record.
    (ii) The total volume of the additive package blended into MVNRLM 
diesel fuel, in accordance with one of the following methods, as 
applicable.
    (A) For a facility which uses in-line meters to measure usage, the 
total volume of additive package measured, together with supporting data 
which includes one of the following: the beginning and ending meter 
readings for each meter being measured, the metered batch volume 
measurements for each meter being measured, or other comparable metered 
measurements. The supporting data may be supplied on the VAR formula 
record or in the form of computer printouts or other comparable VAR 
supporting documentation.
    (B) For a facility which uses a gauge to measure the inventory of 
the additive package storage tank, the total volume of additive package 
shall be calculated from the following equation:

Additive package volume = (A) - (B) + (C) - (D)

Where:

A = Initial additive package inventory of the tank
B = Final additive package inventory of the tank
C = Sum of any additions to additive package inventory
D = Sum of any withdrawals from additive package inventory for purposes 
other than the additization of MVNRLM diesel fuel.

    (C) The value of each variable in the equation in paragraph 
(f)(1)(ii)(B) of this section must be separately recorded on the VAR 
formula record. In addition, a list of each additive package addition 
included in variable C and a list of each additive package withdrawal 
included in variable D must be provided, either on the formula record or 
as VAR supporting documentation.

[[Page 985]]

    (iii) The total volume of MVNRLM diesel fuel to which the additive 
package has been added, together with supporting data which includes one 
of the following: the beginning and ending meter measurements for each 
meter being measured, the metered batch volume measurements for each 
meter being measured, or other comparable metered measurements. The 
supporting data may be supplied on the VAR formula record or in the form 
of computer printouts or other comparable VAR supporting documentation.
    (iv) The actual concentration of the additive package, calculated as 
the total volume of the additive package added (pursuant to paragraph 
(f)(1)(ii) of this section), divided by the total volume of MVNRLM 
diesel fuel (pursuant to paragraph (f)(1)(iii) of this section). The 
concentration must be calculated and recorded to 4 significant figures.
    (v) A list of each additive package concentration rate set for the 
additive package that is the subject of the VAR record, together with 
the date and description of each adjustment to any initially set 
concentration. The concentration adjustment information may be supplied 
on the VAR formula record or in the form of computer printouts or other 
comparable VAR supporting documentation. No concentration setting is 
permitted above the maximum recommended concentration supplied by the 
additive manufacturer, except as described in paragraph (f)(1)(vii) of 
this section.
    (vi) The dates of the VAR period, which shall be no longer than 
thirty-one days. If the VAR period is contemporaneous with a calendar 
month, then specifying the month will fulfill this requirement; if not, 
then the beginning and ending dates and times of the VAR period must be 
listed. The times may be supplied on the VAR formula record or in 
supporting documentation. Any adjustment to any additive package 
concentration rate initially set in the VAR period shall terminate that 
VAR period and initiate a new VAR period, except as provided in 
paragraph (f)(1)(vii) of this section.
    (vii) The concentration setting for the additive package injector 
may be changed from the concentration initially set in the VAR period 
without terminating that VAR period, provided that:
    (A) The purpose of the change is to correct a batch under-
additization prior to the end of the VAR period and prior to the 
transfer of the batch to another party, or to correct an equipment 
malfunction where there has been no over-additization of the additive;
    (B) The concentration is immediately returned after the correction 
to a concentration that fulfills the requirements of this paragraph (f);
    (C) The blender creates and maintains documentation establishing the 
date and adjustments of the correction; and
    (D) If the correction is initiated only to rectify an equipment 
malfunction, and the amount of additive package used in this procedure 
is not added to MVNRLM diesel fuel within the compliance period, then 
this amount is subtracted from the additive package volume listed on the 
VAR formula record. In such a case, the addition of this amount of 
additive must be reflected in the following VAR period.
    (viii) The measured sulfur level for each batch of MVNRLM diesel 
fuel to which the additive package is added during each VAR period. In 
cases where the storage tank that contains MVNRLM diesel fuel prior to 
additization contains multiple fuel batches, a measured sulfur level on 
each batch added to the storage tank during the current and previous VAR 
periods must be recorded.
    (2) Non-automated facilities. In the case of a facility in which 
hand blending or any other non-automated method is used to blend the 
additive packages, for each additive package and for each batch of 
MVNRLM diesel fuel to which the additive package is being added, the 
following shall be recorded:
    (i) The manufacturer and commercial identifying name of the additive 
package being reconciled, the maximum recommended treatment level, the 
potential contribution to the sulfur content of the finished fuel that 
might result when the additive package is used at its maximum 
recommended treatment level, the intended treatment level, and the 
contribution to the sulfur content of the finished fuel that

[[Page 986]]

would result when the additive package is used at its intended treatment 
level.
    (A) The maximum recommended treatment level and the intended 
treatment level must be expressed in terms of gallons of additive 
package per thousand gallons of MVNRLM diesel fuel, and expressed to 
four significant figures.
    (B) If the additive package storage system which is the subject of 
the VAR formula record is a proprietary system under the control of a 
customer, this fact must be indicated on the record.
    (ii) The date of the additization that is the subject of the VAR 
formula record.
    (iii) The volume of added additive package.
    (iv) The volume of the MVNRLM diesel fuel to which the additive 
package has been added.
    (v) The brand (if known) of MVNRLM diesel fuel.
    (vi) The actual additive package concentration, calculated as the 
volume of added additive package (pursuant to paragraph (f)(1)(ii)(B) of 
this section), divided by the volume of MVNRLM diesel fuel (pursuant to 
paragraph (f)(1)(iii) of this section). The concentration must be 
calculated and recorded to four significant figures.
    (vii) The measured sulfur level for each batch of MVNRLM diesel fuel 
to which the additive package is added during each VAR period. In cases 
where the storage tanks that contains MVNRLM diesel fuel prior to 
additization contains multiple fuel batches, a measured sulfur level on 
each batch added to the storage tank during the current and previous VAR 
periods must be recorded.
    (3) VAR formula records. Every VAR formula record created pursuant 
to paragraphs (f)(1) and (f)(2) of this section shall contain the 
following:
    (i) The signature of the creator of the VAR record;
    (ii) The date of the creation of the VAR record; and
    (iii) A certification of correctness by the creator of the VAR 
record.
    (4) Electronically-generated VAR formula and supporting records. (i) 
Electronically-generated records are acceptable for VAR formula records 
and supporting documentation (including PTDs), provided that they are 
complete, accessible, and easily readable. VAR formula records must also 
be stored with access and audit security, which must restrict to a 
limited number of specified people those who have the ability to alter 
or delete the records. In addition, parties maintaining records 
electronically must make available to EPA the hardware and software 
necessary to review the records.
    (ii) Electronically-generated VAR formula records may use an 
electronic user identification code to satisfy the signature 
requirements of paragraph (f)(3)(i) of this section, provided that:
    (A) The use of the identification is limited to the record creator; 
and
    (B) A paper record is maintained, which is signed and dated by the 
VAR formula record creator, acknowledging that the use of that 
particular user ID on a VAR formula record is equivalent to his/her 
signature on the document.
    (5) Calibration requirements for automated blending facilities. 
Automated static dissipater additive package blenders must calibrate 
their additive package equipment at least once in each calendar half 
year, with the acceptable calibrations being no less than one hundred 
twenty days apart, except that calibrations may be closer in time so 
long as at least two calibrations meet the requirements to be in 
separate halves of the calendar year and no less than 120 days apart. 
Equipment recalibration is also required each time the static dissipater 
additive package is changed, unless written documentation indicates that 
the new additive package has the same viscosity as the previous additive 
package. Additive package change calibrations may be used to satisfy the 
semiannual requirement provided that the calibrations occur in the 
appropriate half calendar year and are no less than one hundred twenty 
days apart.
    (6) Additional VAR documentation. The following VAR supporting 
documentation must also be created and maintained:
    (i) For all automated additive package blending facilities, 
documentation reflecting performance of the calibrations required by 
paragraph (f)(5) of

[[Page 987]]

this section, and any associated adjustments of the automated additive 
package injection equipment;
    (ii) For all blending facilities that blend an additive package 
containing a static dissipater additive and/or red dye, product transfer 
documents for all such additive packages, and MVNRLM diesel fuel 
transferred into or out of the facility that is additized with an 
additive package containing a static dissipater additive and/or red dye;
    (iii) For all automated additive package blending facilities that 
use an additive package containing a static dissipater additive and/or 
red dye, documentation establishing the brands (if known) of the MVNRLM 
diesel fuel which is the subject of the VAR formula record; and
    (iv) For all hand blenders of an additive package that contains a 
static dissipater additive and/or red dye, the documentation, if in the 
party's possession, supporting the volumes of MVNRLM diesel fuel and 
additive package reported on the VAR formula record.
    (7) Document retention and availability. All blenders of an additive 
package that contains a static dissipater additive and/or red dye shall 
retain the documents required under this section for a period of five 
years from the date the VAR formula records and supporting documentation 
are created, and shall deliver them upon request to the EPA 
Administrator or the Administrator's authorized representative.
    (i) Except as provided in paragraph (f)(7)(iii) of this section, 
automated additive package blender facilities and hand-blender 
facilities which are terminals, which physically blend an additive 
packages that contains a static dissipater additive and/or red dye into 
MVNRLM diesel fuel, must make immediately available to EPA, upon 
request, the preceding twelve months of VAR formula records plus the 
preceding two months of VAR supporting documentation.
    (ii) Except as provided in paragraph (f)(7)(iii) of this section, 
other hand-blending additive package facilities which physically blend 
additive package that contains a static dissipater additive and/or red 
dye into MVNRLM diesel fuel must make immediately available to EPA, upon 
request, the preceding two months of VAR formula records and VAR 
supporting documentation.
    (iii) Facilities which have centrally maintained records at other 
locations, or have customers who maintain their own records at other 
locations for their proprietary additive package injection systems, and 
which can document this fact to the Agency, may have until the start of 
the next business day after the EPA request to supply VAR supporting 
documentation, or longer if approved by the Agency.
    (iv) In this paragraph (f)(7), the term ``immediately available'' 
means that the records must be provided, electronically or otherwise, 
within approximately one hour of EPA's request, or within a longer time 
frame as approved by EPA.

[69 FR 39205, June 29, 2004, as amended at 71 FR 25723, May 1, 2006]



Sec. 80.615  What penalties apply under this subpart?

    (a) Any person liable for a violation under Sec. 80.612 is subject 
to civil penalties as specified in section 205 of the Clean Air Act (42 
U.S.C. 7524) for every day of each such violation and the amount of 
economic benefit or savings resulting from each violation.
    (b)(1) Any person liable under Sec. 80.612(a)(1) for a violation of 
an applicable standard or requirement under this Subpart I or for 
causing another party to violate such standard or requirement, is 
subject to a separate day of violation for each and every day the non-
complying diesel fuel remains any place in the distribution system.
    (2) Any person liable under Sec. 80.612(a)(2) for causing motor 
vehicle diesel fuel, NRLM diesel fuel, heating oil, or other distillate 
fuel to be in the distribution system which does not comply with an 
applicable standard or requirement of this Subpart I is subject to a 
separate day of violation for each and every day that the non-complying 
diesel fuel remains any place in the diesel fuel distribution system.
    (3) Any person liable under Sec. 80.612(a)(1) for blending into 
diesel

[[Page 988]]

fuel an additive violating the applicable sulfur standard pursuant to 
the requirements of Sec. 80.521(a) or (b), as applicable, or of causing 
another party to so blend such an additive, is subject to a separate day 
of violation for each and every day the motor vehicle diesel fuel or 
NRLM diesel fuel into which the noncomplying additive was blended, 
remains any place in the fuel distribution system.
    (4) For purposes of this paragraph (b) of this section, the length 
of time the motor vehicle diesel fuel, NRLM diesel fuel, heating oil or 
other distillate fuel in question remained in the diesel fuel 
distribution system is deemed to be 25 days, unless a person subject to 
liability or EPA demonstrates by reasonably specific showings, by direct 
or circumstantial evidence, that the non-complying motor vehicle, NR or 
NRLM diesel fuel, heating oil or distillate fuel remained in the 
distribution system for fewer than or more than 25 days.
    (c) Any person liable under Sec. 80.612(b) for failure to meet, or 
causing a failure to meet, a provision of this subpart is liable for a 
separate day of violation for each and every day such provision remains 
unfulfilled.

[69 FR 39208, June 29, 2004]



Sec. 80.616  What are the enforcement exemptions for California
diesel distributed within the State of California?

    (a) For the purpose of this section, ``California diesel fuel'' is 
defined as any diesel fuel physically within the State of California 
that satisfies all requirements of Title 13, California Code of 
Regulations, Sections 2281-2285, and is sold, intended for sale, or made 
available for sale as a motor fuel in the State of California, 
subsequent to May 31, 2006.
    (b) Any retailer or wholesale purchaser-consumer of California 
diesel fuel is, with regard to such diesel fuel, exempt from the 
labeling requirements contained in Sec. Sec. 80.570, 80.571, 80.572, 
80.573, and 80.574.
    (c)(1) Any refiner, importer, or distributor of California diesel 
fuel is, with regard to such diesel fuel, exempt from the product 
transfer requirements of Sec. 80.590, provided that the product 
transfer document contains the following statement:
    ``California diesel fuel. Maximum 15 ppm sulfur.''
    (2) Product codes may be used to satisfy this product transfer 
document requirement.
    (d) Any refiner, importer, or distributor of California diesel fuel 
is, with regard to such diesel fuel, exempt from the designation 
requirements of Sec. 80.598, provided that:
    (1) The refiner, importer, or distributor does not transfer custody 
of the California diesel fuel to facility outside the State of 
California;
    (2) The fuel is intended to be sold or made available for sale in 
the State of California; and
    (3) The PTD requirements in paragraph (f) of the section are 
satisfied.
    (e) Any refiner, importer, or distributor of California diesel fuel 
is, with regard to such diesel fuel, exempt from the volume balance 
requirements of Sec. 80.599.
    (f) Any refiner, importer, or distributor of California diesel fuel 
is, with regard to such diesel fuel, exempt from the recordkeeping 
requirements under designate and track provisions of Sec. 80.600.
    (g) Any refiner, importer, or distributor of California diesel fuel 
is, with regard to such diesel fuel, exempt from the reporting 
requirements for the purposes of the designate and track provisions of 
Sec. 80.601.
    (h) Any refiner, importer, or distributor of California diesel fuel 
is, with regard to such diesel fuel, exempt from the recordkeeping 
requirements for entities in the MV or NRLM diesel fuel and diesel fuel 
additive production, importation, and distribution systems of Sec. Sec. 
80.592 and 80.602 except those relating to sampling and testing, under 
Sec. Sec. 80.581, 80.584, 80.585, and 80.586.
    (i) Any refiner or importer of California diesel fuel is, with 
regard to such diesel fuel, exempt from the annual reporting 
requirements for NRLM diesel under Sec. 80.604.

[71 FR 25725, May 1, 2006]

[[Page 989]]



Sec. 80.617  How may California diesel fuel be distributed or sold 
outside of the State of California?

    California diesel may be distributed or sold outside of the State of 
California provided the provisions of either paragraph (a) or (b) of 
this section are satisfied:
    (a) Distribution of taxed or dyed California diesel fuel. California 
diesel fuel that is distributed from a truck loading terminal after such 
diesel has been taxed or dyed may be distributed or sold outside of the 
State of California, provided that it is accompanied by a Product 
Transfer Document that states: ``California diesel fuel. Maximum 15 ppm 
sulfur.''; or
    (b) Distribution of untaxed and undyed diesel California diesel 
fuel. California diesel may be distributed or sold outside of the State 
of California without having been dyed or taxed provided that the 
requirements of either paragraph (b)(1) or (b)(2) of this section are 
satisfied. (Note that the requirements of IRS code 26 CFR part 48 along 
with other applicable requirements outside of this 40 CFR part 80 
subpart I must also be satisfied.)
    (1)(i) Prior to shipment outside the State of California, the 
California diesel fuel meets all requirements of Sec. 80.616 and meets 
all of the requirements of 40 CFR part 80, subpart I that are not 
exempted under this section;
    (ii) The California diesel fuel is shipped out of the state via 
pipeline;
    (iii) The pipeline shipping the California diesel out of state 
maintains the California diesel fuel designation while the product is in 
the pipeline's custody;
    (iv) The pipeline provides a product transfer document that clearly 
indicates that the product is designated as California diesel fuel;
    (v) Upon delivery into the terminal, the terminal receiving the 
California diesel fuel redesignates it as motor vehicle diesel meeting 
the 15 ppm sulfur standard; and
    (vi) The terminal includes the volumes of California diesel fuel 
redesignated as motor vehicle diesel fuel in the total volume of motor 
vehicle diesel designated meeting the 15 ppm sulfur standard received by 
the terminal, per the volume balance and anti-downgrading equations for 
motor vehicle diesel fuel found in Sec. 80.599(b) and (e).
    (2)(i) The California diesel fuel is delivered via pipeline to a 
terminal outside the State of California that has a tank dedicated to 
the receipt of California diesel fuel and which intends to distribute 
the diesel fuel from the dedicated tank back into the State of 
California;
    (ii) The terminal must maintain the designation of the diesel fuel 
as ``California diesel fuel'' and not redesignate it to another product;
    (iii) The product transfer documents for California diesel fuel 
distributed by a terminal outside of the state of California must 
indicate ``California diesel fuel. Maximum 15 ppm sulfur.''; and,
    (iv) Any volume of California diesel fuel distributed by a terminal 
outside the state of California must be taxed or dyed and must be 
excluded from the terminal's volume balance equations under Sec. 
80.599.

[71 FR 25726, May 1, 2006]



Sec. Sec. 80.618-80.619  [Reserved]

 Provisions for Foreign Refiners and Importers for Motor Vehicle Diesel 
   Fuel Subject to a Temporary Compliance Option or Hardship Provision



Sec. 80.620  What are the additional requirements for diesel fuel or 
distillates produced by foreign refineries subject to a temporary 

refiner compliance 
          option, hardship provisions, or motor vehicle or NRLM diesel 
          fuel credit provisions?

    (a) Definitions. (1) A foreign refinery is a refinery that is 
located outside the United States, the Commonwealth of Puerto Rico, the 
Virgin Islands, Guam, American Samoa, and the Commonwealth of the 
Northern Mariana Islands (collectively referred to in this section as 
``the United States'').
    (2) A foreign refiner is a person who meets the definition of 
refiner under Sec. 80.2(i) for a foreign refinery.
    (3) A diesel fuel program foreign refiner (``DFR'') is a foreign 
refiner that has been approved by EPA for participation in any motor 
vehicle diesel fuel or NRLM diesel fuel provision of Sec. 80.530 
through 80.533, or Sec. Sec. 80.535, 80.536, 80.540,

[[Page 990]]

80.552, 80.553, 80.554, 80.560 or 80.561 (collectively referred to as 
``diesel foreign refiner program'').
    (4) ``DFR-Diesel'' means diesel fuel or distillate fuel as 
applicable under subpart I of this part produced at a DFR refinery that 
is imported into the United States.
    (5) ``Non-DFR-Diesel'' means diesel fuel or distillate fuel that is 
produced at a foreign refinery that has not been approved as a DFR 
foreign refiner, diesel fuel produced at a DFR foreign refinery that is 
not imported into the United States, and diesel fuel produced at a DFR 
foreign refinery during a period when the foreign refiner has opted to 
not participate in the DFR-Diesel foreign refiner program under 
paragraph (c)(3) of this section.
    (6) ``Certified DFR-Diesel'' means DFR-Diesel the foreign refiner 
intends to include in the foreign refinery's compliance calculations 
under any provisions of Sec. 80.530 through 80.533, or Sec. Sec. 
80.535, 80.536, 80.540, 80.552, 80.553, 80.554, 80.560 or 80.561 and 
does include in these compliance calculations when reported to EPA.
    (7) ``Non-Certified DFR-Diesel'' means DFR-Diesel fuel that a DFR 
foreign refiner imports to the United States that is not Certified DFR-
Diesel.
    (b) Baseline. For any foreign refiner to obtain approval under the 
diesel foreign refiner program of this subpart for any refinery, it must 
apply for approval under the applicable provisions of this subpart. To 
obtain approval the refiner is required, as applicable, to demonstrate a 
volume baseline under subpart I of this part.
    (1) The refiner shall follow the procedures, applicable to volume 
baselines and using diesel fuel, or if applicable, heating oil, instead 
of gasoline, in Sec. Sec. 80.91 through 80.93 to establish the volume 
of motor vehicle diesel fuel that was produced at the refinery and 
imported into the United States during the applicable years for purposes 
of establishing a baseline under Subpart I for applicable fuels produced 
for use in the United States.
    (2) In making determinations for foreign refinery baselines EPA will 
consider all information supplied by a foreign refiner, and in addition 
may rely on any and all appropriate assumptions necessary to make such 
determinations.
    (3) Where a foreign refiner submits a petition that is incomplete or 
inadequate to establish an accurate baseline, and the refiner fails to 
correct this deficiency after a request for more information, EPA will 
not assign an individual refinery baseline.
    (c) General requirements for DFR foreign refiners. A foreign refiner 
of a refinery that is approved under the diesel foreign refiner program 
of this subpart must designate each batch of diesel fuel produced at the 
foreign refinery that is exported to the United States as either 
Certified DFR-Diesel or as Non-Certified DFR-Diesel, except as provided 
in paragraph (c)(3) of this section. It must further designate all 
Certified DFR-Diesel as provided in Sec. 80.598, and designate whether 
the diesel fuel is dyed or undyed, and for heating oil and/or locomotive 
or marine diesel fuel whether it is marked or unmarked under Sec. 
80.510(d) through (f). It must further designate any credits earned as 
either nonroad diesel credits or motor vehicle diesel credits.
    (1) In the case of Certified DFR-Diesel, the foreign refiner must 
meet all requirements that apply to refiners under this subpart, except 
that:
    (i) For purposes of complying with the compliance option 
requirements of Sec. 80.530, motor vehicle diesel fuel produced by a 
foreign refinery must comply separately for each Credit Trading Area of 
import, as defined in Sec. 80.531(a)(5).
    (ii) For purposes of complying with the compliance option 
requirements of Sec. 80.530, credits obtained from any other refinery 
or from any importer must have been generated in the same Credit Trading 
Area as the Credit Trading Area of import of the fuel for which credits 
are needed to achieve compliance.
    (iii) For purposes of generating credits under Sec. 80.531, credits 
shall be generated separately by Credit Trading Area of import and shall 
be designated by Credit Trading Area of importation and by port of 
importation.
    (2) In the case of Non-Certified DFR-Diesel, the foreign refiner 
shall meet all the following requirements:

[[Page 991]]

    (i) The designation requirements in this section.
    (ii) The reporting requirements in this section and in Sec. Sec. 
80.593, 80.594, 80.601, and 80.604.
    (iii) The product transfer document requirements in this section and 
in Sec. Sec. 80.590 and 80.591.
    (iv) The prohibitions in this section and in Sec. 80.610.
    (3)(i) Any foreign refiner that has been approved to produce diesel 
fuel subject to the diesel foreign refiner program for a foreign 
refinery under this subpart may elect to classify no diesel fuel 
imported into the United States as DFR-Diesel provided the foreign 
refiner notifies EPA of the election no later than 60 calendar days 
prior to the beginning of the compliance period.
    (ii) An election under paragraph (c)(3)(i) of this section shall be 
for a 12 month compliance period and apply to all diesel fuel that is 
produced by the foreign refinery that is imported into the United 
States, and shall remain in effect for each succeeding year unless and 
until the foreign refiner notifies EPA of the termination of the 
election. The change in election shall take effect at the beginning of 
the next annual compliance period.
    (d) Designation, product transfer documents, and foreign refiner 
certification. (1) Any foreign refiner of a foreign refinery that has 
been approved by EPA to produce motor vehicle diesel fuel subject to the 
diesel foreign refiner program must designate each batch of DFR-Diesel 
as such at the time the diesel fuel is produced, unless the refiner has 
elected to classify no diesel fuel exported to the United States as DFR-
Diesel under paragraph (c)(3) of this section.
    (2) On each occasion when any person transfers custody or title to 
any DFR-Diesel prior to its being imported into the United States, it 
must include the following information as part of the product transfer 
document information in this section:
    (i) Designation of the diesel fuel or distillate as Certified DFR-
Diesel or as Non-Certified DFR-Diesel, and if it is Certified DFR-
Diesel, further designate the fuel pursuant to Sec. 80.598, and whether 
the diesel fuel or distillate is dyed or undyed, and for heating oil 
whether it is marked or unmarked under Sec. 80.510(d) through (f), and 
all other applicable product transfer document information required 
under Sec. 80.590; and
    (ii) The name and EPA refinery registration number (under Sec. 
80.597) of the refinery where the DFR-Diesel was produced.
    (3) On each occasion when DFR-Diesel is loaded onto a vessel or 
other transportation mode for transport to the United States, the 
foreign refiner shall prepare a certification for each batch of the DFR-
Diesel that meets the following requirements.
    (i) The certification shall include the report of the independent 
third party under paragraph (f) of this section, and the following 
additional information:
    (A) The name and EPA registration number of the refinery that 
produced the DFR-Diesel;
    (B) The identification of the diesel fuel as Certified DFR-Diesel or 
Non-Certified DFR-Diesel;
    (C) The volume of DFR-Diesel being transported, in gallons;
    (D) In the case of Certified DFR-Diesel:
    (1) The sulfur content as determined under paragraph (f) of this 
section, and the applicable designations stated in paragraph (d)(2)(i) 
of this section; and
    (2) A declaration that the DFR-Diesel is being included in the 
applicable compliance calculations required by EPA under this subpart.
    (ii) The certification shall be made part of the product transfer 
documents for the DFR-Diesel.
    (e) Transfers of DFR-Diesel to non-United States markets. The 
foreign refiner is responsible to ensure that all diesel fuel classified 
as DFR-Diesel is imported into the United States. A foreign refiner may 
remove the DFR-Diesel classification, and the diesel fuel need not be 
imported into the United States, but only if:
    (1)(i) The foreign refiner excludes:
    (A) The volume of diesel from the refinery's compliance report under 
Sec. 80.593, Sec. 80.601, or Sec. 80.604; and
    (B) In the case of Certified DFR-Diesel, the volume of the diesel 
fuel from the compliance report under Sec. 80.593, Sec. 80.601, or 
Sec. 80.604.

[[Page 992]]

    (ii) The exclusions under paragraph (e)(1)(i) of this section shall 
be on the basis of the designations under Sec. 80.598 and this section, 
and volumes determined under paragraph (f) of this section.
    (2) The foreign refiner obtains sufficient evidence in the form of 
documentation that the diesel fuel was not imported into the United 
States.
    (f) Load port independent sampling, testing and refinery 
identification. (1) On each occasion that DFR-Diesel is loaded onto a 
vessel for transport to the United States a foreign refiner shall have 
an independent third party:
    (i) Inspect the vessel prior to loading and determine the volume of 
any tank bottoms;
    (ii) Determine the volume of DFR-Diesel loaded onto the vessel 
(exclusive of any tank bottoms before loading);
    (iii) Obtain the EPA-assigned registration number of the foreign 
refinery;
    (iv) Determine the name and country of registration of the vessel 
used to transport the DFR-Diesel to the United States; and
    (v) Determine the date and time the vessel departs the port serving 
the foreign refinery.
    (2) On each occasion that Certified DFR-Diesel is loaded onto a 
vessel for transport to the United States a foreign refiner shall have 
an independent third party:
    (i) Collect a representative sample of the Certified DFR-Diesel from 
each vessel compartment subsequent to loading on the vessel and prior to 
departure of the vessel from the port serving the foreign refinery;
    (ii) Determine the sulfur content value for each compartment, and if 
applicable, the marker content under Sec. 80.510(d) through (f) using 
an approved methodology as specified in Sec. Sec. 80.580 through 80.586 
by one of the following:
    (A) The third party analyzing each sample; or
    (B) The third party observing the foreign refiner analyze the 
sample;
    (iii) Review original documents that reflect movement and storage of 
the certified DFR-Diesel from the refinery to the load port, and from 
this review determine:
    (A) The refinery at which the DFR-Diesel was produced; and
    (B) That the DFR-Diesel remained segregated from:
    (1) Non-DFR-Diesel and Non-Certified DFR-Diesel; and
    (2) Other Certified DFR-Diesel produced at a different refinery.
    (3) The independent third party shall submit a report:
    (i) To the foreign refiner containing the information required under 
paragraphs (f)(1) and (f)(2) of this section, to accompany the product 
transfer documents for the vessel; and
    (ii) To the Administrator containing the information required under 
paragraphs (f)(1) and (f)(2) of this section, within thirty days 
following the date of the independent third party's inspection. This 
report shall include a description of the method used to determine the 
identity of the refinery at which the diesel fuel or distillate was 
produced, assurance that the diesel fuel or distillate remained 
segregated as specified in paragraph (n)(1) of this section, and a 
description of the diesel fuel's movement and storage between production 
at the source refinery and vessel loading.
    (4) The independent third party must:
    (i) Be approved in advance by EPA, based on a demonstration of 
ability to perform the procedures required in this paragraph (f);
    (ii) Be independent under the criteria specified in Sec. 
80.65(e)(2)(iii); and
    (iii) Sign a commitment that contains the provisions specified in 
paragraph (i) of this section with regard to activities, facilities and 
documents relevant to compliance with the requirements of this paragraph 
(f).
    (g) Comparison of load port and port of entry testing. (1)(i) Any 
foreign refiner and any United States importer of Certified DFR-Diesel 
shall compare the results from the load port testing under paragraph (f) 
of this section, with the port of entry testing as reported under 
paragraph (o) of this section, for the volume of diesel fuel and the 
sulfur content value; except as specified in paragraph (g)(1)(ii) of 
this section.
    (ii) Where a vessel transporting Certified DFR-Diesel off loads this 
diesel fuel at more than one United States port of entry, and the 
conditions of

[[Page 993]]

paragraph (g)(2)(i) of this section are met at the first United States 
port of entry, the requirements of paragraph (g)(2) of this section do 
not apply at subsequent ports of entry if the United States importer 
obtains a certification from the vessel owner that meets the 
requirements of paragraph (s) of this section, that the vessel has not 
loaded any diesel fuel or blendstock between the first United States 
port of entry and the subsequent port of entry.
    (2)(i) The requirements of this paragraph (g)(2) apply if--
    (A) The temperature-corrected volumes determined at the port of 
entry and at the load port differ by more than one percent; or
    (B) The sulfur content value determined at the port of entry is 
higher than the sulfur content value determined at the load port, and 
the amount of this difference is greater than the reproducibility amount 
specified for the port of entry test result by the American Society of 
Testing and Materials (ASTM) for a test method used for testing the port 
of entry sample under the provisions Sec. Sec. 80.580 through 80.586.
    (ii) The United States importer and the foreign refiner shall treat 
the diesel fuel as Non-Certified DFR-Diesel, and the foreign refiner 
shall exclude the diesel fuel volume from its diesel fuel volumes 
calculations and sulfur standard designations under Sec. 80.598.
    (h) Attest requirements. Refiners, for each annual compliance 
period, must arrange to have an attest engagement performed of the 
underlying documentation that forms the basis of any report required 
under this subpart. The attest engagement must comply with the 
procedures and requirements that apply to refiners under Sec. Sec. 
80.125 through 80.130, or other applicable attest engagement provisions, 
and must be submitted to the Administrator of EPA by August 31 of each 
year for the prior annual compliance period. The following additional 
procedures shall be carried out for any foreign refiner of DFR-Diesel.
    (1) The inventory reconciliation analysis under Sec. 80.128(b) and 
the tender analysis under Sec. 80.128(c) shall include Non-DFR-Diesel.
    (2) Obtain separate listings of all tenders of Certified DFR-Diesel 
and of Non-Certified DFR-Diesel, and obtain separate listings of 
Certified DFR-Diesel based on whether it is 15 ppm sulfur content diesel 
fuel, 500 ppm sulfur content diesel fuel or high sulfur fuel having a 
sulfur content greater than 500 ppm (and if so, whether the fuel is 
heating oil, small refiner diesel fuel, diesel fuel produced through the 
use of credits, or other applicable designation under Sec. 80.598). 
Agree the total volume of tenders from the listings to the diesel fuel 
inventory reconciliation analysis in Sec. 80.128(b), and to the volumes 
determined by the third party under paragraph (f)(1) of this section.
    (3) For each tender under paragraph (h)(2) of this section, where 
the diesel fuel is loaded onto a marine vessel, report as a finding the 
name and country of registration of each vessel, and the volumes of DFR-
Diesel loaded onto each vessel.
    (4) Select a sample from the list of vessels identified in paragraph 
(h)(3) of this section used to transport Certified DFR-Diesel, in 
accordance with the guidelines in Sec. 80.127, and for each vessel 
selected perform the following:
    (i) Obtain the report of the independent third party, under 
paragraph (f) of this section, and of the United States importer under 
paragraph (o) of this section.
    (A) Agree the information in these reports with regard to vessel 
identification, diesel fuel volumes and sulfur content test results.
    (B) Identify, and report as a finding, each occasion the load port 
and port of entry sulfur content and volume results differ by more than 
the amounts allowed in paragraph (g) of this section, and determine 
whether the foreign refiner adjusted its refinery calculations as 
required in paragraph (g) of this section.
    (ii) Obtain the documents used by the independent third party to 
determine transportation and storage of the Certified DFR-Diesel from 
the refinery to the load port, under paragraph (f) of this section. 
Obtain tank activity records for any storage tank where the Certified 
DFR-Diesel is stored, and pipeline activity records for any pipeline 
used to transport the Certified DFR-Diesel, prior to being loaded onto

[[Page 994]]

the vessel. Use these records to determine whether the Certified DFR-
Diesel was produced at the refinery that is the subject of the attest 
engagement, and whether the Certified DFR-Diesel was mixed with any Non-
Certified DFR-Diesel, Non-DFR-Diesel, or any Certified DFR-Diesel 
produced at a different refinery.
    (5) Select a sample from the list of vessels identified in paragraph 
(h)(3) of this section used to transport certified and Non-Certified 
DFR-Diesel, in accordance with the guidelines in Sec. 80.127, and for 
each vessel selected perform the following:
    (i) Obtain a commercial document of general circulation that lists 
vessel arrivals and departures, and that includes the port and date of 
departure of the vessel, and the port of entry and date of arrival of 
the vessel.
    (ii) Agree the vessel's departure and arrival locations and dates 
from the independent third party and United States importer reports to 
the information contained in the commercial document.
    (6) Obtain separate listings of all tenders of Non-DFR-Diesel, and 
perform the following:
    (i) Agree the total volume and sulfur content of tenders from the 
listings to the diesel fuel inventory reconciliation analysis in Sec. 
80.128(b).
    (ii) Obtain a separate listing of the tenders under this paragraph 
(h)(6) where the diesel fuel is loaded onto a marine vessel. Select a 
sample from this listing in accordance with the guidelines in Sec. 
80.127, and obtain a commercial document of general circulation that 
lists vessel arrivals and departures, and that includes the port and 
date of departure and the ports and dates where the diesel fuel was off 
loaded for the selected vessels. Determine and report as a finding the 
country where the diesel fuel was off loaded for each vessel selected.
    (7) In order to complete the requirements of this paragraph (h) an 
auditor shall:
    (i) Be independent of the foreign refiner;
    (ii) Be licensed as a Certified Public Accountant in the United 
States and a citizen of the United States, or be approved in advance by 
EPA based on a demonstration of ability to perform the procedures 
required in Sec. Sec. 80.125 through 80.130 and this paragraph (h); and
    (iii) Sign a commitment that contains the provisions specified in 
paragraph (i) of this section with regard to activities and documents 
relevant to compliance with the requirements of Sec. Sec. 80.125 
through 80.130 and this paragraph (h).
    (i) Foreign refiner commitments. Any foreign refiner shall commit to 
and comply with the provisions contained in this paragraph (i) as a 
condition to being approved for a temporary refiner diesel fuel program 
option.
    (1) Any United States Environmental Protection Agency inspector or 
auditor must be given full, complete and immediate access to conduct 
inspections and audits of the foreign refinery.
    (i) Inspections and audits may be either announced in advance by 
EPA, or unannounced.
    (ii) Access will be provided to any location where:
    (A) Diesel fuel is produced;
    (B) Documents related to refinery operations are kept;
    (C) Diesel fuel or blendstock samples are tested or stored; and
    (D) DFR-Diesel is stored or transported between the foreign refinery 
and the United States, including storage tanks, vessels and pipelines.
    (iii) Inspections and audits may be by EPA employees or contractors 
to EPA.
    (iv) Any documents requested that are related to matters covered by 
inspections and audits must be provided to an EPA inspector or auditor 
on request.
    (v) Inspections and audits by EPA may include review and copying of 
any documents related to:
    (A) Refinery baseline establishment, if applicable, including the 
volume, sulfur content and dye and marker status of diesel fuel, heating 
oil and other distillates; transfers of title or custody of any diesel 
fuel, heating oil or blendstocks whether DFR-Diesel or Non-DFR-Diesel, 
produced at the foreign refinery during the period January 1, 1998 
through the date of the refinery baseline petition or through the date 
of the inspection or audit if a

[[Page 995]]

baseline petition has not been approved, and any work papers related to 
refinery baseline establishment;
    (B) The volume and sulfur content of DFR-Diesel;
    (C) The proper classification of diesel fuel as being DFR-Diesel or 
as not being DFR-Diesel, or as Certified DFR-Diesel or as Non-Certified 
DFR-Diesel, and all other relevant designations under this subpart, 
including Sec. 80.598 and this section;
    (D) Transfers of title or custody to DFR-Diesel;
    (E) Sampling and testing of DFR-Diesel;
    (F) Work performed and reports prepared by independent third parties 
and by independent auditors under the requirements of this section, 
including work papers; and
    (G) Reports prepared for submission to EPA, and any work papers 
related to such reports.
    (vi) Inspections and audits by EPA may include taking samples of 
diesel fuel, heating oil, other distillates, diesel fuel additives or 
blendstock, dyes and chemical markers and interviewing employees.
    (vii) Any employee of the foreign refiner must be made available for 
interview by the EPA inspector or auditor, on request, within a 
reasonable time period.
    (viii) English language translations of any documents must be 
provided to an EPA inspector or auditor, on request, within 10 working 
days.
    (ix) English language interpreters must be provided to accompany EPA 
inspectors and auditors, on request.
    (2) An agent for service of process located in the District of 
Columbia shall be named, and service on this agent constitutes service 
on the foreign refiner or any employee of the foreign refiner for any 
action by EPA or otherwise by the United States related to the 
requirements of this subpart.
    (3) The forum for any civil or criminal enforcement action related 
to the provisions of this section for violations of the Clean Air Act or 
regulations promulgated thereunder shall be governed by the Clean Air 
Act, including the EPA administrative forum where allowed under the 
Clean Air Act.
    (4) United States substantive and procedural laws shall apply to any 
civil or criminal enforcement action against the foreign refiner or any 
employee of the foreign refiner related to the provisions of this 
section.
    (5) Submitting a petition for participation in the diesel foreign 
refiner program or producing and exporting diesel fuel or heating oil 
under any such program, and all other actions to comply with the 
requirements of this subpart relating to participation in any diesel 
foreign refiner program, or to establish an individual refinery motor 
vehicle diesel fuel volume baseline or other baseline under subpart I of 
this part (if applicable) constitute actions or activities that satisfy 
the provisions of 28 U.S.C. 1605(a)(2), but solely with respect to 
actions instituted against the foreign refiner, its agents and employees 
in any court or other tribunal in the United States for conduct that 
violates the requirements applicable to the foreign refiner under this 
subpart, including conduct that violates the False Statements 
Accountability Act of 1996 (18 U.S.C. 1001) and section 113(c)(2) of the 
Clean Air Act (42 U.S.C. 7413).
    (6) The foreign refiner, or its agents or employees, will not seek 
to detain or to impose civil or criminal remedies against EPA inspectors 
or auditors, whether EPA employees or EPA contractors, for actions 
performed within the scope of EPA employment related to the provisions 
of this section.
    (7) The commitment required by this paragraph (i) shall be signed by 
the owner or president of the foreign refiner business.
    (8) In any case where DFR-Diesel produced at a foreign refinery is 
stored or transported by another company between the refinery and the 
vessel that transports the DFR-Diesel to the United States, the foreign 
refiner shall obtain from each such other company a commitment that 
meets the requirements specified in paragraphs (i)(1) through (7) of 
this section, and these commitments shall be included in the foreign 
refiner's petition to participate in any diesel foreign refiner program 
.
    (j) Sovereign immunity. By submitting a petition for participation 
in any diesel foreign refiner program under this

[[Page 996]]

subpart (and baseline, if applicable) under this section, or by 
producing and exporting diesel fuel to the United States under any such 
program, the foreign refiner, and its agents and employees, without 
exception, become subject to the full operation of the administrative 
and judicial enforcement powers and provisions of the United States 
without limitation based on sovereign immunity, with respect to actions 
instituted against the foreign refiner, its agents and employees in any 
court or other tribunal in the United States for conduct that violates 
the requirements applicable to the foreign refiner under this subpart 
including conduct that violates the False Statements Accountability Act 
of 1996 (18 U.S.C. 1001) and section 113(c)(2) of the Clean Air Act (42 
U.S.C. 7413).
    (k) Bond posting. Any foreign refiner shall meet the requirements of 
this paragraph (k) as a condition to approval for any diesel foreign 
refiner program under this subpart.
    (1) The foreign refiner shall post a bond of the amount calculated 
using the following equation:


Bond = G x $ 0.01

Where:

Bond = amount of the bond in U.S. dollars
G = the applicable volume baseline under Subpart I for diesel fuel or 
distillate produced at the foreign refinery and exported to the United 
States, in gallons.

    (2) Bonds shall be posted by:
    (i) Paying the amount of the bond to the Treasurer of the United 
States;
    (ii) Obtaining a bond in the proper amount from a third party surety 
agent that is payable to satisfy United States administrative or 
judicial judgments against the foreign refiner, provided EPA agrees in 
advance as to the third party and the nature of the surety agreement; or
    (iii) An alternative commitment that results in assets of an 
appropriate liquidity and value being readily available to the United 
States, provided EPA agrees in advance as to the alternative commitment.
    (3) Bonds posted under this paragraph (k) shall--
    (i) Be used to satisfy any judicial judgment that results from an 
administrative or judicial enforcement action for conduct in violation 
of this subpart, including where such conduct violates the False 
Statements Accountability Act of 1996 (18 U.S.C. 1001) and section 
113(c)(2) of the Clean Air Act (42 U.S.C. 7413);
    (ii) Be provided by a corporate surety that is listed in the United 
States Department of Treasury Circular 570 ``Companies Holding 
Certificates of Authority as Acceptable Sureties on Federal Bonds;'' and
    (iii) Include a commitment that the bond will remain in effect for 
at least five years following the end of latest annual reporting period 
that the foreign refiner produces diesel fuel pursuant to the 
requirements of this subpart.
    (4) On any occasion a foreign refiner bond is used to satisfy any 
judgment, the foreign refiner shall increase the bond to cover the 
amount used within 90 days of the date the bond is used.
    (5) If the bond amount for a foreign refiner increases, the foreign 
refiner shall increase the bond to cover the shortfall within 90 days of 
the date the bond amount changes. If the bond amount decreases, the 
foreign refiner may reduce the amount of the bond beginning 90 days 
after the date the bond amount changes.
    (l) [Reserved]
    (m) English language reports. Any report or other document submitted 
to EPA by a foreign refiner shall be in English language, or shall 
include an English language translation.
    (n) Prohibitions. (1) No person may combine Certified DFR-Diesel 
with any Non-Certified DFR-Diesel or Non-DFR-Diesel, and no person may 
combine Certified DFR-Diesel with any Certified DFR-Diesel produced at a 
different refinery, until the importer has met all the requirements of 
paragraph (o) of this section, except as provided in paragraph (e) of 
this section. No person may violate the product segregation requirements 
of Sec. 80.511.
    (2) No foreign refiner or other person may cause another person to 
commit an action prohibited in paragraph (n)(1) of this section, or that 
otherwise violates the requirements of this section.
    (o) United States importer requirements. Any United States importer 
shall meet the following requirements:

[[Page 997]]

    (1) Each batch of imported diesel fuel and heating oil shall be 
classified by the importer as being DFR-Diesel or as Non-DFR-Diesel, and 
each batch classified as DFR-Diesel shall be further classified as 
Certified DFR-Diesel or as Non-Certified DFR-Diesel, and each batch of 
Certified DFR-Diesel shall be further designated pursuant to the 
designation requirements of Sec. 80.598 and this section.
    (2) Diesel fuel shall be classified as Certified DFR-Diesel or as 
Non-Certified DFR-Diesel according to the designation by the foreign 
refiner if this designation is supported by product transfer documents 
prepared by the foreign refiner as required in paragraph (d) of this 
section, unless the diesel fuel is classified as Non-Certified DFR-
Diesel under paragraph (g) of this section. Additionally, the importer 
shall comply with all requirements of this subpart applicable to 
importers.
    (3) For each diesel fuel batch classified as DFR-Diesel, any United 
States importer shall perform the following procedures.
    (i) In the case of both Certified and Non-Certified DFR-Diesel, have 
an independent third party:
    (A) Determine the volume of diesel fuel in the vessel;
    (B) Use the foreign refiner's DFR-Diesel certification to determine 
the name and EPA-assigned registration number of the foreign refinery 
that produced the DFR-Diesel;
    (C) Determine the name and country of registration of the vessel 
used to transport the DFR-Diesel to the United States; and
    (D) Determine the date and time the vessel arrives at the United 
States port of entry.
    (ii) In the case of Certified DFR-Diesel, have an independent third 
party:
    (A) Collect a representative sample from each vessel compartment 
subsequent to the vessel's arrival at the United States port of entry 
and prior to off loading any diesel fuel from the vessel;
    (B) Obtain the compartment samples; and
    (C) Determine the sulfur content value, and if applicable, the 
marker content, of each compartment sample using an appropriate 
methodology as specified in Sec. Sec. 80.580 through 80.586 by the 
third party analyzing the sample or by the third party observing the 
importer analyze the sample.
    (4) Any importer shall submit reports within 30 days following the 
date any vessel transporting DFR-Diesel arrives at the United States 
port of entry:
    (i) To the Administrator containing the information determined under 
paragraph (o)(3) of this section; and
    (ii) To the foreign refiner containing the information determined 
under paragraph (o)(3)(ii) of this section, and including identification 
of the port and Credit Trading Area at which the product was offloaded.
    (5) Any United States importer shall meet the requirements specified 
in Sec. Sec. 80.510 and 80.520 and all other requirements of this 
subpart, for any imported diesel fuel or heating oil that is not 
classified as Certified DFR-Diesel under paragraph (o)(2) of this 
section.
    (p) Truck imports of Certified DFR-Diesel produced at a foreign 
refinery. (1) Any refiner whose Certified DFR-Diesel is transported into 
the United States by truck may petition EPA to use alternative 
procedures to meet the following requirements:
    (i) Certification under paragraph (d)(5) of this section;
    (ii) Load port and port of entry sampling and testing under 
paragraphs (f) and (g) of this section;
    (iii) Attest under paragraph (h) of this section; and
    (iv) Importer testing under paragraph (o)(3) of this section.
    (2) These alternative procedures must ensure Certified DFR-Diesel 
remains segregated from Non-Certified DFR-Diesel and from Non-DFR-Diesel 
until it is imported into the United States. The petition will be 
evaluated based on whether it adequately addresses the following:
    (i) Provisions for monitoring pipeline shipments, if applicable, 
from the refinery, that ensure segregation of Certified DFR-Diesel from 
that refinery from all other diesel fuel;
    (ii) Contracts with any terminals and/or pipelines that receive and/
or transport Certified DFR-Diesel, that prohibit the commingling of 
Certified DFR-Diesel with any of the following:

[[Page 998]]

    (A) Other Certified DFR-Diesel from other refineries.
    (B) All Non-Certified DFR-Diesel.
    (C) All Non-DFR-Diesel.
    (D) All diesel fuel or heating oil products required to be 
segregated under this subpart;
    (iii) Procedures for obtaining and reviewing truck loading records 
and United States import documents for Certified DFR-Diesel to ensure 
that such diesel fuel is only loaded into trucks making deliveries to 
the United States;
    (iv) Attest procedures to be conducted annually by an independent 
third party that review loading records and import documents based on 
volume reconciliation, or other criteria, to confirm that all Certified 
DFR-Diesel remains segregated throughout the distribution system and is 
only loaded into trucks for import into the United States.
    (3) The petition required by this section must be submitted to EPA 
along with the application for temporary refiner relief individual 
refinery diesel sulfur standard under this subpart.
    (q) Withdrawal or suspension of a foreign refinery's temporary 
refinery flexibility program approval. EPA may withdraw or suspend a 
diesel refiner baseline or standard approval for a foreign refinery 
where--
    (1) A foreign refiner fails to meet any requirement of this section;
    (2) A foreign government fails to allow EPA inspections as provided 
in paragraph (i)(1) of this section;
    (3) A foreign refiner asserts a claim of, or a right to claim, 
sovereign immunity in an action to enforce the requirements in this 
subpart; or
    (4) A foreign refiner fails to pay a civil or criminal penalty that 
is not satisfied using the foreign refiner bond specified in paragraph 
(k) of this section.
    (r) Early use of a foreign refiner motor vehicle diesel fuel 
baseline. (1) A foreign refiner may begin using an individual refinery 
baseline under subpart I of this part before EPA has approved the 
baseline, provided that:
    (i) A baseline petition has been submitted as required in paragraph 
(b) of this section;
    (ii) EPA has made a provisional finding that the baseline petition 
is complete;
    (iii) The foreign refiner has made the commitments required in 
paragraph (i) of this section;
    (iv) The persons who will meet the independent third party and 
independent attest requirements for the foreign refinery have made the 
commitments required in paragraphs (f)(3)(iii) and (h)(7)(iii) of this 
section; and
    (v) The foreign refiner has met the bond requirements of paragraph 
(k) of this section.
    (2) In any case where a foreign refiner uses an individual refinery 
baseline before final approval under paragraph (r)(1) of this section, 
and the foreign refinery baseline values that ultimately are approved by 
EPA are more stringent than the early baseline values used by the 
foreign refiner, the foreign refiner shall recalculate its compliance, 
ab initio, using the baseline values approved by the EPA, and the 
foreign refiner shall be liable for any resulting violation of the motor 
vehicle highway diesel fuel requirements.
    (s) Additional requirements for petitions, reports and certificates. 
Any petition for approval to produce diesel fuel subject to the diesel 
foreign refiner program, any alternative procedures under paragraph (p) 
of this section, any report or other submission required by paragraph 
(c), (f)(2), or (i) of this section, and any certification under 
paragraph (d)(3) of this section shall be--
    (1) Submitted in accordance with procedures specified by the 
Administrator, including use of any forms that may be specified by the 
Administrator.
    (2) Be signed by the president or owner of the foreign refiner 
company, or by that person's immediate designee, and shall contain the 
following declaration:

    I hereby certify: (1) That I have actual authority to sign on behalf 
of and to bind [insert name of foreign refiner] with regard to all 
statements contained herein; (2) that I am aware that the information 
contained herein is being certified, or submitted to the United States 
Environmental Protection Agency, under the requirements of 40 CFR part 
80, subpart I, and that the information is material for determining 
compliance under these regulations; and (3) that I have

[[Page 999]]

read and understand the information being certified or submitted, and 
this information is true, complete and correct to the best of my 
knowledge and belief after I have taken reasonable and appropriate steps 
to verify the accuracy thereof.
    I affirm that I have read and understand the provisions of 40 CFR 
part 80, subpart I, including 40 CFR 80.620 apply to [insert name of 
foreign refiner]. Pursuant to Clean Air Act section 113(c) and 18 U.S.C. 
1001, the penalty for furnishing false, incomplete or misleading 
information in this certification or submission is a fine of up to 
$10,000 U.S., and/or imprisonment for up to five years.

[66 FR 5136, Jan. 18, 2001, as amended at 69 FR 39208, June 29, 2004]



                        Subpart J_Gasoline Toxics

                           General Information

    Source: 66 FR 17263, Mar. 29, 2001, unless otherwise noted.



Sec. Sec. 80.800-80.805  [Reserved]



Sec. 80.810  Who shall register with EPA under the gasoline toxics
program?

    (a) Refiners and importers who are registered by EPA under Sec. 
80.76 are deemed to be registered for purposes of this subpart.
    (b) Refiners and importers subject to the standards in Sec. 80.815 
who are not registered by EPA under Sec. 80.76 shall provide to EPA the 
information required by Sec. 80.76 by October 1, 2001, or not later 
than three months in advance of the first date that such person produces 
or imports gasoline, whichever is later.

                Gasoline Toxics Performance Requirements



Sec. 80.815  What are the gasoline toxics performance requirements
for refiners and importers?

    (a)(1) The gasoline toxics performance requirements of this subpart 
require that the annual average toxics value of a refinery or importer 
be compared to that refinery's or importer's compliance baseline, where 
compliance has been achieved if--
    (i) For conventional gasoline, the annual average toxics value is 
less than or equal to the compliance baseline;
    (ii) For reformulated gasoline and RBOB, combined, the annual 
average toxics value is greater than or equal to the compliance 
baseline.
    (A) Refineries that only produce RBOB and importers that only import 
RBOB shall treat RBOB as reformulated gasoline for the purposes of 
determining compliance with the requirements of this subpart.
    (B) Refineries that produce both RFG and RBOB and importers that 
import both RFG and RBOB must combine any RFG and RBOB qualities and 
volumes for the purposes of determining compliance with the requirements 
of this subpart.
    (2) The requirements under this paragraph (a) shall be met by the 
importer for all imported gasoline, except gasoline imported as 
Certified Toxics-FRGAS under Sec. 80.1030.
    (b) The gasoline toxics requirements of this subpart apply 
separately for each of the following types of gasoline produced at a 
refinery or imported:
    (1) Reformulated gasoline and RBOB, combined;
    (2) Conventional gasoline.
    (c) Compliance baseline. (1) The compliance baseline of a refinery 
or importer is determined in accordance with Sec. 80.915 or Sec. 
80.855, as applicable.
    (2) Refiners who have chosen, under subpart E of this part, to 
comply with the requirements of subpart E of this part on an aggregate 
basis, shall comply with the requirements of this subpart on the same 
aggregate basis.
    (d) Compliance determination. (1)(i) The gasoline toxics performance 
requirements of this subpart apply to gasoline produced at a refinery or 
imported by an importer during each calendar year starting January 1, 
2002. The averaging period is January 1 through December 31 of each 
year.
    (ii)(A) Beginning January 1, 2011, or January 1, 2015 for small 
refiners approved under Sec. 80.1340, the gasoline toxics performance 
requirements of this subpart shall apply only to gasoline that is not 
subject to the benzene standard of Sec. 80.1230, pursuant to the 
provisions of Sec. 80.1235.
    (B) The gasoline toxics performance requirements of this subpart 
shall not apply to gasoline produced by a refinery approved under Sec. 
80.1334, pursuant to Sec. 80.1334(c).

[[Page 1000]]

    (2) The annual average toxics value is calculated in accordance with 
Sec. 80.825.
    (e) Deficit carryforward. (1) A refinery or importer creates a 
toxics deficit, separately for reformulated gasoline and conventional 
gasoline, for a given averaging period, when--
    (i) For conventional gasoline, its annual average toxics value is 
greater than the compliance baseline;
    (ii) For reformulated gasoline and RBOB, combined, the annual 
average toxics value is less than the compliance baseline.
    (2) In the calendar year following the year the toxics deficit is 
created, the refinery or importer shall:
    (i) Achieve compliance with the refinery or importer toxics 
performance requirement specified in paragraph (a) of this section; and
    (ii) Generate additional toxics credits sufficient to offset the 
toxics deficit of the previous year.
    (f) Credit carryforward. (1) A refinery or importer generates toxics 
credits, separately for reformulated gasoline and conventional gasoline, 
for a given averaging period, when--
    (i) For conventional gasoline, its annual average toxics value is 
less than the compliance baseline;
    (ii) For reformulated gasoline and RBOB, combined, the annual 
average toxics value is greater than the compliance baseline.
    (2) Toxics credits may be used to offset a toxics deficit in the 
calendar year following the year the credits are generated, provided the 
following criteria are met:
    (i) Reformulated gasoline toxics credits are only to be used to 
offset a reformulated gasoline toxics deficit; conventional gasoline 
credits are only to be used to offset a conventional gasoline toxics 
deficit.
    (ii) A refiner only offsets a toxics deficit at a refinery with 
toxics credits generated by that refinery.
    (iii) Credits generated on an aggregate basis may only be used to 
offset a deficit calculated on an aggregate basis.
    (iv) Credits used to offset a deficit from the previous year may not 
also be carried forward to the following year. Credits in excess of 
those used to offset a deficit from the previous year may be used to 
offset a deficit in the following year.
    (v) Only toxics credits generated under this subpart may be used to 
offset a toxics deficit created under this subpart.

[66 FR 17263, Mar. 29, 2001, as amended at 72 FR 8544, Feb. 26, 2007]



Sec. 80.820  What gasoline is subject to the toxics performance
requirements of this subpart?

    For the purpose of this subpart, all reformulated gasoline, 
conventional gasoline and RBOB, collectively called ``gasoline'' unless 
otherwise specified, is subject to the requirements under this subpart, 
as applicable, with the following exceptions:
    (a) Gasoline that is used to fuel aircraft, racing vehicles or 
racing boats that are used only in sanctioned racing events, provided 
that:
    (1) Product transfer documents associated with such gasoline, and 
any pump stand from which such gasoline is dispensed, identify the 
gasoline either as gasoline that is restricted for use in aircraft, or 
as gasoline that is restricted for use in racing motor vehicles or 
racing boats that are used only in sanctioned racing events;
    (2) The gasoline is completely segregated from all other gasoline 
throughout production, distribution and sale to the ultimate consumer; 
and
    (3) The gasoline is not made available for use as motor vehicle 
gasoline, or dispensed for use in motor vehicles, except for motor 
vehicles used only in sanctioned racing events.
    (b) Gasoline that is exported for sale outside the U.S.
    (c) Gasoline designated as California gasoline under Sec. 80.845, 
and used in California.
    (d) Gasoline used in American Samoa, Guam and the Commonwealth of 
the Northern Mariana Islands.
    (e) Gasoline exempt per Sec. 80.995.
    (f) Gasoline exempt per Sec. 80.1000.



Sec. 80.825  How is the refinery or importer annual average
toxics value determined?

    (a) The refinery or importer annual average toxics value is 
calculated as follows:

[[Page 1001]]

[GRAPHIC] [TIFF OMITTED] TR29MR01.000

Where:

Ta = The refinery or importer annual average toxics value, as 
applicable.
Vi = The volume of applicable gasoline produced or imported 
in batch i.
Ti = The toxics value of batch i.
n = The number of batches of gasoline produced or imported during the 
averaging period.
i = Individual batch of gasoline produced or imported during the 
averaging period.

    (b) The calculation specified in paragraph (a) of this section shall 
be made separately for each type of gasoline specified at Sec. 
80.815(b).
    (c) The toxics value, Ti, of each batch of gasoline is 
determined using the Phase II Complex Model specified at Sec. 80.45.
    (1) The toxics value, Ti, of each batch of reformulated 
gasoline or RBOB, and the annual average toxics value, Ta, 
for reformulated gasoline and RBOB, combined, under this subpart are in 
percent reduction from the statutory baseline described in Sec. 
80.45(b) and volumes are in gallons.
    (2) (i) The toxics value, Ti, of each batch of 
conventional gasoline, and the annual average toxics value, 
Ta, for conventional gasoline under this subpart are in 
milligrams per mile (mg/mile) and volumes are in gallons.
    (ii) Any refiner for any refinery or importer that has received EPA 
approval of a petition submitted in accordance with the provisions of 
Sec. 80.93(d) shall determine the toxics value, Ti, of each 
batch of conventional gasoline produced or imported for use in Alaska, 
and/or Hawaii, the Commonwealth of Puerto Rico, and the Virgin Islands 
in accordance with Sec. 80.101(g)(1)(ii).
    (d) All refinery or importer annual average toxics value 
calculations shall be conducted to two decimal places.
    (e) A refiner or importer may include oxygenate added downstream 
from the refinery or import facility when calculating the toxics value, 
provided the following requirements are met:
    (1) For oxygenate added to conventional gasoline, the refiner or 
importer shall comply with the requirements of Sec. 80.101(d)(4)(ii).
    (2) For oxygenate added to RBOB, the refiner or importer shall 
comply with the requirements of Sec. 80.69(a).
    (f) Gasoline excluded. Refiners and importers shall exclude from 
compliance calculations all of the following:
    (1) Gasoline that was not produced at the refinery;
    (2) In the case of an importer, gasoline that was imported as 
Certified Toxics-FRGAS under Sec. 80.1030;
    (3) Blending stocks transferred to others;
    (4) Gasoline that has been included in the compliance calculations 
for another refinery or importer; and
    (5) Gasoline exempted from standards under Sec. 80.820.

[66 FR 17263, Mar. 29, 2001, as amended at 72 FR 60581, Oct. 25, 2007]



Sec. 80.830  What requirements apply to oxygenate blenders?

    Oxygenate blenders who blend oxygenate into gasoline downstream of 
the refinery that produced the gasoline or the import facility where the 
gasoline was imported are not subject to the requirements of this 
subpart applicable to refiners for this gasoline.



Sec. 80.835  What requirements apply to butane blenders?

    Butane blenders who blend butane into gasoline downstream of the 
refinery that produced the gasoline or the import facility where the 
gasoline was imported are not subject to the requirements of this 
subpart applicable to refiners for this gasoline.



Sec. 80.840  What requirements apply to transmix processors?

    Any transmix processor who produces gasoline or gasoline blendstock 
from transmix, or recovers gasoline or gasoline blendstock from transmix 
through transmix processing under Sec. 80.84 (c) shall include such 
gasoline or gasoline blendstock in the baseline and compliance 
calculations of this subpart to the same extent such gasoline or 
gasoline blendstock must be included in compliance calculations under 
subpart D of this part for reformulated

[[Page 1002]]

gasoline and RBOB, and under subpart E of this part for conventional 
gasoline, according to the requirements specified in Sec. 80.84(c).

[71 FR 31964, June 2, 2006]



Sec. 80.845  What requirements apply to California gasoline?

    (a) Definition. For purposes of this subpart ``California gasoline'' 
means any gasoline designated by the refiner or importer as for use in 
California.
    (b) California gasoline exemption. California gasoline that complies 
with all the requirements of this section is exempt from all other 
provisions of this subpart.
    (c) Requirements for California gasoline. (1) Each batch of 
California gasoline shall be designated as such by its refiner or 
importer.
    (2) [Reserved]
    (3) Designated California gasoline must ultimately be used in the 
State of California and not used elsewhere.
    (4) In the case of California gasoline produced outside the State of 
California, the transferors and transferees shall meet the product 
transfer document requirements under Sec. 80.81(g).
    (5) Gasoline that is ultimately used in any part of the United 
States outside of the State of California shall comply with the 
standards and requirements of this subpart, regardless of any 
designation as California gasoline.



Sec. 80.850  How is the compliance baseline determined?

    (a) The compliance baseline to which annual average toxics values 
are compared according to Sec. 80.815(a) is calculated according to the 
following equation:
[GRAPHIC] [TIFF OMITTED] TR29MR01.001

Where:

TCBase = Compliance baseline toxics value.
TBase = Baseline toxics value for the refinery or importer, 
calculated according to Sec. 80.915(b)(1).
VBase = Baseline volume for the refinery or importer, 
calculated according to Sec. 80.915(b)(2).
TExist = Existing toxics standard, per paragraph (b) of this 
section.
Vinc = Volume of gasoline produced during the averaging 
period in excess of VBase.

    (b) The value of existing toxics standard, TExist, is 
equal to:
    (1) 21.5 percent, for reformulated gasoline and RBOB, combined;
    (2) The refinery's or importer's anti-dumping compliance baseline 
value for exhaust toxics, in mg/mi, per Sec. 80.101(f), for 
conventional gasoline.
    (c) Any refiner for any refinery or importer with an approved anti-
dumping baseline under Sec. 80.93(d) for gasoline produced or imported 
for use in Alaska, and/or Hawaii, the Commonwealth of Puerto Rico, and 
the Virgin Islands, and for which a conventional gasoline baseline 
toxics value for such gasoline can be determined according to Sec. 
80.915(b)(1), shall determine its compliance baseline applicable to such 
gasoline according to the following equation:
[GRAPHIC] [TIFF OMITTED] TR25OC07.002

Where:

TCBase = Compliance baseline toxics value.
TBase = Baseline toxics value for the refinery or importer, 
calculated according to Sec. 80.915(b)(1) for all gasoline except 
gasoline produced or imported for use in Alaska, Hawaii, the 
Commonwealth of Puerto Rico, and the Virgin Islands.
VBase = Baseline volume for the refinery or importer, 
calculated according to Sec. 80.915(b)(2) for all gasoline except 
gasoline produced or imported for use in Alaska, Hawaii, the 
Commonwealth of Puerto Rico, and the Virgin Islands.
TExist = The refinery's or importer's anti-dumping compliance 
baseline value for exhaust toxics, in mg/mi, per Sec. 80.101(f) for all 
gasoline except gasoline produced or imported for use in Alaska, Hawaii, 
the Commonwealth of Puerto Rico, and the Virgin Islands.
VInc = Volume of gasoline produced or imported, excluding the 
volume of gasoline produced or imported for use in Alaska,

[[Page 1003]]

Hawaii, the Commonwealth of Puerto Rico, and the Virgin Islands during 
the averaging period, which is in excess of VBase.
TSBase = Baseline toxics value for the refinery or importer, 
calculated according to Sec. 80.915(e)(2)(i) for gasoline produce or 
imported for use in Hawaii, the Commonwealth of Puerto Rico, and the 
Virgin Islands.
VSBase = Baseline volume for the refinery or importer, 
calculated according to Sec. 80.915(e)(2)(ii) for gasoline produce or 
imported for use in Hawaii, the Commonwealth of Puerto Rico, and the 
Virgin Islands.
TSExist = The refinery's or importer's anti-dumping 
compliance baseline value for exhaust toxics, in mg/mi, per Sec. 
80.101(f) for gasoline produce or imported for use in Hawaii, the 
Commonwealth of Puerto Rico, and the Virgin Islands.
VSInc = Volume of gasoline produced or imported for use in 
Hawaii, the Commonwealth of Puerto Rico, and the Virgin Islands during 
the averaging period which is in excess of VSBase.
TWBase = Baseline toxics value for the refinery or importer, 
calculated according to Sec. 80.915(e)(1)(i) for gasoline produce or 
imported for use in Alaska.
VWBase = Baseline volume for the refinery or importer, 
calculated according to Sec. 80.915(e)(1)(ii) for gasoline produce or 
imported for use in Alaska.
TWExist = The refinery's or importer's anti-dumping 
compliance baseline value for exhaust toxics, in mg/mi, per Sec. 
80.101(f) for gasoline produce or imported for use in Alaska.
VWInc = Volume of gasoline produced or imported for use in 
Alaska during the averaging period which is in excess of 
VWBase.

    (d) If the refinery or importer produced less gasoline during the 
compliance period than its applicable baseline volume, the value of 
Vinc, VSInc or VWInc, as applicable, 
will be zero.

[66 FR 17263, Mar. 29, 2001, as amended at 72 FR 60581, Oct. 25, 2007]



Sec. 80.855  What is the compliance baseline for refineries or
importers with insufficient data?

    (a) A refinery or importer shall use the methodology specified in 
this section for determining a compliance baseline if it cannot 
determine an applicable toxics value for every batch of gasoline 
produced or imported for 12 or more consecutive months during January 1, 
1998 through December 31, 2000.
    (b)(1) A refinery or importer that cannot determine an applicable 
toxics value on every batch of gasoline produced or imported for 12 or 
more consecutive months during the period January 1, 1998 through 
December 31, 2000 or a refinery or importer that did not produce or 
import reformulated gasoline and/or RBOB (combined) or conventional 
gasoline or both during the period between January 1, 1998 and December 
31, 2000, inclusive, shall have the following as its compliance baseline 
for the purposes of this subpart:
    (i) For conventional gasoline, prior to January 1, 2006, 94.64 mg/
mile; starting January 1, 2006, 97.38 mg/mile.
    (ii) For reformulated gasoline, prior to January 1, 2006, 25.31 
percent reduction from statutory baseline; starting January 1, 2006, 
26.78 percent reduction from statutory baseline.
    (2)(i) A refinery or importer that has an approved anti-dumping 
baseline under Sec. 80.93(d) for gasoline produced or imported for use 
in Alaska, and that cannot determine an applicable toxics value 
according to paragraph (b)(1) of this section, shall have the following 
as its compliance baseline for the purposes of this subpart: 110.72 mg/
mile.
    (ii) A refinery or importer that has an approved anti-dumping 
baseline under Sec. 80.93(d) for gasoline produce or imported for use 
in Hawaii, the Commonwealth of Puerto Rico, and the Virgin Islands and 
that cannot determine an applicable toxics value according to paragraph 
(b)(1) of this section, shall have the following as its compliance 
baseline for the purposes of this subpart: 77.82 mg/mile.
    (iii) The provisions of this paragraph (b)(2) shall apply to any 
refiner, for any refinery, or importer that received approval of a 
petition under Sec. 80.93(d) prior to November 26, 2007 beginning with 
the 2008 annual averaging period.
    (iv) Any new refiner or importer without a toxics baseline that 
produces or imports gasoline for use in Alaska, Hawaii, the Commonwealth 
of Puerto Rico or the Virgin Islands shall be subject to the applicable 
toxics default baseline under paragraph (b)(1) of this section unless 
the refiner or importer petitions for and receives approval of use of a 
seasonal baseline and seasonal Complex Model under Sec. 80.93(d).
    (c)(1) Eligibility to petition. A refiner who has been granted an 
alternative

[[Page 1004]]

anti-dumping averaging period under Sec. 80.101(k) may petition the 
Administrator to have the statutory baseline exhaust toxics emissions, 
Phase II value specified in Sec. 80.91(c)(5)(iv) as its compliance 
baseline for the purposes of this subpart J for one or more of the years 
of the refiner's approved alternative anti-dumping averaging period.
    (2) Application process. Applications must be submitted to the 
Administrator by January 1, 2004 to the following address: U.S. EPA--
Attn: Anti-Dumping Compliance Period (6406J), 1200 Pennsylvania Avenue, 
NW., Washington, DC 20460 (certified mail/return receipt) or U.S. EPA--
Attn: Anti-Dumping Compliance Period (6406J), Transportation & Regional 
Programs Division, 501 3rd Street, NW., Washington, DC 20001 (express 
mail/return receipt).
    (3) Contents of the application petition. Each petition must 
include:
    (i) A copy of the refinery's approval for an alternative averaging 
period under section 80.101(k).
    (ii) A description of the hardships that make it infeasible, on a 
cost and/or technological basis, for the refinery to comply with the 
compliance baseline specified in paragraph (b) of this section.
    (iii) A quarterly timeline, from the date of the application, 
indicating the expected exhaust toxics emissions performance of the 
refinery's conventional gasoline, and the reasons for any expected non-
compliance with the compliance baseline specified in paragraph (b) of 
this section (for example, a particular gasoline blendstock-producing 
unit not yet installed). The timeline shall include the date by which 
the refinery will produce conventional gasoline that complies with the 
baseline specified in paragraph (b) of this section on an annual average 
basis.
    (4) Approval or disapproval of petitions. (i) The Administrator may 
approve a petition if it includes information sufficient to demonstrate 
to the Administrator's satisfaction that cost and/or technological 
constraints make it infeasible for the refinery to comply with the 
baseline specified in paragraph (b) of this section. The Administrator 
will approve or deny a petition in writing within six months of receipt.
    (ii)(A) Each approval will specify the date by which the refinery 
must comply with the baseline specified in paragraph (b) of this 
section. No petition approval shall allow for use of the statutory 
baseline exhaust toxics emissions, Phase II value as a refinery's 
compliance baseline under this subpart J beyond the last day of a 
refinery's alternative anti-dumping averaging period under Sec. 
80.101(k) or Sec. 80.101(l).
    (B) An approval may include any conditions or other requirements to 
which the approval is subject.
    (5) Effective date for petition. (i) Beginning with the averaging 
period immediately following the end of the approved period under 
paragraph (c)(4) of this section, the compliance baseline for the 
purposes of this subpart J shall be as specified in paragraph (b) of 
this section.
    (ii) Notwithstanding the requirement specified in paragraph 
(c)(5)(i) of this section, if at any time the alternative compliance 
period approved under Sec. 80.101(k) or Sec. 80.101(l) ceases to 
apply, the approval granted under this paragraph (c) shall also cease to 
apply.

[68 FR 24309, May 6, 2003, as amended at 70 FR 58335, Oct. 6, 2005; 72 
FR 60582, Oct. 25, 2007]



Sec. Sec. 80.860-80.905  [Reserved]

                         Baseline Determination



Sec. 80.910  How does a refiner or importer apply for a toxics baseline?

    (a)(1) A refiner or importer shall submit an application to EPA 
which includes the information required under paragraph (c) of this 
section no later than June 30, 2001, or 3 months prior to the first 
introduction of gasoline into commerce from the refinery or by the 
importer, whichever is later.
    (2) A refiner or importer shall submit an application to EPA for the 
purposes of this subpart simultaneously with the submission of a 
petition under Sec. 80.93(d).
    (b) The toxics baseline request shall be sent to: U.S. EPA, Attn: 
Toxics Program (6406J), 1200 Pennsylvania Ave., NW, Washington, DC 
20460. For commercial (non-postal) delivery: U.S. EPA, Attn: Toxics 
Program, 501 3rd Street NW, Washington, DC 20001.

[[Page 1005]]

    (c) The toxics baseline application shall include the following 
information:
    (1) A listing of the names and addresses of all refineries owned by 
the company for which the refiner is applying for a toxics baseline, or 
the name and address of the importer applying for a toxics baseline.
    (2) For each refinery and importer--
    (i) The baseline toxics value for each type of gasoline, per Sec. 
80.815(b), calculated in accordance with Sec. 80.915;
    (ii) The baseline toxics volume for each type of gasoline, per Sec. 
80.815(b), calculated in accordance with Sec. 80.915;
    (iii) For those with insufficient data pursuant to Sec. 80.855, a 
statement that the refinery's or importer's baseline toxics value is the 
default compliance baseline specified at Sec. 80.855(b), and that its 
baseline toxics volume is zero.
    (3) A letter signed by the president, chief operating or chief 
executive officer, of the company, or his/her delegate, stating that the 
information contained in the toxics baseline determination is true to 
the best of his/her knowledge.
    (4) Name, address, phone number, facsimile number and E-mail address 
of a company contact person.
    (5) The following information for each batch of gasoline produced or 
imported during the period 1998-2000, separately for each type of 
gasoline listed at Sec. 80.815(b):
    (i) Batch number assigned to the batch under Sec. 80.65(d) or Sec. 
80.101(i);
    (ii) Volume; and
    (iii) Applicable toxics value determined as specified at Sec. 
80.915(c).
    (d) Foreign refiners shall follow the procedures specified in Sec. 
80.1030(b) to establish individual toxics baseline values for a foreign 
refinery.
    (e) By October 31, 2001, or 4 months after the submission date, 
whichever is later, EPA will notify the submitter of approval of its 
toxics baseline.
    (f) If at any time the baseline submitted in accordance with the 
requirements of this section is determined to be incorrect, the 
corrected baseline applies ab initio and the annual average toxics 
requirements are deemed to be those applicable under the corrected 
information.

[66 FR 17263, Mar. 29, 2001, as amended at 72 FR 60582, Oct. 25, 2007]



Sec. 80.915  How are the baseline toxics value and baseline toxics
volume determined?

    (a)(1) A refinery or importer shall use the methodology specified in 
this section for determining a baseline toxics value if it can determine 
an applicable toxics value for every batch of gasoline produced or 
imported for 12 or more consecutive months during January 1, 1998 
through December 31, 2000.
    (2) The determination in paragraph (a)(1) of this section is made 
separately for each type of gasoline listed at Sec. 80.815(b) produced 
or imported between January 1, 1998 and December 31, 2000, inclusive.
    (3) All consecutive and non-consecutive batch toxics measurements 
between January 1, 1998 and December 31, 2000, inclusive, are to be 
included in the baseline determination, unless the refinery or importer 
petitions EPA to exclude such data on the basis of data quality, per 
Sec. 80.91(d)(6), and receives permission from EPA to exclude such 
data.
    (b)(1) A refinery's or importer's baseline toxics value is 
calculated using the following equation:
[GRAPHIC] [TIFF OMITTED] TR29MR01.002

Where:

TBase = Baseline toxics value.
Vi = Volume of gasoline batch i produced or imported between 
January 1, 1998 and December 31, 2000, inclusive.
Ti = Toxics value of gasoline batch i produced or imported 
between January 1, 1998 and December 31, 2000, inclusive.
i = Individual batch of gasoline produced or imported between January 1, 
1998 and December 31, 2000, inclusive.
n = Total number of batches of gasoline produced or imported between 
January 1, 1998 and December 31, 2000, inclusive.
M = Compliance margin.


[[Page 1006]]


    (2) A refinery's or importer's baseline toxics volume is calculated 
using the following equation:
[GRAPHIC] [TIFF OMITTED] TR29MR01.003

Where:

Vbase = Baseline toxics volume.
Vi = Volume of gasoline batch i produced or imported between 
January 1, 1998 and December 31, 2000, inclusive.
i = Individual batch of gasoline produced or imported between January 1, 
1998 and December 31, 2000, inclusive.
n = Total number of batches of gasoline produced or imported between 
January 1, 1998 and December 31, 2000, inclusive.
Y = Number of years between 1998 and 2000, inclusive, during some or all 
of which the refinery produced, or the importer imported, gasoline.

    (c) The calculation specified in paragraph (b) of this section shall 
be made separately for each type of gasoline listed at Sec. 80.815(b).
    (d) The toxics value, Ti, of each batch of gasoline is 
determined using the Phase II Complex Model specified at Sec. 80.45.
    (1) The toxics value, Ti, of each batch of reformulated 
gasoline or RBOB, and the baseline toxics value, TBase, for 
reformulated gasoline and RBOB, combined, under this subpart are in 
percent reduction from the statutory baseline defined in 40 CFR 80.45(b) 
and volumes are in gallons.
    (2) The toxics value, Ti, of each batch of conventional 
gasoline, and the baseline toxics value, TBase, for 
conventional gasoline under this subpart are in milligrams per mile (mg/
mile) and volumes are in gallons.
    (e)(1)(i) A refiner or importer which is approved for a petition 
submitted under Sec. 80.910(a)(2) for gasoline produced or imported for 
use in Alaska shall calculate the applicable toxics baseline value using 
the following equation:
[GRAPHIC] [TIFF OMITTED] TR25OC07.003

Where:

TWBase = Baseline toxics value for gasoline produced or 
imported for use in Alaska.
Vi = Volume of gasoline batch i produced or imported for use 
in Alaska between January 1, 1998 and December 31, 2000, inclusive.
Ti = Toxics value of gasoline batch i produced or imported 
for use in Alaska between January 1, 1998 and December 31, 2000, 
inclusive.
i = Individual batch of gasoline produced or imported for use in Alaska 
between January 1, 1998 and December 31, 2000, inclusive.
n = Total number of batches of gasoline produced or imported for use in 
Alaska between January 1, 1998 and December 31, 2000, inclusive.
M = Compliance margin.

    (ii) The baseline volume associated with the baseline value 
calculated in paragraph (e)(1)(i) of this section shall be calculated 
using the methodology in paragraph (b)(2) of this section for the 
gasoline described in paragraph (e)(1)(i) of this section.
    (2)(i) A refiner or importer which is approved for a petition 
submitted under Sec. 80.910(a)(2) for gasoline produced or imported for 
use in Hawaii, the Commonwealth of Puerto Rico, and the Virgin Islands 
shall calculate the applicable toxics baseline value using the following 
equation:
[GRAPHIC] [TIFF OMITTED] TR25OC07.004

Where:

TSBase = Baseline toxics value for gasoline produced or 
imported for use in Hawaii, the Commonwealth of Puerto Rico, and the 
Virgin Islands.
Vi = Volume of gasoline batch i produced or imported for use 
in Hawaii, the Commonwealth of Puerto Rico, and the Virgin Islands 
between January 1, 1998 and December 31, 2000, inclusive.
Ti= Toxics value of gasoline batch i produced or imported for 
use in Hawaii, the Commonwealth of Puerto Rico, and the Virgin Islands 
between January 1, 1998 and December 31, 2000, inclusive.
i = Individual batch of gasoline produced or imported for use 
in Hawaii, the Commonwealth of Puerto Rico, and the Virgin Islands 
between January 1, 1998 and December 31, 2000, inclusive.
n = Total number of batches of gasoline produced or imported for use in 
Hawaii, the Commonwealth of Puerto Rico, and the

[[Page 1007]]

Virgin Islands between January 1, 1998 and December 31, 2000, inclusive.
M = Compliance margin.

    (ii) The baseline volume associated with the baseline value 
calculated in paragraph (e)(2)(i) of this section shall be calculated 
using the methodology in paragraph (b)(2) of this section for the 
gasoline described in paragraph (e)(2)(i) of this section.
    (f) All refinery or importer baseline toxics value calculations 
shall be conducted to two decimal places.
    (g) Any refinery for which oxygenate blended downstream was included 
in compliance calculations for 1998-2000, pursuant to Sec. 80.65 or 
Sec. 80.101(d)(4), shall include this oxygenate in the baseline 
calculations for toxics value under paragraph (a) of this section.
    (h) Baseline adjustment. (1) A toxics baseline determined 
differently than described in paragraphs (a) through (e) of this section 
may be allowed upon petition by the refiner or importer and approval by 
the Administrator or designee. The petition must be included with the 
baseline submittal under Sec. 80.910.
    (2) A toxics baseline adjustment petition shall, at minimum, be 
accompanied by:
    (i) Unadjusted and adjusted baseline fuel parameters, applicable 
toxics values, and volumes; and
    (ii) A narrative describing how the circumstances during 1998-2000 
materially affected the baseline toxics value calculated under paragraph 
(a) of this section. The narrative shall also describe and show the 
calculations, and the reasoning supporting the calculations, used to 
determine the adjusted values.
    (i) The compliance margin, M, that will be added to the toxics 
baseline calculated according to paragraph (a) of this section shall be 
equal to:
    (1) -0.7% for reformulated gasoline or RBOB;
    (2) 2.5 mg/mile for conventional gasoline.

[66 FR 17263, Mar. 29, 2001, as amended at 72 FR 60582, Oct. 25, 2007]



Sec. Sec. 80.920-80.980  [Reserved]

                Recordkeeping and Reporting Requirements



Sec. 80.985  What records shall be kept?

    (a) The recordkeeping requirements specified under Sec. 80.74 
applicable to refiners and importers of reformulated gasoline, RBOB and/
or conventional gasoline apply under this subpart, however, duplicate 
records are not required.
    (b) Additional records that refiners and importers shall keep. 
Beginning January 1, 2002, any refiner for each of its refineries, and 
any importer for the gasoline it imports, shall keep records that 
include the following information:
    (1) The calculations used to determine the applicable compliance 
baseline under Sec. 80.915.
    (2) The calculations used to determine compliance with the 
applicable toxics requirements per Sec. 80.815.
    (3) A copy of all reports submitted to EPA under Sec. 80.990, 
however, duplicate records are not required.
    (c) Additional records importers shall keep. Any importer shall keep 
records that identify and verify the source of each batch of Certified 
Toxics-FRGAS and Non-Certified Toxics-FRGAS imported and demonstrate 
compliance with the requirements for importers under Sec. 80.1030(o).
    (d) Length of time records shall be kept. The records required in 
this section shall be kept for five years from the date they were 
created.
    (e) Make records available to EPA. On request by EPA the records 
required in paragraphs (a), (b) and (c) of this section shall be 
provided to the Administrator's authorized representative. For records 
that are electronically generated or maintained the equipment and 
software necessary to read the records shall be made available, or upon 
approval by EPA, electronic records shall be converted to paper 
documents which shall be provided to the Administrator's authorized 
representative.



Sec. 80.990  What are the toxics reporting requirements?

    Beginning with the 2002 averaging period, and continuing for each 
averaging

[[Page 1008]]

period thereafter, any refiner or importer shall submit to EPA the 
information required in this section, and such other information as EPA 
may require.
    (a) Refiner and importer annual reports. Any refiner, for each of 
its refineries and/or aggregate(s) of refineries, and any importer for 
the gasoline it imports, shall:
    (1) Include in its reformulated gasoline toxics emissions 
performance averaging report per Sec. 80.75(e) the compliance baseline 
and incremental volume, Vinc, for its reformulated gasoline 
and RBOB, combined, per Sec. 80.850.
    (2) Include in its conventional gasoline report per Sec. 80.105 the 
compliance baseline and incremental volume, Vinc, for its 
conventional gasoline per Sec. 80.850.
    (3) Exclude Certified Toxics-FRGAS under Sec. 80.1030, if an 
importer.
    (b) Additional reporting requirements for importers. Any importer 
shall report the following information for Toxics-FRGAS imported during 
the averaging period:
    (1) The EPA refiner and refinery registration numbers of each 
foreign refiner and refinery where the Certified Toxics-FRGAS was 
produced; and
    (2) The total gallons of Certified Toxics-FRGAS and Non-Certified 
Toxics-FRGAS imported from each foreign refiner and refinery.

                               Exemptions



Sec. 80.995  What if a refiner or importer is unable to produce 
gasoline conforming to the requirements of this subpart?

    In appropriate extreme and unusual circumstances (e.g., natural 
disaster or Act of God) which are clearly outside the control of the 
refiner or importer and which could not have been avoided by the 
exercise of prudence, diligence, and due care, EPA may permit a refiner 
or importer, for a brief period, to not meet the requirements of this 
subpart, separately for reformulated gasoline (and RBOB, combined) and 
conventional gasoline, provided the refiner or importer meets all the 
criteria, requirements and conditions contained in Sec. 80.73 (a) 
through (e).



Sec. 80.1000  What are the requirements for obtaining an exemption
for gasoline used for research, development or testing purposes?

    Gasoline used for research, development or testing purposes is 
exempt from the requirements of this subpart if it is exempted for these 
purposes under the reformulated and conventional gasoline programs, as 
applicable.

                          Violation Provisions



Sec. 80.1005  What acts are prohibited under the gasoline 
toxics program?

    No person shall:
    (a) Averaging violation. Produce or import gasoline subject to this 
subpart that does not comply with the applicable toxics requirement 
under Sec. 80.815.
    (b) Causing an averaging use violation. Cause another person to 
commit an act in violation of paragraph (a) of this section.



Sec. 80.1010  [Reserved]



Sec. 80.1015  Who is liable for violations under the gasoline 
toxics program?

    (a) Persons liable for violations of prohibited acts--(1) Averaging 
violation. Any person who violates Sec. 80.1005(a) is liable for the 
violation.
    (2) Causing an averaging violation. Any person who causes another 
party to violate Sec. 80.1005(a), is liable for a violation of Sec. 
80.1005(b).
    (3) Parent corporation liability. Any parent corporation is liable 
for any violations of this subpart that are committed by any of its 
wholly-owned subsidiaries.
    (b) Persons liable for failure to meet other provisions of this 
subpart. (1) Any person who fails to meet a provision of this subpart 
not addressed in paragraph (a) of this section is liable for a violation 
of that provision.
    (2) Any person who causes another party to fail to meet a 
requirement of this subpart not addressed in paragraph (a) of this 
section, is liable for causing a violation of that provision.

[[Page 1009]]



Sec. 80.1020  [Reserved]



Sec. 80.1025  What penalties apply under this subpart?

    (a) Any person liable for a violation under Sec. 80.1015 is subject 
to civil penalties as specified in sections 205 and 211(d) of the Clean 
Air Act for every day of each such violation and the amount of economic 
benefit or savings resulting from each violation.
    (b) Any person liable under Sec. 80.1015(a) for a violation of the 
applicable toxics requirements or causing another party to violate the 
requirements during any averaging period, is subject to a separate day 
of violation for each and every day in the averaging period.
    (c) Any person liable under Sec. 80.1015(b) for failure to meet, or 
causing a failure to meet, a provision of this subpart is liable for a 
separate day of violation for each and every day such provision remains 
unfulfilled.

    Provisions for Foreign Refiners With Individual Toxics Baselines



Sec. 80.1030  What are the requirements for gasoline produced at
foreign refineries having individual refiner toxics baselines?

    (a) Definitions. (1) A foreign refinery is a refinery that is 
located outside the United States, the Commonwealth of Puerto Rico, the 
Virgin Islands, Guam, American Samoa, and the Commonwealth of the 
Northern Mariana Islands (collectively referred to in this section as 
``the United States'').
    (2) A foreign refiner is a person who meets the definition of 
refiner under Sec. 80.2(i) for a foreign refinery.
    (3) Toxics-FRGAS means gasoline produced at a foreign refinery that 
has been assigned an individual refinery toxics baseline under Sec. 
80.915 and that is imported into the U.S.
    (4) Non-Toxics-FRGAS means gasoline that is produced at a foreign 
refinery that has not been assigned an individual refinery toxics 
baseline, gasoline produced at a foreign refinery with an individual 
refinery toxics baseline that is not imported into the United States, 
and gasoline produced at a foreign refinery with an individual toxics 
baseline during a year when the foreign refiner has opted to not 
participate in the Toxics-FRGAS program under paragraph (c)(3) of this 
section.
    (5) Certified Toxics-FRGAS means Toxics-FRGAS the foreign refiner 
intends to include in the foreign refinery's toxics compliance 
calculations under Sec. 80.825, and does include in these compliance 
calculations when reported to EPA.
    (6) Non-Certified Toxics-FRGAS means Toxics-FRGAS that is not 
Certified Toxics-FRGAS.
    (b) Baseline establishment. Any foreign refiner may submit a 
petition to the Administrator for an individual refinery toxics baseline 
pursuant to Sec. 80.915 for all gasoline that was produced at the 
foreign refinery and imported into the United States between January 1, 
1998 and December 31, 2000.
    (1) The refiner shall follow the procedures specified in Sec. Sec. 
80.91 through 80.93 to establish an anti-dumping baseline, if it does 
not already have such a baseline.
    (2) In making determinations for foreign refinery baselines, EPA 
will consider all information supplied by a foreign refiner, and in 
addition may rely on any and all appropriate assumptions necessary to 
make such determinations.
    (3)(i) Where a foreign refiner submits a petition that is incomplete 
or inadequate to establish an accurate toxics baseline, and the refiner 
fails to cure this defect after a request for more information, EPA will 
not assign an individual refinery toxics baseline.
    (ii) If a foreign refiner does not already have an anti-dumping 
individual baseline per Sec. 80.94, and if pursuant to Sec. 
80.94(b)(5) EPA does not assign an individual anti-dumping baseline, EPA 
will also not assign an individual refinery toxics baseline.
    (c) General requirements for foreign refiners with individual 
refinery toxics baselines. A foreign refiner of a refinery that has been 
assigned an individual toxics baseline according to Sec. 80.915 shall 
designate all gasoline produced at the foreign refinery that is exported 
to the United States as either Certified Toxics-FRGAS or as Non-
Certified Toxics-FRGAS, except as provided in paragraph (c)(3) of this 
section.
    (1) In the case of Certified Toxics-FRGAS, the foreign refiner shall 
meet

[[Page 1010]]

all provisions that apply to refiners under this subpart J.
    (2) In the case of Non-Certified Toxics-FRGAS, the foreign refiner 
shall meet all the following provisions, except the foreign refiner 
shall use the name Non-Certified Toxics-FRGAS instead of the names 
``reformulated gasoline'' or ``RBOB'' wherever they appear in the 
following provisions:
    (i) The designation requirements in this section.
    (ii) The recordkeeping requirements under Sec. 80.985.
    (iii) The reporting requirements in Sec. 80.990 and this section.
    (iv) The product transfer document requirements in this section.
    (v) The prohibitions in this section and Sec. 80.1005.
    (vi) The independent audit requirements under Sec. 80.1035, 
paragraph (h) of this section, Sec. Sec. 80.125 through 80.127, Sec. 
80.128(a), (b), (c), (g) through (i), and Sec. 80.130.
    (3)(i) Any foreign refiner that has been assigned an individual 
toxics baseline for a foreign refinery under Sec. 80.915 may elect to 
classify no gasoline imported into the United States as Toxics-FRGAS, 
provided the foreign refiner notifies EPA of the election no later than 
November 1 of the prior calendar year.
    (ii) An election under paragraph (c)(3)(i) of this section shall:
    (A) Apply to an entire calendar year averaging period, and apply to 
all gasoline produced during the calendar year at the foreign refinery 
that is used in the United States; and
    (B) Remain in effect for each succeeding calendar year averaging 
period, unless and until the foreign refiner notifies EPA of a 
termination of the election. The change in election shall take effect at 
the beginning of the next calendar year.
    (4) In the case of information required under this section which 
would duplicate information submitted in accordance with Sec. 80.94, 
the refiner may indicate that such information is also submitted in 
accordance with the requirements of this section. Duplicate submissions 
are not required.
    (d) Designation, product transfer documents, and foreign refiner 
certification. (1) Any foreign refiner of a foreign refinery that has 
been assigned an individual toxics baseline shall designate each batch 
of Toxics-FRGAS as such at the time the gasoline is produced, unless the 
refiner has elected to classify no gasoline exported to the United 
States as Toxics-FRGAS under paragraph (c)(3)(i) of this section.
    (2) On each occasion when any person transfers custody or title to 
any Toxics-FRGAS prior to its being imported into the United States, it 
shall include the following information as part of the product transfer 
document information in this section:
    (i) Identification of the gasoline as Certified Toxics-FRGAS or as 
Non-Certified Toxics-FRGAS; and
    (ii) The name and EPA refinery registration number of the refinery 
where the Toxics-FRGAS was produced.
    (3) On each occasion when Toxics-FRGAS is loaded onto a vessel or 
other transportation mode for transport to the United States, the 
foreign refiner shall prepare a written verification for each batch of 
the Toxics-FRGAS that meets the following requirements:
    (i) The verification shall include the report of the independent 
third party under paragraph (f) of this section, and the following 
additional information:
    (A) The name and EPA registration number of the refinery that 
produced the Toxics-FRGAS;
    (B) The identification of the gasoline as Certified Toxics-FRGAS or 
Non-Certified Toxics-FRGAS;
    (C) The volume of Toxics-FRGAS being transported, in gallons;
    (D) In the case of Certified Toxics-FRGAS:
    (1) The toxics value as determined under paragraph (f) of this 
section; and
    (2) A declaration that the Toxics-FRGAS is being included in the 
compliance calculations under Sec. 80.825 for the refinery that 
produced the Toxics-FRGAS.
    (ii) The verification shall be made part of the product transfer 
documents for the Toxics-FRGAS.
    (e) Transfers of Toxics-FRGAS to non-United States markets. The 
foreign refiner is responsible to ensure that all gasoline classified as 
Toxics-FRGAS is imported into the United States. A foreign refiner may 
remove the Toxics-FRGAS classification, and the gasoline

[[Page 1011]]

need not be imported into the United States, but only if:
    (1)(i) The foreign refiner excludes:
    (A) The volume of gasoline from the refinery's compliance 
calculations under Sec. 80.825; and
    (B) In the case of Certified Toxics-FRGAS, the volume and toxics 
value of the gasoline from the compliance calculations under Sec. 
80.825.
    (ii) The exclusions under paragraph (e)(1)(i) of this section shall 
be on the basis of the toxics value and volumes determined under 
paragraph (f) of this section; and
    (2) The foreign refiner obtains sufficient evidence in the form of 
documentation that the gasoline was not imported into the United States.
    (f) Load port independent sampling, testing and refinery 
identification. (1) On each occasion Toxics-FRGAS is loaded onto a 
vessel for transport to the United States a foreign refiner shall have 
an independent third party:
    (i) Inspect the vessel prior to loading and determine the volume of 
any tank bottoms;
    (ii) Determine the volume of Toxics-FRGAS loaded onto the vessel 
(exclusive of any tank bottoms present before vessel loading);
    (iii) Obtain the EPA-assigned registration number of the foreign 
refinery;
    (iv) Determine the name and country of registration of the vessel 
used to transport the Toxics-FRGAS to the United States; and
    (v) Determine the date and time the vessel departs the port serving 
the foreign refinery.
    (2) On each occasion Certified Toxics-FRGAS is loaded onto a vessel 
for transport to the United States a foreign refiner shall have an 
independent third party:
    (i) Collect a representative sample of the Certified Toxics-FRGAS 
from each vessel compartment subsequent to loading on the vessel and 
prior to departure of the vessel from the port serving the foreign 
refinery;
    (ii) Prepare a volume-weighted vessel composite sample from the 
compartment samples, and determine the value for toxics using the 
methodology specified in Sec. 80.730 by:
    (A) The third party analyzing the sample; or
    (B) The third party observing the foreign refiner analyze the 
sample;
    (iii) Review original documents that reflect movement and storage of 
the Certified Toxics-FRGAS from the refinery to the load port, and from 
this review determine:
    (A) The refinery at which the Toxics-FRGAS was produced; and
    (B) That the Toxics-FRGAS remained segregated from:
    (1) Non-Toxics-FRGAS and Non-Certified Toxics-FRGAS; and
    (2) Other Certified Toxics-FRGAS produced at a different refinery.
    (3) The independent third party shall submit a report:
    (i) To the foreign refiner containing the information required under 
paragraphs (f)(1) and (2) of this section, to accompany the product 
transfer documents for the vessel; and
    (ii) To the Administrator containing the information required under 
paragraphs (f)(1) and (2) of this section, within thirty days following 
the date of the independent third party's inspection. This report shall 
include a description of the method used to determine the identity of 
the refinery at which the gasoline was produced, assurance that the 
gasoline remained segregated as specified in paragraph (n)(1) of this 
section, and a description of the gasoline's movement and storage 
between production at the source refinery and vessel loading.
    (4) The independent third party shall:
    (i) Be approved in advance by EPA, based on a demonstration of 
ability to perform the procedures required in this paragraph (f);
    (ii) Be independent under the criteria specified in Sec. 
80.65(e)(2)(iii); and
    (iii) Sign a commitment that contains the provisions specified in 
paragraph (i) of this section with regard to activities, facilities and 
documents relevant to compliance with the requirements of this paragraph 
(f).
    (g) Comparison of load port and port of entry testing. (1)(i) Except 
as described in paragraph (g)(1)(ii) of this section, any foreign 
refiner and any United States importer of Certified Toxics-FRGAS shall 
compare the results from the load port testing under paragraph

[[Page 1012]]

(f) of this section, with the port of entry testing as reported under 
paragraph (o) of this section, for the volume of gasoline and the toxics 
value.
    (ii) Where a vessel transporting Certified Toxics-FRGAS off loads 
this gasoline at more than one United States port of entry, and the 
conditions of paragraph (g)(2)(i) of this section are met at the first 
United States port of entry, the requirements of paragraph (g)(2) of 
this section do not apply at subsequent ports of entry if the United 
States importer obtains a certification from the vessel owner, that 
meets the requirements of paragraph (s) of this section, that the vessel 
has not loaded any gasoline or blendstock between the first United 
States port of entry and the subsequent port of entry.
    (2)(i) The requirements of this paragraph (g)(2) apply if:
    (A) The temperature-corrected volumes determined at the port of 
entry and at the load port differ by more than one percent; or
    (B) The toxics value determined at the port of entry is higher than 
the toxics value determined at the load port, and the amount of this 
difference is greater than the reproducibility amount specified for the 
port of entry test result by the American Society of Testing and 
Materials (ASTM).
    (ii) The United States importer and the foreign refiner shall treat 
the gasoline as Non-Certified Toxics-FRGAS, and the foreign refiner 
shall exclude the gasoline volume and properties from its gasoline 
toxics compliance calculations under Sec. 80.825.
    (h) Attest requirements. The following additional procedures shall 
be carried out by any foreign refiner of Toxics-FRGAS as part of the 
applicable attest engagement for each foreign refinery under Sec. 
80.1035:
    (1) The inventory reconciliation analysis under Sec. 80.128(b) and 
the tender analysis under Sec. 80.128(c) shall include Non-Toxics-FRGAS 
in addition to the gasoline types listed in Sec. 80.128(b) and (c).
    (2) Obtain separate listings of all tenders of Certified Toxics-
FRGAS, and of Non-Certified Toxics-FRGAS. Agree the total volume of 
tenders from the listings to the gasoline inventory reconciliation 
analysis in Sec. 80.128(b), and to the volumes determined by the third 
party under paragraph (f)(1) of this section.
    (3) For each tender under paragraph (h)(2) of this section where the 
gasoline is loaded onto a marine vessel, report as a finding the name 
and country of registration of each vessel, and the volumes of Toxics-
FRGAS loaded onto each vessel.
    (4) Select a sample from the list of vessels identified in paragraph 
(h)(3) of this section used to transport Certified Toxics-FRGAS, in 
accordance with the guidelines in Sec. 80.127, and for each vessel 
selected perform the following:
    (i) Obtain the report of the independent third party, under 
paragraph (f) of this section, and of the United States importer under 
paragraph (o) of this section.
    (A) Agree the information in these reports with regard to vessel 
identification, gasoline volumes and test results.
    (B) Identify, and report as a finding, each occasion the load port 
and port of entry parameter and volume results differ by more than the 
amounts allowed in paragraph (g) of this section, and determine whether 
the foreign refiner adjusted its refinery calculations as required in 
paragraph (g) of this section.
    (ii) Obtain the documents used by the independent third party to 
determine transportation and storage of the Certified Toxics-FRGAS from 
the refinery to the load port, under paragraph (f) of this section. 
Obtain tank activity records for any storage tank where the Certified 
Toxics-FRGAS is stored, and pipeline activity records for any pipeline 
used to transport the Certified Toxics-FRGAS, prior to being loaded onto 
the vessel. Use these records to determine whether the Certified Toxics-
FRGAS was produced at the refinery that is the subject of the attest 
engagement, and whether the Certified Toxics-FRGAS was mixed with any 
Non-Certified Toxics-FRGAS, Non-Toxics-FRGAS, or any Certified Toxics-
FRGAS produced at a different refinery.
    (5) Select a sample from the list of vessels identified in paragraph 
(h)(3) of this section used to transport Certified and Non-Certified 
Toxics-FRGAS, in accordance with the guidelines in

[[Page 1013]]

Sec. 80.127, and for each vessel selected perform the following:
    (i) Obtain a commercial document of general circulation that lists 
vessel arrivals and departures, and that includes the port and date of 
departure of the vessel, and the port of entry and date of arrival of 
the vessel.
    (ii) Agree the vessel's departure and arrival locations and dates 
from the independent third party and United States importer reports to 
the information contained in the commercial document.
    (6) Obtain separate listings of all tenders of Non-Toxics-FRGAS, and 
perform the following:
    (i) Agree the total volume of tenders from the listings to the 
gasoline inventory reconciliation analysis in Sec. 80.128(b).
    (ii) Obtain a separate listing of the tenders under this paragraph 
(h)(6) where the gasoline is loaded onto a marine vessel. Select a 
sample from this listing in accordance with the guidelines in Sec. 
80.127, and obtain a commercial document of general circulation that 
lists vessel arrivals and departures, and that includes the port and 
date of departure and the ports and dates where the gasoline was off 
loaded for the selected vessels. Determine and report as a finding the 
country where the gasoline was off loaded for each vessel selected.
    (7) In order to complete the requirements of this paragraph (h) an 
auditor shall:
    (i) Be independent of the foreign refiner;
    (ii) Be licensed as a Certified Public Accountant in the United 
States and a citizen of the United States, or be approved in advance by 
EPA based on a demonstration of ability to perform the procedures 
required in Sec. Sec. 80.125 through 80.130 and this paragraph (h); and
    (iii) Sign a commitment that contains the provisions specified in 
paragraph (i) of this section with regard to activities and documents 
relevant to compliance with the requirements of Sec. Sec. 80.125 
through 80.130, Sec. 80.1035 and this paragraph (h).
    (i) Foreign refiner commitments. Any foreign refiner shall commit to 
and comply with the provisions contained in this paragraph (i) as a 
condition to being assigned an individual refinery toxics baseline.
    (1) Any United States Environmental Protection Agency inspector or 
auditor will be given full, complete and immediate access to conduct 
inspections and audits of the foreign refinery.
    (i) Inspections and audits may be either announced in advance by 
EPA, or unannounced.
    (ii) Access will be provided to any location where:
    (A) Gasoline is produced;
    (B) Documents related to refinery operations are kept;
    (C) Gasoline or blendstock samples are tested or stored; and
    (D) Toxics-FRGAS is stored or transported between the foreign 
refinery and the United States, including storage tanks, vessels and 
pipelines.
    (iii) Inspections and audits may be by EPA employees or contractors 
to EPA.
    (iv) Any documents requested that are related to matters covered by 
inspections and audits will be provided to an EPA inspector or auditor 
on request.
    (v) Inspections and audits by EPA may include review and copying of 
any documents related to:
    (A) Refinery baseline establishment, including the volume and toxics 
value, and transfers of title or custody, of any gasoline or 
blendstocks, whether Toxics-FRGAS or Non-toxics-FRGAS, produced at the 
foreign refinery during the period January 1, 1998 through the date of 
the refinery baseline petition or through the date of the inspection or 
audit if a baseline petition has not been approved, and any work papers 
related to refinery baseline establishment;
    (B) The volume and toxics value of Toxics-FRGAS;
    (C) The proper classification of gasoline as being Toxics-FRGAS or 
as not being Toxics-FRGAS, or as Certified Toxics-FRGAS or as Non-
Certified Toxics-FRGAS;
    (D) Transfers of title or custody to Toxics-FRGAS;
    (E) Sampling and testing of Toxics-FRGAS;
    (F) Work performed and reports prepared by independent third parties 
and

[[Page 1014]]

by independent auditors under the requirements of this section and Sec. 
80.1035 including work papers; and
    (G) Reports prepared for submission to EPA, and any work papers 
related to such reports.
    (vi) Inspections and audits by EPA may include taking samples of 
gasoline or blendstock, and interviewing employees.
    (vii) Any employee of the foreign refiner will be made available for 
interview by the EPA inspector or auditor, on request, within a 
reasonable time period.
    (viii) English language translations of any documents will be 
provided to an EPA inspector or auditor, on request, within 10 working 
days.
    (ix) English language interpreters will be provided to accompany EPA 
inspectors and auditors, on request.
    (2) An agent for service of process located in the District of 
Columbia will be named, and service on this agent constitutes service on 
and personal and subject matter jurisdiction in the United States over 
the foreign refiner or any employee of the foreign refiner for any 
action by EPA or otherwise by the United States related to the 
requirements of this subpart J.
    (3) A foreign refiner shall be subject to civil liability for 
violations of this section, sections 114, 202(l), 211, and 301(a) of the 
Clean Air Act, as amended (42 U.S.C. 7414, 7521(l), 7545 and 7601(a)), 
and all other applicable laws or regulations and shall be subject to the 
provisions thereof. The Administrator may assess a penalty against a 
foreign refiner for any violation of this section by a foreign refiner, 
in the manner set forth in sections 205(c) of the CAA, 42 U.S.C. 7524(c) 
or commence a civil action against a foreign refiner to assess and 
recover a civil penalty in the manner set forth in section 205(b) of the 
CAA, 42 U.S.C. 7524(b). A FR shall be subject to criminal liability for 
violations of this section, section 113(c)(2) of the CAA, 42 U.S.C. 
7413(c)(2), 18 U.S.C. 1001 and all other applicable provisions and shall 
be subject to the provisions thereof.
    (4) United States substantive and procedural laws shall apply to any 
civil or criminal enforcement action against the foreign refiner or any 
employee of the foreign refiner related to the provisions of this 
section.
    (5) Submitting a petition for an individual refinery toxics 
baseline, producing and exporting gasoline under an individual refinery 
toxics baseline, and all other actions to comply with the requirements 
of this subpart J relating to the establishment and use of an individual 
refinery toxics baseline constitute actions or activities that satisfy 
the provisions of 28 U.S.C. 1605(a)(2), but solely with respect to 
actions instituted against the foreign refiner, its agents and employees 
in any court or other tribunal in the United States for conduct that 
violates the requirements applicable to the foreign refiner under this 
subpart J, including conduct that violates Title 18 U.S.C. section 1001 
and Clean Air Act section 113(c)(2).
    (6) The foreign refiner, or its agents or employees, will not seek 
to detain or to impose civil or criminal remedies against EPA inspectors 
or auditors, whether EPA employees or EPA contractors, for actions 
performed within the scope of EPA employment related to the provisions 
of this section.
    (7) The commitment required by this paragraph (i) shall be signed by 
the owner or president of the foreign refiner business.
    (8) In any case where Toxics-FRGAS produced at a foreign refinery is 
stored or transported by another company between the refinery and the 
vessel that transports the Toxics-FRGAS to the United States, the 
foreign refiner shall obtain from each such other company a commitment 
that meets the requirements specified in paragraphs (i)(1) through (7) 
of this section, and these commitments shall be included in the foreign 
refiner's baseline petition.
    (j) Sovereign immunity. By submitting a petition for an individual 
foreign refinery baseline under this section, or by producing and 
exporting gasoline to the United States under an individual refinery 
toxics baseline under this section, the foreign refiner, its agents and 
employees, without exception, become subject to the full operation of 
the administrative and judicial enforcement powers and provisions of the 
United States without limitation based on sovereign immunity, with 
respect to

[[Page 1015]]

actions instituted against the foreign refiner, its agents and employees 
in any court or other tribunal in the United States for conduct that 
violates the requirements applicable to the foreign refiner under this 
subpart J, including conduct that violates Title 18 U.S.C. section 1001 
and Clean Air Act section 113(c)(2).
    (k) Bond posting. Any foreign refiner shall meet the requirements of 
this paragraph (k) as a condition to being assigned an individual 
refinery toxics baseline.
    (1) The foreign refiner shall annually post a bond of the amount 
calculated using the following equation:

Bond = G x $ 0.01 - BondCG

Where:

Bond = amount of the bond in U. S. dollars.
G = the largest volume of gasoline produced at the foreign refinery and 
exported to the United States, in gallons, during a single calendar year 
among the five preceding calendar years.
BondCG = amount of bond currently posted by the refinery 
pursuant to Sec. 80.94.

    (2) Bonds shall be posted by:
    (i) Paying the amount of the bond to the Treasurer of the United 
States;
    (ii) Obtaining a bond in the proper amount from a third party surety 
agent that is payable to satisfy United States administrative or 
judicial judgments against the foreign refiner, provided EPA agrees in 
advance as to the third party and the nature of the surety agreement; or
    (iii) An alternative commitment that results in assets of an 
appropriate liquidity and value being readily available to the United 
States, provided EPA agrees in advance as to the alternative commitment.
    (3) If the bond amount for a foreign refinery increases, the foreign 
refiner shall increase the bond to cover the shortfall within 90 days of 
the date the bond amount changes. If the bond amount decreases, the 
foreign refiner may reduce the amount of the bond beginning 90 days 
after the date the bond amount changes.
    (4) Bonds posted under this paragraph (k) shall:
    (i) Be used to satisfy any judicial or administrative judgment, 
order, assessment or payment under a judicial or administrative 
settlement agreement that results from an administrative or judicial 
enforcement action for conduct in violation of this subpart J, including 
where such conduct violates Title 18 U.S.C. section 1001 and Clean Air 
Act section 113(c)(2);
    (ii) Be provided by a corporate surety that is listed in the United 
States Department of Treasury Circular 570 ``Companies Holding 
Certificates of Authority as Acceptable Sureties on Federal Bonds'; and
    (iii) Include a commitment that the bond will remain in effect for 
at least five (5) years following the end of latest averaging period 
that the foreign refiner produces gasoline pursuant to the requirements 
of this subpart J.
    (5) On any occasion a foreign refiner bond is used to satisfy any 
judgment or other obligation, the foreign refiner shall increase the 
bond to cover the amount used within 90 days of the date the bond is 
used.
    (6) The bond is used for payment of, not in lieu of, any obligation 
arising under any judgment, order, assessment or settlement agreement. 
Nothing herein is intended to waive any portion of any obligation except 
what portion is actually paid by use of funds from the bond.
    (l) [Reserved]
    (m) English language reports. Any report or other document submitted 
to EPA by a foreign refiner shall be in English language, or shall 
include an English language translation.
    (n) Prohibitions. (1) No person may combine Certified Toxics-FRGAS 
with any Non-Certified Toxics-FRGAS or Non-Toxics-FRGAS, and no person 
may combine Certified Toxics-FRGAS with any Certified Toxics-FRGAS 
produced at a different refinery, until the importer has met all the 
requirements of paragraph (o) of this section, except as provided in 
paragraph (e) of this section.
    (2) No foreign refiner or other person may cause another person to 
commit an action prohibited in paragraph (n)(1) of this section, or that 
otherwise violates the requirements of this section.
    (o) United States importer requirements. Any United States importer 
shall meet the following requirements:
    (1) Each batch of imported gasoline shall be classified by the 
importer as

[[Page 1016]]

being Toxics-FRGAS or as Non-Toxics-FRGAS, and each batch classified as 
Toxics-FRGAS shall be further classified as Certified Toxics-FRGAS or as 
Non-Certified Toxics-FRGAS.
    (2) Gasoline shall be classified as Certified Toxics-FRGAS or as 
Non-Certified Toxics-FRGAS according to the designation by the foreign 
refiner if this designation is supported by product transfer documents 
prepared by the foreign refiner as required in paragraph (d) of this 
section, unless the gasoline is classified as Non-Certified Toxics-FRGAS 
under paragraph (g) of this section.
    (3) For each gasoline batch classified as Toxics-FRGAS, any United 
States importer shall perform the following procedures:
    (i) In the case of both Certified and Non-Certified Toxics-FRGAS, 
have an independent third party:
    (A) Determine the volume of gasoline in the vessel;
    (B) Use the foreign refiner's Toxics-FRGAS certification to 
determine the name and EPA-assigned registration number of the foreign 
refinery that produced the Toxics-FRGAS;
    (C) Determine the name and country of registration of the vessel 
used to transport the Toxics-FRGAS to the United States; and
    (D) Determine the date and time the vessel arrives at the United 
States port of entry.
    (ii) In the case of Certified Toxics-FRGAS, have an independent 
third party:
    (A) Collect a representative sample from each vessel compartment 
subsequent to the vessel's arrival at the United States port of entry 
and prior to off loading any gasoline from the vessel;
    (B) Prepare a volume-weighted vessel composite sample from the 
compartment samples; and
    (C) Determine the toxics value using the methodologies specified in 
Sec. 80.730, by:
    (1) The third party analyzing the sample; or
    (2) The third party observing the importer analyze the sample.
    (4) Any importer shall submit reports within thirty days following 
the date any vessel transporting Toxics-FRGAS arrives at the United 
States port of entry:
    (i) To the Administrator containing the information determined under 
paragraph (o)(3) of this section; and
    (ii) To the foreign refiner containing the information determined 
under paragraph (o)(3)(ii) of this section.
    (5) Any United States importer shall meet the requirements specified 
in Sec. 80.815 for any imported gasoline that is not classified as 
Certified Toxics-FRGAS under paragraph (o)(2) of this section.
    (p) Truck Imports of Certified Toxics-FRGAS produced at a Refinery 
(1) Any refiner whose Certified Toxics-FRGAS is transported into the 
United States by truck may petition EPA to use alternative procedures to 
meet the following requirements:
    (i) Certification under paragraph (d)(5) of this section;
    (ii) Load port and port of entry sampling and testing under 
paragraphs (f) and (g) of this section;
    (iii) Attest under paragraph (h) of this section; and
    (iv) Importer testing under paragraph (o)(3) of this section.
    (2) These alternative procedures shall ensure Certified Toxics-FRGAS 
remains segregated from Non-Certified Toxics-FRGAS and from Non-Toxics-
FRGAS until it is imported into the United States. The petition will be 
evaluated based on whether it adequately addresses the following:
    (i) Provisions for monitoring pipeline shipments, if applicable, 
from the refinery, that ensure segregation of Certified Toxics-FRGAS 
from that refinery from all other gasoline;
    (ii) Contracts with any terminals and/or pipelines that receive and/
or transport Certified Toxics-FRGAS, that prohibit the commingling of 
Certified Toxics-FRGAS with any of the following:
    (A) Other Certified Toxics-FRGAS from other refineries.
    (B) All Non-Certified Toxics-FRGAS.
    (C) All Non-Toxics-FRGAS;
    (iii) Procedures for obtaining and reviewing truck loading records 
and United States import documents for Certified Toxics-FRGAS to ensure 
that such gasoline is only loaded into

[[Page 1017]]

trucks making deliveries to the United States;
    (iv) Attest procedures to be conducted annually by an independent 
third party that review loading records and import documents based on 
volume reconciliation, or other criteria, to confirm that all Certified 
Toxics-FRGAS remains segregated throughout the distribution system and 
is only loaded into trucks for import into the United States.
    (3) The petition required by this section shall be submitted to EPA 
along with the application for small refiner status and individual 
refinery toxics baseline and standards under Sec. 80.240 and this 
section.
    (q) Withdrawal or suspension of a foreign refinery's baseline. EPA 
may withdraw or suspend a baseline that has been assigned to a foreign 
refinery where:
    (1) A foreign refiner fails to meet any requirement of this section;
    (2) A foreign government fails to allow EPA inspections as provided 
in paragraph (i)(1) of this section;
    (3) A foreign refiner asserts a claim of, or a right to claim, 
sovereign immunity in an action to enforce the requirements in this 
subpart J; or
    (4) A foreign refiner fails to pay a civil or criminal penalty that 
is not satisfied using the foreign refiner bond specified in paragraph 
(k) of this section.
    (r) Early use of a foreign refinery baseline. (1) A foreign refiner 
may begin using an individual refinery baseline before EPA has approved 
the baseline, provided that:
    (i) A baseline petition has been submitted as required in paragraph 
(b) of this section;
    (ii) EPA has made a provisional finding that the baseline petition 
is complete;
    (iii) The foreign refiner has made the commitments required in 
paragraph (i) of this section;
    (iv) The persons who will meet the independent third party and 
independent attest requirements for the foreign refinery have made the 
commitments required in paragraphs (f)(3)(iii) and (h)(7)(iii) of this 
section; and
    (v) The foreign refiner has met the bond requirements of paragraph 
(k) of this section.
    (2) In any case where a foreign refiner uses an individual refinery 
baseline before final approval under paragraph (r)(1) of this section, 
and the foreign refinery baseline values that ultimately are approved by 
EPA are more stringent than the early baseline values used by the 
foreign refiner, the foreign refiner shall recalculate its compliance, 
ab initio, using the baseline values approved by EPA, and the foreign 
refiner shall be liable for any resulting violation of the gasoline 
toxics requirements.
    (s) Additional requirements for petitions, reports and certificates. 
Any petition for a refinery baseline under Sec. 80.915, any alternative 
procedures under paragraph (r) of this section, any report or other 
submission required by paragraph (c), (f)(2), or (i) of this section, 
and any certification under paragraph (d)(3) of this section shall be:
    (1) Submitted in accordance with procedures specified by the 
Administrator, including use of any forms that may be specified by the 
Administrator.
    (2) Be signed by the president or owner of the foreign refiner 
company, or by that person's immediate designee, and shall contain the 
following declaration:

    I hereby certify: (1) That I have actual authority to sign on behalf 
of and to bind [insert name of foreign refiner] with regard to all 
statements contained herein; (2) that I am aware that the information 
contained herein is being certified, or submitted to the United States 
Environmental Protection Agency, under the requirements of 40 CFR Part 
80, subpart J, and that the information is material for determining 
compliance under these regulations; and (3) that I have read and 
understand the information being certified or submitted, and this 
information is true, complete and correct to the best of my knowledge 
and belief after I have taken reasonable and appropriate steps to verify 
the accuracy thereof.
    I affirm that I have read and understand the provisions of 40 CFR 
Part 80, subpart J, including 40 CFR 80.1030 [insert name of foreign 
refiner]. Pursuant to Clean Air Act section 113(c) and Title 18, United 
States Code, section 1001, the penalty for furnishing false, incomplete 
or misleading information in this certification or submission is a fine 
of up to $10,000, and/or imprisonment for up to five years.

[[Page 1018]]

                           Attest Engagements



Sec. 80.1035  What are the attest engagement requirements for gasoline
toxics compliance applicable to refiners and importers?

    In addition to the requirements for attest engagements that apply to 
refiners and importers under Sec. Sec. 80.125 through 80.130, and Sec. 
80.1030, the attest engagements for refiners and importers applicable to 
this subpart J shall include the following procedures and requirements 
each year, which should be applied separately to reformulated gasoline 
(and RBOB, combined) and conventional gasoline:
    (a) Obtain the EPA toxics baseline approval letter for the refinery 
to determine the refinery's applicable baseline toxics value and 
baseline toxics volume under Sec. 80.915.
    (b) Obtain a written representation from the company representative 
stating the toxics value(s) that the company used as its baseline(s) and 
agree that number to paragraph (a) of this section.
    (c) Obtain and read a copy of the refinery's or importer's annual 
toxics reports per Sec. Sec. 1A80.75(e) and 80.105 filed with EPA for 
the year to determine the compliance baseline and incremental volume.
    (d) Agree the yearly volume of gasoline reported to EPA in the 
toxics reports with the inventory reconciliation analysis under Sec. 
80.128.
    (e) Calculate the annual average toxics value level for each type of 
gasoline specified at Sec. 80.815(b) and agree the applicable values 
with the values reported to EPA.
    (f) Calculate the difference between the yearly volume of gasoline 
reported to EPA and the baseline volume, if applicable, to determine the 
yearly incremental volume and agree that value with the value reported 
to EPA.
    (g) Calculate the compliance baseline per Sec. 80.850, and agree 
that value with the value reported to EPA.
    (h) Beginning January 1, 2011, or January 1, 2015 for small refiners 
approved per Sec. 80.1340, the requirements of this section shall apply 
only to gasoline that is not subject to the benzene standard of Sec. 
80.1230, pursuant to the provisions of Sec. 80.1235.

[66 FR 17263, Mar. 29, 2001, as amended at 72 FR 8544, Feb. 26, 2007]



Sec. 80.1040  [Reserved]

                          Additional Rulemaking



Sec. 80.1045  What additional rulemaking will EPA conduct?

    No later than July 1, 2003, the Administrator shall propose any 
requirements to control hazardous air pollutants from motor vehicles and 
motor vehicle fuels that the Administrator determines are appropriate 
pursuant to section 202(l)(2) of the Act. The Administrator will take 
final action on such proposal no later than July 1, 2004. During this 
rulemaking, EPA also intends to evaluate emissions and potential 
strategies relating to hazardous air pollutants from nonroad engines and 
vehicles.



                    Subpart K_Renewable Fuel Standard



Sec. 80.1100  How is the statutory default requirement
for 2006 implemented?

    (a) Definitions. For calendar year 2006, the definitions of section 
80.2 and the following additional definitions apply to this section.
    (1) Renewable fuel. (i) Renewable fuel means motor vehicle fuel that 
is used to replace or reduce the quantity of fossil fuel present in a 
fuel mixture used to operate a motor vehicle, and which:
    (A) Is produced from grain, starch, oil seeds, vegetable, animal, or 
fish materials including fats, greases, and oils, sugarcane, sugar 
beets, sugar components, tobacco, potatoes, or other biomass; or
    (B) Is natural gas produced from a biogas source, including a 
landfill, sewage waste treatment plant, feedlot, or other place where 
decaying organic material is found.
    (ii) The term ``renewable fuel'' includes cellulosic biomass 
ethanol, waste derived ethanol, biodiesel, and any blending components 
derived from renewable fuel.
    (2) Cellulosic biomass ethanol means ethanol derived from any

[[Page 1019]]

lignocellulosic or hemicellulosic matter that is available on a 
renewable or recurring basis, including dedicated energy crops and 
trees, wood and wood residues, plants, grasses, agricultural residues, 
fibers, animal wastes and other waste materials, and municipal solid 
waste. The term also includes any ethanol produced in facilities where 
animal wastes or other waste materials are digested or otherwise used to 
displace 90 percent or more of the fossil fuel normally used in the 
production of ethanol.
    (3) Waste derived ethanol means ethanol derived from animal wastes, 
including poultry fats and poultry wastes, and other waste materials, or 
municipal solid waste.
    (4) Small refinery means a refinery for which the average aggregate 
daily crude oil throughput for a calendar year (as determined by 
dividing the aggregate throughput for the calendar year by the number of 
days in the calendar year) does not exceed 75,000 barrels.
    (5) Biodiesel means a diesel fuel substitute produced from 
nonpetroleum renewable resources that meets the registration 
requirements for fuels and fuel additives established by the 
Environmental Protection Agency under section 211 of the Clean Air Act. 
It includes biodiesel derived from animal wastes (including poultry fats 
and poultry wastes) and other waste materials, or biodiesel derived from 
municipal solid waste and sludges and oils derived from wastewater and 
the treatment of wastewater.
    (b) Renewable Fuel Standard for 2006. The percentage of renewable 
fuel in the total volume of gasoline sold or dispensed to consumers in 
2006 in the United States shall be a minimum of 2.78 percent on an 
annual average volume basis.
    (c) Responsible parties. Parties collectively responsible for 
attainment of the standard in paragraph (b) of this section are refiners 
(including blenders) and importers of gasoline. However, a party that is 
a refiner only because he owns or operates a small refinery is exempt 
from this responsibility.
    (d) EPA determination of attainment. EPA will determine after the 
close of 2006 whether or not the requirement in paragraph (b) of this 
section has been met. EPA will base this determination on information 
routinely published by the Energy Information Administration on the 
annual domestic volume of gasoline sold or dispensed to U.S. consumers 
and of ethanol produced for use in such gasoline, supplemented by 
readily available information concerning the use in motor fuel of other 
renewable fuels such as cellulosic biomass ethanol, waste derived 
ethanol, biodiesel, and other non-ethanol renewable fuels.
    (1) The renewable fuel volume will equal the sum of all renewable 
fuel volumes used in motor fuel, provided that:
    (i) One gallon of cellulosic biomass ethanol or waste derived 
ethanol shall be considered to be the equivalent of 2.5 gallons of 
renewable fuel; and
    (ii) Only the renewable fuel portion of blending components derived 
from renewable fuel shall be counted towards the renewable fuel volume.
    (2) If the nationwide average volume percent of renewable fuel in 
gasoline in 2006 is equal to or greater than the standard in paragraph 
(b) of this section, the standard has been met.
    (e) Consequence of nonattainment in 2006. In the event that EPA 
determines that the requirement in paragraph (b) of this section has not 
been attained in 2006, a deficit carryover volume shall be added to the 
renewable fuel volume obligation for 2007 for use in calculating the 
standard applicable to gasoline in 2007.
    (1) The deficit carryover volume shall be calculated as follows:


DC = Vgas * (Rs-Ra)

Where:

DC = Deficit carryover, in gallons, of renewable fuel.
Vgas = Volume of gasoline sold or dispensed to U.S. consumers in 2006, 
in gallons.
Rs = 0.0278.
Ra = Ratio of renewable fuel volume divided by total gasoline volume 
determined in accordance with paragraph (d)(2) of this section.

    (2) There shall be no other consequence of failure to attain the 
standard in paragraph (b) of this section in 2006 for any of the parties 
in paragraph (c) of this section.

[72 FR 23991, May 1, 2007]

[[Page 1020]]



Sec. 80.1101  Definitions.

    The definitions of Sec. 80.2 and the following additional 
definitions apply for the purposes of this subpart. For calendar year 
2007 and beyond, the definitions in this section Sec. 80.1101 supplant 
those in Sec. 80.1100.
    (a) Cellulosic biomass ethanol means either of the following:
    (1) Ethanol derived from any lignocellulosic or hemicellulosic 
matter that is available on a renewable or recurring basis and includes 
any of the following:
    (i) Dedicated energy crops and trees.
    (ii) Wood and wood residues.
    (iii) Plants.
    (iv) Grasses.
    (v) Agricultural residues.
    (vi) Animal wastes and other waste materials, the latter of which 
may include waste materials that are residues (e.g., residual tops, 
branches, and limbs from a tree farm).
    (vii) Municipal solid waste.
    (2) Ethanol made at facilities at which animal wastes or other waste 
materials are digested or otherwise used onsite to displace 90 percent 
or more of the fossil fuel that is combusted to produce thermal energy 
integral to the process of making ethanol, by:
    (i) The direct combustion of the waste materials or a byproduct 
resulting from digestion of such waste materials (e.g., methane from 
animal wastes) to make thermal energy; and/or
    (ii) The use of waste heat captured from an off-site combustion 
process as a source of thermal energy.
    (b) Waste derived ethanol means ethanol derived from either of the 
following:
    (1) Animal wastes, including poultry fats and poultry wastes, and 
other waste materials.
    (2) Municipal solid waste.
    (c) Biogas means methane or other hydrocarbon gas produced from 
decaying organic material, including landfills, sewage waste treatment 
plants, and animal feedlots.
    (d) Renewable fuel. (1) Renewable fuel is any motor vehicle fuel 
that is used to replace or reduce the quantity of fossil fuel present in 
a fuel mixture used to fuel a motor vehicle, and is produced from any of 
the following:
    (i) Grain.
    (ii) Starch.
    (iii) Oilseeds.
    (iv) Vegetable, animal, or fish materials including fats, greases, 
and oils.
    (v) Sugarcane.
    (vi) Sugar beets.
    (vii) Sugar components.
    (viii) Tobacco.
    (ix) Potatoes.
    (x) Other biomass.
    (xi) Natural gas produced from a biogas source, including a 
landfill, sewage waste treatment plant, feedlot, or other place where 
there is decaying organic material.
    (2) The term ``Renewable fuel'' includes cellulosic biomass ethanol, 
waste derived ethanol, biodiesel (mono-alky ester), non-ester renewable 
diesel, and blending components derived from renewable fuel.
    (3) Ethanol covered by this definition shall be denatured as 
required and defined in 27 CFR parts 20 and 21.
    (4) Small volume additives (excluding denaturants) less than 1.0 
percent of the total volume of a renewable fuel shall be counted as part 
of the total renewable fuel volume.
    (5) A fuel produced by a renewable fuel producer that is used in 
boilers or heaters is not a motor vehicle fuel and therefore is not a 
renewable fuel.
    (e) Blending component has the same meaning as ``Gasoline blending 
stock, blendstock, or component'' as defined at Sec. 80.2(s), for which 
the portion that can be counted as renewable fuel is calculated as set 
forth in Sec. 80.1115(a).
    (f) Motor vehicle has the meaning given in Section 216(2) of the 
Clean Air Act (42 U.S.C. 7550).
    (g) Small refinery means a refinery for which the average aggregate 
daily crude oil throughput for the calendar year 2004 (as determined by 
dividing the aggregate throughput for the calendar year by the number of 
days in the calendar year) does not exceed 75,000 barrels.
    (h) Biodiesel (mono-alkyl ester) means a motor vehicle fuel or fuel 
additive which is all the following:
    (1) Registered as a motor vehicle fuel or fuel additive under 40 CFR 
part 79.
    (2) A mono-alkyl ester.

[[Page 1021]]

    (3) Meets ASTM D-6751-07, entitled ``Standard Specification for 
Biodiesel Fuel Blendstock (B100) for Middle Distillate Fuels.'' ASTM D-
6751-07 is incorporated by reference. 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. A copy may be obtained from the 
American Society for Testing and Materials, 100 Barr Harbor Drive, West 
Conshohocken, Pennsylvania. A copy may be inspected at the EPA Docket 
Center, Docket No. EPA-HQ-OAR-2005-0161, EPA/DC, EPA West, Room 3334, 
1301 Constitution Ave., NW., Washington, DC, 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/cfr/ibr-locations.html.
    (4) Intended for use in engines that are designed to run on 
conventional diesel fuel.
    (5) Derived from nonpetroleum renewable resources (as defined in 
paragraph (m) of this section).
    (i) Non-ester renewable diesel means a motor vehicle fuel or fuel 
additive which is all the following:
    (1) Registered as a motor vehicle fuel or fuel additive under 40 CFR 
part 79.
    (2) Not a mono-alkyl ester.
    (3) Intended for use in engines that are designed to run on 
conventional diesel fuel.
    (4) Derived from nonpetroleum renewable resources (as defined in 
paragraph (m) of this section).
    (j) Renewable crude means biologically derived liquid feedstocks 
including but not limited to poultry fats, poultry wastes, vegetable 
oil, and greases that are used as feedstocks to make gasoline or diesel 
fuels at production units as specified in paragraph (k) of this section.
    (k) Renewable crude-based fuels are renewable fuels that are 
gasoline or diesel products resulting from the processing of renewable 
crudes in production units within refineries or at dedicated facilities 
within refineries, that process petroleum based feedstocks and which 
make gasoline and diesel fuel.
    (l) Importers. For the purposes of this subpart only, an importer of 
gasoline or renewable fuel is:
    (1) Any person who brings gasoline or renewable fuel into the 48 
contiguous states of the United States from a foreign country or from an 
area that has not opted in to the program requirements of this subpart 
pursuant to Sec. 80.1143; and
    (2) Any person who brings gasoline or renewable fuel into an area 
that has opted in to the program requirements of this subpart pursuant 
to Sec. 80.1143.
    (m) Nonpetroleum renewable resources include, but are not limited to 
the following:
    (1) Plant oils.
    (2) Animal fats and animal wastes, including poultry fats and 
poultry wastes, and other waste materials.
    (3) Municipal solid waste and sludges and oils derived from 
wastewater and the treatment of wastewater.
    (n) Export of renewable fuel means:
    (1) Transfer of a batch of renewable fuel to a location outside the 
United States; and
    (2) Transfer of a batch of renewable fuel from a location in the 
contiguous 48 states to Alaska, Hawaii, or a United States territory, 
unless that state or territory has received an approval from the 
Administrator to opt-in to the renewable fuel program pursuant to Sec. 
80.1143.
    (o) Renewable Identification Number (RIN), is a unique number 
generated to represent a volume of renewable fuel pursuant to Sec. Sec. 
80.1125 and 80.1126.
    (1) Gallon-RIN is a RIN that represents an individual gallon of 
renewable fuel; and
    (2) Batch-RIN is a RIN that represents multiple gallon-RINs.
    (p) Neat renewable fuel is a renewable fuel to which only de minimus 
amounts of conventional gasoline or diesel have been added.

[72 FR 23992, May 1, 2007]



Sec. Sec. 80.1102-80.1103  [Reserved]



Sec. 80.1104  What are the implementation dates for the Renewable Fuel
Standard Program?

    The RFS standards and other requirements of Sec. 80.1101 and all 
sections

[[Page 1022]]

following are effective beginning on September 1, 2007.

[72 FR 23993, May 1, 2007]



Sec. 80.1105  What is the Renewable Fuel Standard?

    (a) The annual value of the renewable fuel standard for 2007 shall 
be 4.02 percent.
    (b) Beginning with the 2008 compliance period, EPA will calculate 
the value of the annual standard and publish this value in the Federal 
Register by November 30 of the year preceding the compliance period.
    (c) EPA will base the calculation of the standard on information 
provided by the Energy Information Administration regarding projected 
gasoline volumes and projected volumes of renewable fuel expected to be 
used in gasoline blending for the upcoming year.
    (d) EPA will calculate the annual renewable fuel standard using the 
following equation:
[GRAPHIC] [TIFF OMITTED] TR01MY07.059

Where:

RFStdi = Renewable Fuel Standard, in year i, in percent.
RFVi = Nationwide annual volume of renewable fuels required 
by section 211(o)(2)(B) of the Act (42 U.S.C. 7545), for year i, in 
gallons.
Gi = Amount of gasoline projected to be used in the 48 
contiguous states, in year i, in gallons.
Ri = Amount of renewable fuel blended into gasoline that is 
projected to be used in the 48 contiguous states, in year i, in gallons.
GSi = Amount of gasoline projected to be used in 
noncontiguous states or territories (if the state or territory opts-in), 
in year i, in gallons.
RSi = Amount of renewable fuel blended into gasoline that is 
projected to be used in noncontiguous states or territories (if the 
state or territory opts-in), in year i, in gallons.
GEi = Amount of gasoline projected to be produced by exempt 
small refineries and small refiners, in year i, in gallons (through 2010 
only, except to the extent that a small refinery exemption is extended 
pursuant to Sec. 80.1141(e)).
Celli = Beginning in 2013, the amount of renewable fuel that 
is required to come from cellulosic sources, in year i, in gallons.

    (e) Beginning with the 2013 compliance period, EPA will calculate 
the value of the annual cellulosic standard and publish this value in 
the Federal Register by November 30 of the year preceding the compliance 
period.
    (f) EPA will calculate the annual cellulosic standard using the 
following equation:
[GRAPHIC] [TIFF OMITTED] TR01MY07.060

Where:

RFCelli = Renewable Fuel Cellulosic Standard in year i, in 
percent.
Gi = Amount of gasoline projected to be used in the 48 
contiguous states, in year i, in gallons.
Ri = Amount of renewable fuel blended into gasoline that is 
projected to be used in the 48 contiguous states, in year i, in gallons.
GSi = Amount of gasoline projected to be used in 
noncontiguous states or territories (if the state or territory opts-in), 
in year i, in gallons.
RSi = Amount of renewable fuel blended into gasoline that is 
projected to be used in noncontiguous states or territories (if the 
state or territory opts-in), in year i, in gallons.
Celli = Amount of renewable fuel that is required to come 
from cellulosic sources, in year i, in gallons.

[72 FR 23993, May 1, 2007]



Sec. 80.1106  To whom does the Renewable Volume Obligation apply?

    (a) (1) An obligated party is a refiner that produces gasoline 
within the 48 contiguous states, or an importer that imports gasoline 
into the 48 contiguous states. A party that simply adds renewable fuel 
to gasoline, as defined in Sec. 80.1107(c), is not an obligated party.
    (2) If the Administrator approves a petition of Alaska, Hawaii, or a 
United States territory to opt-in to the renewable fuel program under 
the provisions

[[Page 1023]]

in Sec. 80.1143, then ``obligated party'' shall also include any 
refiner that produces gasoline within that state or territory, or any 
importer that imports gasoline into that state or territory.
    (3) For the purposes of this section, ``gasoline'' refers to any and 
all of the products specified at Sec. 80.1107(c).
    (b) For each compliance period starting with 2007, any obligated 
party is required to demonstrate, pursuant to Sec. 80.1127, that it has 
satisfied the Renewable Volume Obligation for that compliance period, as 
specified in Sec. 80.1107(a).
    (c) An obligated party may comply with the requirements of paragraph 
(b) of this section for all of its refineries in the aggregate, or for 
each refinery individually.
    (d) An obligated party must comply with the requirements of 
paragraph (b) of this section for all of its imported gasoline in the 
aggregate.
    (e) An obligated party that is both a refiner and importer must 
comply with the requirements of paragraph (b) of this section for its 
imported gasoline separately from gasoline produced by its refinery or 
refineries.
    (f) Where a refinery or importer is jointly owned by two or more 
parties, the requirements of paragraph (b) of this section may be met by 
one of the joint owners for all of the gasoline produced at the 
refinery, or all of the imported gasoline, in the aggregate, or each 
party may meet the requirements of paragraph (b) of this section for the 
portion of the gasoline that it owns, as long as all of the gasoline 
produced at the refinery, or all of the imported gasoline, is accounted 
for in determining the renewable fuels obligation under Sec. 80.1107.
    (g) The requirements in paragraph (b) of this section apply to the 
following compliance periods:
    (1) For 2007, the compliance period is September 1 through December 
31.
    (2) Beginning in 2008, and every year thereafter, the compliance 
period is January 1 through December 31.

[72 FR 23993, May 1, 2007]



Sec. 80.1107  How is the Renewable Volume Obligation calculated?

    (a) The Renewable Volume Obligation for an obligated party is 
determined according to the following formula:

RVOi = (RFStdi * GVi) + Di-1

Where:

RVOi = The Renewable Volume Obligation for an obligated party 
for calendar year i, in gallons of renewable fuel.
RFStdi = The renewable fuel standard for calendar year i, 
determined by EPA pursuant to Sec. 80.1105, in percent.
GVi = The non-renewable gasoline volume, determined in 
accordance with paragraphs (b), (c), and (d) of this section, which is 
produced or imported by the obligated party in calendar year i, in 
gallons.
Di-1 = Renewable fuel deficit carryover from the previous 
year, per Sec. 80.1127(b), in gallons.

    (b) The non-renewable gasoline volume for a refiner, blender, or 
importer for a given year, GVi, specified in paragraph (a) of 
this section is calculated as follows:
[GRAPHIC] [TIFF OMITTED] TR01MY07.061

Where:

x = Individual batch of gasoline produced or imported in calendar year 
i.
n = Total number of batches of gasoline produced or imported in calendar 
year i.
GX = Volume of batch x of gasoline produced or imported, in 
gallons.
y = Individual batch of renewable fuel blended into gasoline in calendar 
year i.
m = Total number of batches of renewable fuel blended into gasoline in 
calendar year i.
RBy = Volume of batch y of renewable fuel blended into 
gasoline, in gallons.

    (c) All of the following products that are produced or imported 
during a compliance period, collectively called ``gasoline'' for the 
purposes of this section (unless otherwise specified), are to be 
included in the volume used to calculate a party's renewable volume 
obligation under paragraph (a) of this section, except as provided in 
paragraph (d) of this section:
    (1) Reformulated gasoline, whether or not renewable fuel is later 
added to it.
    (2) Conventional gasoline, whether or not renewable fuel is later 
added to it.
    (3) Reformulated gasoline blendstock that becomes finished 
reformulated gasoline upon the addition of oxygenate (``RBOB'').

[[Page 1024]]

    (4) Conventional gasoline blendstock that becomes finished 
conventional gasoline upon the addition of oxygenate (``CBOB'').
    (5) Blendstock (including butane and gasoline treated as blendstock 
(``GTAB'')) that has been combined with other blendstock and/or finished 
gasoline to produce gasoline.
    (6) Any gasoline, or any unfinished gasoline that becomes finished 
gasoline upon the addition of oxygenate, that is produced or imported to 
comply with a state or local fuels program.
    (d) The following products are not included in the volume of 
gasoline produced or imported used to calculate a party's renewable 
volume obligation under paragraph (a) of this section:
    (1) Any renewable fuel as defined in Sec. 80.1101(d).
    (2) Blendstock that has not been combined with other blendstock or 
finished gasoline to produce gasoline.
    (3) Gasoline produced or imported for use in Alaska, Hawaii, the 
Commonwealth of Puerto Rico, the U.S. Virgin Islands, Guam, American 
Samoa, and the Commonwealth of the Northern Marianas, unless the area 
has opted into the RFS program under Sec. 80.1143.
    (4) Gasoline produced by a small refinery that has an exemption 
under Sec. 80.1141 or an approved small refiner that has an exemption 
under Sec. 80.1142 until January 1, 2011 (or later, for small 
refineries, if their exemption is extended pursuant to Sec. 
80.1141(e)).
    (5) Gasoline exported for use outside the 48 United States, and 
gasoline exported for use outside Alaska, Hawaii, the Commonwealth of 
Puerto Rico, the U.S. Virgin Islands, Guam, American Samoa, and the 
Commonwealth of the Northern Marianas, if the area has opted into the 
RFS program under Sec. 80.1143.
    (6) For blenders, the volume of finished gasoline, RBOB, or CBOB to 
which a blender adds blendstocks.
    (7) The gasoline portion of transmix produced by a transmix 
processor, or the transmix blended into gasoline by a transmix blender, 
under 40 CFR 80.84.

[72 FR 23993, May 1, 2007]



Sec. Sec. 80.1108-80.1114  [Reserved]



Sec. 80.1115  How are equivalence values assigned to renewable fuel?

    (a)(1) Each gallon of a renewable fuel shall be assigned an 
equivalence value by the producer or importer pursuant to paragraph (b) 
or (c) of this section.
    (2) The equivalence value is a number that is used to determine how 
many gallon-RINs can be generated for a batch of renewable fuel 
according to Sec. 80.1126.
    (b) Equivalence values shall be assigned for certain renewable fuels 
as follows:
    (1) Cellulosic biomass ethanol and waste derived ethanol produced on 
or before December 31, 2012 which is denatured shall have an equivalence 
value of 2.5.
    (2) Ethanol other than cellulosic biomass ethanol or waste-derived 
ethanol which is denatured shall have an equivalence value of 1.0.
    (3) Biodiesel (mono-alkyl ester) shall have an equivalence value of 
1.5.
    (4) Butanol shall have an equivalence value of 1.3.
    (5) Non-ester renewable diesel, including that produced from 
coprocessing a renewable crude with fossil fuels in a hydrotreater, 
shall have an equivalence value of 1.7.
    (6) All other renewable crude-based renewable fuels shall have an 
equivalence value of 1.0.
    (c)(1) For renewable fuels not listed in paragraph (b) of this 
section, a producer or importer shall submit an application to the 
Agency for an equivalence value following the provisions of paragraph 
(d) of this section.
    (2) A producer or importer may also submit an application for an 
alternative equivalence value pursuant to paragraph (d) of this section 
if the renewable fuel is listed in paragraph (b) of this section, but 
the producer or importer has reason to believe that a different 
equivalence value than that listed in paragraph (b) of this section is 
warranted.
    (d) Determination of equivalence values. (1) Except as provided in 
paragraph (d)(4) of this section, the equivalence value for renewable 
fuels described in paragraph (c) of this section shall be calculated 
using the following formula:


[[Page 1025]]


EV = (R / 0.931) * (EC / 77,550)

Where:

EV = Equivalence Value for the renewable fuel, rounded to the nearest 
tenth.
R = Renewable content of the renewable fuel. This is a measure of the 
portion of a renewable fuel that came from a renewable source, expressed 
as a percent, on an energy basis.
EC = Energy content of the renewable fuel, in Btu per gallon (lower 
heating value).

    (2) The application for an equivalence value shall include a 
technical justification that includes a description of the renewable 
fuel, feedstock(s) used to make it, and the production process.
    (3) The Agency will review the technical justification and assign an 
appropriate Equivalence Value to the renewable fuel based on the 
procedure in this paragraph (d).
    (4) For biogas, the Equivalence Value is 1.0, and 77,550 Btu of 
biogas is equivalent to 1 gallon of renewable fuel.

[72 FR 23995, May 1, 2007]



Sec. Sec. 80.1116-80.1124  [Reserved]



Sec. 80.1125  Renewable Identification Numbers (RINs).

    Each RIN is a 38 character numeric code of the following form:
    KYYYYCCCCFFFFFBBBBBRRDSS

SSSSSSEEEEEEEE
    (a) K is a number identifying the type of RIN as follows:
    (1) K has the value of 1 when the RIN is assigned to a volume of 
renewable fuel pursuant to Sec. Sec. 80.1126(e) and 80.1128(a).
    (2) K has the value of 2 when the RIN has been separated from a 
volume of renewable fuel pursuant to Sec. 80.1126(e)(4) or Sec. 
80.1129.
    (b) YYYY is the calendar year in which the batch of renewable fuel 
was produced or imported. YYYY also represents the year in which the RIN 
was originally generated.
    (c) CCCC is the registration number assigned according to Sec. 
80.1150 to the producer or importer of the batch of renewable fuel.
    (d) FFFFF is the registration number assigned according to Sec. 
80.1150 to the facility at which the batch of renewable fuel was 
produced or imported.
    (e) BBBBB is a serial number assigned to the batch which is chosen 
by the producer or importer of the batch such that no two batches have 
the same value in a given calendar year.
    (f) RR is a number representing the equivalence value of the 
renewable fuel as specified in Sec. 80.1115 and multiplied by 10 to 
produce the value for RR.
    (g) D is a number identifying the type of renewable fuel, as 
follows:
    (1) D has the value of 1 if the renewable fuel can be categorized as 
cellulosic biomass ethanol as defined in Sec. 80.1101(a).
    (2) D has the value of 2 if the renewable fuel cannot be categorized 
as cellulosic biomass ethanol as defined in Sec. 80.1101(a).
    (h) SSSSSSSS is a number representing the first gallon-RIN 
associated with a batch of renewable fuel.
    (i) EEEEEEEE is a number representing the last gallon-RIN associated 
with a batch of renewable fuel. EEEEEEEE will be identical to SSSSSSSS 
if the batch-RIN represents a single gallon-RIN. Assign the value of 
EEEEEEEE as described in Sec. 80.1126.

[72 FR 23995, May 1, 2007]



Sec. 80.1126  How are RINs generated and assigned to batches of
renewable fuel by renewable fuel producers or importers?

    (a) Regional applicability. (1) Except as provided in paragraph (b) 
of this section, a RIN must be assigned by a renewable fuel producer or 
importer to every batch of renewable fuel produced by a facility located 
in the contiguous 48 states of the United States, or imported into the 
contiguous 48 states.
    (2) If the Administrator approves a petition of Alaska, Hawaii, or a 
United States territory to opt-in to the renewable fuel program under 
the provisions in Sec. 80.1143, then the requirements of paragraph 
(a)(1) of this section shall also apply to renewable fuel produced or 
imported into that state or territory beginning in the next calendar 
year.
    (b) Volume threshold. Renewable fuel producers located within the 
United States that produce less than 10,000 gallons of renewable fuel 
each year, and importers that import less than 10,000 gallons of 
renewable fuel each year, are not required to generate and assign RINs 
to batches of renewable fuel. Such producers and importers are

[[Page 1026]]

also exempt from the registration, reporting, and recordkeeping 
requirements of Sec. Sec. 80.1150-80.1152. However, for such producers 
and importers that voluntarily generate and assign RINs, all the 
requirements of this subpart apply.
    (c) Definition of batch. For the purposes of this section and Sec. 
80.1125, a ``batch of renewable fuel'' is a volume of renewable fuel 
that has been assigned a unique RIN code BBBBB within a calendar year by 
the producer or importer of the renewable fuel in accordance with the 
provisions of this section and Sec. 80.1125.
    (1) The number of gallon-RINs generated for a batch of renewable 
fuel may not exceed 99,999,999.
    (2) A batch of renewable fuel cannot represent renewable fuel 
produced or imported in excess of one calendar month.
    (d) Generation of RINs. (1) Except as provided in paragraph (b) of 
this section, the producer or importer of a batch of renewable fuel must 
generate RINs for that batch, including any renewable fuel contained in 
imported gasoline.
    (2) A producer or importer of renewable fuel may generate RINs for 
volumes of renewable fuel that it owns on September 1, 2007.
    (3) A party generating a RIN shall specify the appropriate numerical 
values for each component of the RIN in accordance with the provisions 
of Sec. 80.1125 and this paragraph (d).
    (4) Except as provided in paragraph (d)(6) of this section, the 
number of gallon-RINs that shall be generated for a given batch of 
renewable fuel shall be equal to a volume calculated according to the 
following formula:

VRIN = EV * Vs

Where:

VRIN = RIN volume, in gallons, for use determining the number 
of gallon-RINs that shall be generated.
EV = Equivalence value for the renewable fuel per Sec. 80.1115.
Vs = Standardized volume of the batch of renewable fuel at 60 
[deg]F, in gallons, calculated in accordance with paragraph (d)(7) of 
this section.

    (5) Multiple gallon-RINs generated to represent a given volume of 
renewable fuel can be represented by a single batch-RIN through the 
appropriate designation of the RIN volume codes SSSSSSSS and EEEEEEEE.
    (i) The value of SSSSSSSS in the batch-RIN shall be 00000001 to 
represent the first gallon-RIN associated with the volume of renewable 
fuel.
    (ii) The value of EEEEEEEE in the batch-RIN shall represent the last 
gallon-RIN associated with the volume of renewable fuel, based on the 
RIN volume determined pursuant to paragraph (d)(4) of this section.
    (6) (i) For renewable crude-based renewable fuels produced in a 
facility or unit that coprocesses renewable crudes and fossil fuels, the 
number of gallon-RINs that shall be generated for a given batch of 
renewable fuel shall be equal to the gallons of renewable crude used 
rather than the gallons of renewable fuel produced.
    (ii) Parties that produce renewable crude-based renewable fuels in a 
facility or unit that coprocesses renewable crudes and fossil fuels may 
submit a petition to the Agency requesting the use of volumes of 
renewable fuel produced as the basis for the number of gallon-RINs, 
pursuant to paragraph (d)(4) of this section.
    (7) Standardization of volumes. In determining the standardized 
volume of a batch of renewable fuel for purposes of generating RINs 
under this paragraph (d), the batch volumes shall be adjusted to a 
standard temperature of 60 [deg]F.
    (i) For ethanol, the following formula shall be used:

Vs,e = Va,e * (-0.0006301 * T + 1.0378)

Where:

Vs,e = Standardized volume of ethanol at 60 [deg]F, in 
gallons.
Va,e = Actual volume of ethanol, in gallons.
T = Actual temperature of the batch, in [deg]F.

    (ii) For biodiesel (mono alkyl esters), the following formula shall 
be used:

Vs,b = Va,b * (-0.0008008 * T + 1.0480)

Where:

Vs,b = Standardized volume of biodiesel at 60 [deg]F, in 
gallons.
Va,b = Actual volume of biodiesel, in gallons.
T = Actual temperature of the batch, in [deg]F.

    (iii) For other renewable fuels, an appropriate formula commonly 
accepted by the industry shall be used to standardize the actual volume 
to 60 [deg]F. Formulas used must be reported to the

[[Page 1027]]

Agency, and may be reviewed for appropriateness.
    (8) (i) A party is prohibited from generating RINs for a volume of 
renewable fuel that it produces if:
    (A) The renewable fuel has been produced from a chemical conversion 
process that uses another renewable fuel as a feedstock; and
    (B) The renewable fuel used as a feedstock was produced by another 
party.
    (ii) Any RINs that the party acquired with renewable fuel used as a 
feedstock shall be assigned to the new renewable fuel that was made with 
that feedstock.
    (e) Assignment of RINs to batches. (1) Except as provided in 
paragraph (e)(4) of this section, the producer or importer of renewable 
fuel must assign all RINs generated to volumes of renewable fuel.
    (2) A RIN is assigned to a volume of renewable fuel when ownership 
of the RIN is transferred along with the transfer of ownership of the 
volume of renewable fuel, pursuant to Sec. 80.1128(a).
    (3) All assigned RINs shall have a K code value of 1.
    (4) RINs not assigned to batches. (i) If a party produces or imports 
a batch of cellulosic biomass ethanol or waste-derived ethanol having an 
equivalence value of 2.5, that party must assign at least one gallon-RIN 
to each gallon of cellulosic biomass ethanol or waste-derived ethanol, 
representing the first 1.0 portion of the Equivalence Value.
    (ii) Any remaining gallon-RINs generated for the cellulosic biomass 
ethanol or waste-derived ethanol which represent the remaining 1.5 
portion of the Equivalence Value may remain unassigned.
    (iii) The producer or importer of cellulosic biomass ethanol or 
waste-derived ethanol shall designate the K code as 2 for all unassigned 
RINs.

[72 FR 23995, May 1, 2007]



Sec. 80.1127  How are RINs used to demonstrate compliance?

    (a) Renewable volume obligations. (1) Except as specified in 
paragraph (b) of this section, each party that is obligated to meet the 
Renewable Volume Obligation under Sec. 80.1107, or each party that is 
an exporter of renewable fuels that is obligated to meet a Renewable 
Volume Obligation under Sec. 80.1130, must demonstrate pursuant to 
Sec. 80.1152(a)(1) that it has taken ownership of sufficient RINs to 
satisfy the following equation:

(<3-ln [><5-ln )>{<3-ln ]>RINNUM)i 
    + 
    (<3-ln [><5-ln )>{<3-ln ]>RINNUM)i-1
     = RVOi

Where:

(<3-ln [><5-ln )>{<3-ln ]>RINNUM)i 
= Sum of all owned gallon-RINs that were generated in year i and are 
being applied towards the RVOi, in gallons.
(<3-ln [><5-ln )>{<3-ln ]>RINNUM)i-1
 = Sum of all owned gallon-RINs that were generated in year i-1 and are 
being applied towards the RVOi, in gallons.
RVOi = The Renewable Volume Obligation for the obligated 
party or renewable fuel exporter for calendar year i, in gallons, 
pursuant to Sec. 80.1107 or Sec. 80.1130.

    (2) For compliance for calendar years 2008 and later, the value of 
(<3-ln [><5-ln )>{<3-ln ]>RINNUM)i-1
 may not exceed a value determined by the following inequality:

(<3-ln [><5-ln )>{<3-ln ]>RINNUM)i-1
     <= 0.20 x RVOi

    (3) RINs may only be used to demonstrate compliance with the RVO for 
the calendar year in which they were generated or the following calendar 
year. RINs used to demonstrate compliance in one year cannot be used to 
demonstrate compliance in any other year.
    (4) A party may only use a RIN for purposes of meeting the 
requirements of paragraphs (a)(1) and (a)(2) of this section if that RIN 
is an unassigned RIN with a K code of 2 obtained in accordance with 
Sec. Sec. 80.1126(e)(4), 80.1128, and 80.1129.
    (5) The number of gallon-RINs associated with a given batch-RIN that 
can be used for compliance with the RVO shall be calculated from the 
following formula:

RINNUM = EEEEEEEE-SSSSSSSS + 1

Where:

RINNUM = Number of gallon-RINs associated with a batch-RIN, where each 
gallon-RIN represents one gallon of renewable fuel for compliance 
purposes.
EEEEEEEE = Batch-RIN component identifying the last gallon-RIN 
associated with the batch-RIN.
SSSSSSSS = Batch-RIN component identifying the first gallon-RIN 
associated with the batch-RIN.


[[Page 1028]]


    (b) Deficit carryovers. (1) An obligated party or an exporter of 
renewable fuel that fails to meet the requirements of paragraphs (a)(1) 
or (a)(2) of this section for calendar year i is permitted to carry a 
deficit into year i+1 under the following conditions:
    (i) The party did not carry a deficit into calendar year i from 
calendar year i-1.
    (ii) The party subsequently meets the requirements of paragraph 
(a)(1) of this section for calendar year i+1 and carries no deficit into 
year i+2.
    (2) A deficit is calculated according to the following formula:

Di RVOi-1 
    (<3-ln [><5-ln )>{<3-ln ]>RINNUM)i+1
     (<3-ln [><5-ln )>{<3-ln ]>RINNUM)i-1


Where:

Di = The deficit, in gallons, generated in calendar year i 
that must be carried over to year i+1 if allowed to do so pursuant to 
paragraph (b)(1)(i) of this section.
RVOi = The Renewable Volume Obligation for the obligated 
party or renewable fuel exporter for calendar year i, in gallons.
(<3-ln [><5-ln )>{<3-ln ]>RINNUM)i-1
 = Sum of all acquired gallon-RINs that were generated in year i and are 
being applied towards the RVOi, in gallons.
(<3-ln [><5-ln )>{<3-ln ]>RINNUM)i-1
 = Sum of all acquired gallon-RINs that were generated in year i-1 and 
are being applied towards the RVOi, in gallons.

[72 FR 23995, May 1, 2007]



Sec. 80.1128  General requirements for RIN distribution.

    (a) RINs assigned to volumes of renewable fuel. (1) Assigned RIN, 
for the purposes of this subpart, means a RIN assigned to a volume of 
renewable fuel pursuant to Sec. 80.1126(e) with a K code of 1.
    (2) Except as provided in Sec. 80.1126(e)(4) and Sec. 80.1129, no 
party can separate a RIN that has been assigned to a batch pursuant to 
Sec. 80.1126(e).
    (3) An assigned RIN cannot be transferred to another party without 
simultaneously transferring a volume of renewable fuel to that same 
party.
    (4) No more than 2.5 assigned gallon-RINs with a K code of 1 can be 
transferred to another party with every gallon of renewable fuel 
transferred to that same party.
    (5) (i) On each of the dates listed in paragraph (a)(5)(v) of this 
section in any calendar year, the following equation must be satisfied 
for assigned RINs and volumes of renewable fuel owned by a party:

<3-ln [><5-ln )>{<3-ln ]>(RIN)D <= 
    <3-ln [><5-ln )>{<3-ln ]>(Vsi 
    xEVi)D

Where:

D = Applicable date.
<3-ln [><5-ln )>{<3-ln ]>(RIN)D = 
Sum of all assigned gallon-RINs with a K code of 1 that are owned on 
date D.
(Vsi)D = Volume i of renewable fuel owned on date 
D, standardized to 60 [deg]F, in gallons.
EVi = Equivalence value representing volume i.
<3-ln [><5-ln )>{<3-ln ]>(Vsix 
EVi)D = Sum of all volumes of renewable fuel owned 
on date D, multiplied by their respective equivalence values.

    (ii) The equivalence value EVi for use in the equation in 
paragraph (a)(5)(i) of this section for any volume of ethanol shall be 
2.5.
    (iii) If the equivalence value for a volume of renewable fuel i can 
be determined pursuant to Sec. 80.1115 based on its composition, then 
the appropriate equivalence value shall be used for EVi.
    (iv) If the equivalence value for a volume of renewable fuel cannot 
be determined based on its composition, the value of EVi 
shall be 1.0.
    (v) The applicable dates are March 31, June 30, September 30, and 
December 31. For 2007 only, the applicable dates are September 30, and 
December 31.
    (6) Producers and importers of renewable fuel. (i) Except as 
provided in paragraph (a)(6)(ii) of this section, a producer or importer 
of renewable fuel must transfer ownership of a number of gallon-RINs 
with a K code of 1 whenever it transfers ownership of a volume of 
renewable fuel such that the ratio of gallon-RINs to gallons is equal to 
the equivalence value for the renewable fuel.

<3-ln [><5-ln )>{<3-ln ]>(RIN) / Vs 
    = EV

Where:

<3-ln [><5-ln )>{<3-ln ]>(RIN) = Sum of all 
gallon-RINs with a K code of 1 which are transferred along with volume 
Vs.
Vs = A volume of renewable fuel transferred, standardized to 
60 [deg]F, in gallons.
EV = Equivalence value assigned to the renewable fuel being transferred.

    (ii) A producer or importer of renewable fuel can transfer ownership 
of a volume of renewable fuel without simultaneously transferring 
ownership

[[Page 1029]]

of gallon-RINs having a K code of 1 if it can demonstrate one of the 
following:
    (A) It is a small volume producer exempt from the requirement to 
generate RINs pursuant to Sec. 80.1126(b); or
    (B) The producer or importer received an equivalent volume of 
renewable fuel from another party without accompanying RINs.
    (C) The producer or importer has generated RINs for cellulosic 
biomass ethanol or waste-derived ethanol having an equivalence value of 
2.5, and has chosen to specify as unassigned a number of gallon-RINs 
pursuant to Sec. 80.1126(e)(4).
    (7) Any transfer of ownership of assigned RINs must be documented on 
product transfer documents generated pursuant to Sec. 80.1153.
    (i) The RIN must be recorded on the product transfer document used 
to transfer ownership of the RIN and the volume to another party; or
    (ii) The RIN must be recorded on a separate product transfer 
document transferred to the same party on the same day as the product 
transfer document used to transfer ownership of the volume of renewable 
fuel.
    (b) RINs not assigned to volumes of renewable fuel. (1) Unassigned 
RIN, for the purposes of this subpart, means a RIN with a K code of 2 
that has been separated from a volume of renewable fuel pursuant to 
Sec. 80.1126(e)(4) or Sec. 80.1129.
    (2) Any party that has registered pursuant to Sec. 80.1150 can hold 
title to an unassigned RIN.
    (3) Unassigned RINs can be transferred from one party to another any 
number of times.
    (4) An unassigned batch-RIN can be divided by its holder into 
multiple batch-RINs, each representing a smaller number of gallon-RINs, 
if all of the following conditions are met:
    (i) All RIN components other than SSSSSSSS and EEEEEEEE are 
identical for the original parent and newly formed daughter RINs.
    (ii) The sum of the gallon-RINs associated with the multiple 
daughter batch-RINs is equal to the gallon-RINs associated with the 
parent batch-RIN.

[72 FR 23995, May 1, 2007]



Sec. 80.1129  Requirements for separating RINs from volumes of
renewable fuel.

    (a)(1) Separation of a RIN from a volume of renewable fuel means 
termination of the assignment of the RIN to a volume of renewable fuel.
    (2) RINs that have been separated from volumes of renewable fuel 
become unassigned RINs subject to the provisions of Sec. 80.1128(b).
    (b) A RIN that is assigned to a volume of renewable fuel is 
separated from that volume only under one of the following conditions:
    (1) Except as provided in paragraph (b)(6) of this section, a party 
that is an obligated party according to Sec. 80.1106 must separate any 
RINs that have been assigned to a volume of renewable fuel if they own 
that volume.
    (2) Except as provided in paragraph (b)(5) of this section, any 
party that owns a volume of renewable fuel must separate any RINs that 
have been assigned to that volume once the volume is blended with 
gasoline or diesel to produce a motor vehicle fuel.
    (3) Any party that exports a volume of renewable fuel must separate 
any RINs that have been assigned to the exported volume.
    (4) Any renewable fuel producer or importer that produces or imports 
a volume of renewable fuel shall have the right to separate any RINs 
that have been assigned to that volume if the producer or importer 
designates the renewable fuel as motor vehicle fuel and the renewable 
fuel is used as motor vehicle fuel.
    (5) RINs assigned to a volume of biodiesel (mono-alkyl ester) can 
only be separated from that volume pursuant to paragraph (b)(2) of this 
section if such biodiesel is blended into diesel fuel at a concentration 
of 80 volume percent biodiesel (mono-alkyl ester) or less.
    (i) This paragraph (b)(5) shall not apply to obligated parties or 
exporters of renewable fuel.
    (ii) This paragraph (b)(5) shall not apply to renewable fuel 
producers meeting the requirements of paragraph (b)(4) of this section.
    (6) For RINs that an obligated party generates, the obligated party 
can only

[[Page 1030]]

separate such RINs from volumes of renewable fuel if the number of 
gallon-RINs separated is less than or equal to its annual RVO.
    (7) A producer or importer of cellulosic biomass ethanol or waste-
derived ethanol can separate a portion of the RINs that it generates 
pursuant to Sec. 80.1126(e)(4).
    (c) The party responsible for separating a RIN from a volume of 
renewable fuel shall change the K code in the RIN from a value of 1 to a 
value of 2 prior to transferring the RIN to any other party.
    (d) (1) Upon and after separation from a renewable fuel volume, a 
RIN shall not appear on documentation that is either:
    (i) Used to identify title to the volume of renewable fuel; or
    (ii) Transferred with the volume of renewable fuel.
    (2) Upon and after separation of a RIN from its associated volume, 
product transfer documents used to transfer ownership of the volume must 
continue to meet the requirements of Sec. 80.1153(a)(5)(iii).
    (e) Any obligated party that uses a renewable fuel in a boiler or 
heater must retire any RINs associated with that volume of renewable 
fuel and report the retired RINs in the applicable reports under Sec. 
80.1152.

[72 FR 23995, May 1, 2007]



Sec. 80.1130  Requirements for exporters of renewable fuels.

    (a) Any party that owns any amount of renewable fuel (in its neat 
form or blended with gasoline or diesel) that is exported from the 
region described in Sec. 80.1126(a) shall acquire sufficient RINs to 
offset a Renewable Volume Obligation representing the exported renewable 
fuel.
    (b) Renewable Volume Obligations. An exporter of renewable fuel 
shall determine its Renewable Volume Obligation from the volumes of the 
renewable fuel exported.
    (1) A renewable fuel exporter's total Renewable Volume Obligation 
shall be calculated according to the following formula:

RVOi = (VOLk * EVk)i + 
    Di-1

Where:

RVOi = The Renewable Volume Obligation for the exporter for 
calendar year i, in gallons of renewable fuel.
k = A discrete volume of renewable fuel.
VOLk = The standardized volume of discrete volume k of 
exported renewable fuel, in gallons, calculated in accordance with Sec. 
80.1126(d)(7).
EVk = The equivalence value associated with discrete volume 
k.
 = Sum involving all volumes of renewable fuel exported.
Di-1 = Renewable fuel deficit carryover from the previous 
year, in gallons.

    (2)(i) If the equivalence value for a volume of renewable fuel can 
be determined pursuant to Sec. 80.1115 based on its composition, then 
the appropriate equivalence value shall be used in the calculation of 
the exporter's Renewable Volume Obligation.
    (ii) If the equivalence value for a volume of renewable fuel cannot 
be determined, the value of EVk shall be 1.0.
    (c) Each exporter of renewable fuel must demonstrate compliance with 
its RVO using RINs it has acquired pursuant to Sec. 80.1127.

[72 FR 23995, May 1, 2007]



Sec. 80.1131  Treatment of invalid RINs.

    (a) Invalid RINs. An invalid RIN is a RIN that is any of the 
following:
    (1) Is a duplicate of a valid RIN.
    (2) Was based on volumes that have not been standardized to 60 
[deg]F.
    (3) Has expired.
    (4) Was based on an incorrect equivalence value.
    (5) Is deemed invalid under Sec. 80.1167(g).
    (6) Does not represent renewable fuel as it is defined in Sec. 
80.1101.
    (7) Was otherwise improperly generated.
    (b) In the case of RINs that are invalid, the following provisions 
apply:
    (1) Invalid RINs cannot be used to achieve compliance with the 
Renewable Volume Obligation of an obligated party or exporter, 
regardless of the party's good faith belief that the RINs were valid at 
the time they were acquired.
    (2) Upon determination by any party that RINs owned are invalid, the 
party must adjust their records, reports, and compliance calculations as 
necessary to reflect the deletion of the invalid RINs.

[[Page 1031]]

    (3) Any valid RINs remaining after deleting invalid RINs must first 
be applied to correct the transfer of invalid RINs to another party 
before applying the valid RINs to meet the party's Renewable Volume 
Obligation at the end of the compliance year.
    (4) In the event that the same RIN is transferred to two or more 
parties, all such RINs will be deemed to be invalid, unless EPA in its 
sole discretion determines that some portion of these RINs is valid.

[72 FR 23995, May 1, 2007]



Sec. 80.1132  Reported spillage of renewable fuel.

    (a) A reported spillage under paragraph (d) of this section means a 
spillage of renewable fuel associated with a requirement by a federal, 
state or local authority to report the spillage.
    (b) Except as provided in paragraph (c) of this section, in the 
event of a reported spillage of any volume of renewable fuel, the owner 
of the renewable fuel must retire a number of gallon-RINs corresponding 
to the volume of spilled renewable fuel multiplied by its equivalence 
value.
    (1) If the equivalence value for the spilled volume may be 
determined pursuant to Sec. 80.1115 based on its composition, then the 
appropriate equivalence value shall be used.
    (2) If the equivalence value for a spilled volume of renewable fuel 
cannot be determined, the equivalence value shall be 1.0.
    (c) If the owner of a volume of renewable fuel that is spilled and 
reported establishes that no RINs were generated to represent the 
volume, then no gallon-RINs shall be retired.
    (d) A RIN that is retired under paragraph (b) of this section:
    (1) Must be reported as a retired RIN in the applicable reports 
under Sec. 80.1152.
    (2) May not be transferred to another party or used by any obligated 
party to demonstrate compliance with the party's Renewable Volume 
Obligation.

[72 FR 23995, May 1, 2007]



Sec. Sec. 80.1133-80.1140  [Reserved]



Sec. 80.1141  Small refinery exemption.

    (a)(1) Gasoline produced at a refinery by a refiner, or foreign 
refiner (as defined at Sec. 80.1165(a)), is exempt from the renewable 
fuel standards of Sec. 80.1105 if that refinery meets the definition of 
a small refinery under Sec. 80.1101(g) for calendar year 20460.
    (2) This exemption shall apply through December 31, 2010, unless a 
refiner chooses to waive this exemption (as described in paragraph (f) 
of this section), or the exemption is extended (as described in 
paragraph (e) of this section).
    (3) For the purposes of this section, the term ``refiner'' shall 
include foreign refiners.
    (b)(1) The small refinery exemption is effective immediately, except 
as specified in paragraph (b)(4) of this section.
    (2) A refiner owning a small refinery must submit a verification 
letter to EPA containing all of the following information:
    (i) The annual average aggregate daily crude oil throughput for the 
period January 1, 2004, through December 31, 2004 (as determined by 
dividing the aggregate throughput for the calendar year by the number 
365).
    (ii) A letter signed by the president, chief operating or chief 
executive officer of the company, or his/her designee, stating that the 
information contained in the letter is true to the best of his/her 
knowledge, and that the company owned the refinery as of January 1, 
2004.
    (iii) Name, address, phone number, facsimile number, and e-mail 
address of a corporate contact person.
    (3) Verification letters must be submitted by August 31, 2007, to 
one of the addresses listed in paragraph (h) of this section.
    (4) For foreign refiners the small refinery exemption shall be 
effective upon approval, by EPA, of a small refinery application. The 
application must contain all of the elements required for small refinery 
verification letters (as specified in paragraph (b)(2) of this section), 
must satisfy the provisions of Sec. 80.1165(f) through (h) and (o), and 
must be submitted by August 31, 2007 to one of the addresses listed in 
paragraph (h) of this section.
    (c) If EPA finds that a refiner provided false or inaccurate 
information regarding a refinery's crude throughput (pursuant to 
paragraph (b)(2)(i) of

[[Page 1032]]

this section) in its small refinery verification letter, the exemption 
will be void as of the effective date of these regulations.
    (d) If a refiner is complying on an aggregate basis for multiple 
refineries, any such refiner may exclude from the calculation of its 
Renewable Volume Obligation (under Sec. 80.1107(a)) gasoline from any 
refinery receiving the small refinery exemption under paragraph (a) of 
this section.
    (e)(1) The exemption period in paragraph (a) of this section shall 
be extended by the Administrator for a period of not less than two 
additional years if a study by the Secretary of Energy determines that 
compliance with the requirements of this subpart would impose a 
disproportionate economic hardship on the small refinery.
    (i) A refiner may at any time petition the Administrator for an 
extension of its small refinery exemption under paragraph (a) of this 
section for the reason of disproportionate economic hardship.
    (ii) A petition for an extension of the small refinery exemption 
must specify the factors that demonstrate a disproportionate economic 
hardship and must provide a detailed discussion regarding the inability 
of the refinery to produce gasoline meeting the requirements of Sec. 
80.1105 and the date the refiner anticipates that compliance with the 
requirements can be achieved at the small refinery.
    (2) The Administrator shall act on such a petition not later than 90 
days after the date of receipt of the petition.
    (f) At any time, a refiner with an approved small refinery exemption 
under paragraph (a) of this section may waive that exemption upon 
notification to EPA.
    (1) A refiner's notice to EPA that it intends to waive its small 
refinery exemption must be received by November 1 to be effective in the 
next compliance year.
    (2) The waiver will be effective beginning on January 1 of the 
following calendar year, at which point the gasoline produced at that 
refinery will be subject to the renewable fuels standard of Sec. 
80.1105.
    (3) The waiver must be sent to EPA at one of the addresses listed in 
paragraph (h) of this section.
    (g) A refiner that acquires a refinery from either an approved small 
refiner (as defined under Sec. 80.1142(a)) or another refiner with an 
approved small refinery exemption under paragraph (a) of this section 
shall notify EPA in writing no later than 20 days following the 
acquisition.
    (h) Verification letters under paragraph (b) of this section, 
petitions for small refinery hardship extensions under paragraph (e) of 
this section, and small refinery exemption waivers under paragraph (f) 
of this section shall be sent to one of the following addresses:
    (1) For U.S. mail: U.S. EPA--Attn: RFS Program, 6406J, 1200 
Pennsylvania Avenue, NW., Washington, DC 20460.
    (2) For overnight or courier services: U.S. EPA, Attn: RFS Program, 
6406J, 1310 L Street, NW., 6th floor, Washington, DC 20005.

[72 FR 23999, May 1, 2007]



Sec. 80.1142  What are the provisions for small refiners under
the RFS program?

    (a) (1) Gasoline produced by a refiner, or foreign refiner (as 
defined at Sec. 80.1165(a)), is exempt from the renewable fuel 
standards of Sec. 80.1105 if the refiner or foreign refiner does not 
meet the definition of a small refinery under Sec. 80.1101(g) but meets 
all of the following criteria:
    (i) The refiner produced gasoline at its refineries by processing 
crude oil through refinery processing units from January 1, 2004 through 
December 31, 2004.
    (ii) The refiner employed an average of no more than 1,500 people, 
based on the average number of employees for all pay periods for 
calendar year 2004 for all subsidiary companies, all parent companies, 
all subsidiaries of the parent companies, and all joint venture 
partners.
    (iii) The refiner had a corporate-average crude oil capacity less 
than or equal to 155,000 barrels per calendar day (bpcd) for 2004.
    (2) The small refiner exemption shall apply through December 31, 
2010, unless

[[Page 1033]]

a refiner chooses to waive the exemption (pursuant to paragraph (h) of 
this section) prior to that date.
    (3) For the purposes of this section, the term ``refiner'' shall 
include foreign refiners.
    (b) The small refiner exemption is effective immediately, except as 
provided in paragraph (d) of this section. Refiners who qualify for the 
small refiner exemption under paragraph (a) of this section must submit 
a verification letter (and any other relevant information) to EPA 
containing all of the following information for the refiner and for all 
subsidiary companies, all parent companies, all subsidiaries of the 
parent companies, and all joint venture partners:
    (1)(i) A listing of the name and address of each company location 
where any employee worked for the period January 1, 2004 through 
December 31, 2004.
    (ii) The average number of employees at each location based on the 
number of employees for each pay period for the period January 1, 2004 
through December 31, 2004.
    (iii) The type of business activities carried out at each location.
    (iv) For joint ventures, the total number of employees includes the 
combined employee count of all corporate entities in the venture.
    (v) For government-owned refiners, the total employee count includes 
all government employees.
    (2) The total corporate crude oil capacity of each refinery as 
reported to the Energy Information Administration (EIA) of the U.S. 
Department of Energy (DOE), for the period January 1, 2004 through 
December 31, 2004. The information submitted to EIA is presumed to be 
correct. In cases where a company disagrees with this information, the 
company may petition EPA with appropriate data to correct the record 
when the company submits its verification letter.
    (3) The verification letter must be signed by the president, chief 
operating or chief executive officer of the company, or his/her 
designee, stating that the information is true to the best of his/her 
knowledge, and that the company owned the refinery as of December 31, 
2004.
    (4) Name, address, phone number, facsimile number, and e-mail 
address of a corporate contact person.
    (c) Verification letters under paragraph (b) of this section must be 
submitted by September 1, 2007.
    (d) For foreign refiners the small refiner exemption shall be 
effective upon approval, by EPA, of a small refiner application. The 
application must contain all of the elements required for small refiner 
verification letters (as specified in paragraphs (b)(1), (b)(3), and 
(b)(4) of this section), must demonstrate compliance with the crude oil 
capacity criterion of paragraph (a)(1)(iii) of this section, must 
satisfy the provisions of Sec. 80.1165(f) through (h) and (o), and must 
be submitted by September 1, 2007 to one of the addresses listed in 
paragraph (j) of this section.
    (e) A refiner who qualifies as a small refiner under this section 
and subsequently fails to meet all of the qualifying criteria as set out 
in paragraph (a) of this section will have its small refiner exemption 
terminated effective January 1 of the next calendar year; however, 
disqualification shall not apply in the case of a merger between two 
approved small refiners.
    (f) If EPA finds that a refiner provided false or inaccurate 
information in its small refiner status verification letter under this 
subpart, the small refiner's exemption will be void as of the effective 
date of these regulations.
    (g) If a small refiner is complying on an aggregate basis for 
multiple refineries, the refiner may exempt the refineries from the 
calculation of its Renewable Volume Obligation under Sec. 80.1107.
    (h) (1) A refiner may, at any time, waive the small refiner 
exemption under paragraph (a) of this section upon notification to EPA.
    (2) A refiner's notice to EPA that it intends to waive the small 
refiner exemption must be received by November 1 in order for the waiver 
to be effective for the following calendar year. The waiver will be 
effective beginning on January 1 of the following calendar year, at 
which point the refiner will be subject to the renewable fuel standard 
of Sec. 80.1105.
    (3) The waiver must be sent to EPA at one of the addresses listed in 
paragraph (j) of this section.

[[Page 1034]]

    (i) Any refiner that acquires a refinery from another refiner with 
approved small refiner status under paragraph (a) of this section shall 
notify EPA in writing no later than 20 days following the acquisition.
    (j) Verification letters under paragraph (b) of this section and 
small refiner exemption waivers under paragraph (h) of this section 
shall be sent to one of the following addresses:
    (1) For U.S. Mail: U.S. EPA--Attn: RFS Program, 6406J, 1200 
Pennsylvania Avenue, NW., Washington, DC 20460.
    (2) For overnight or courier services: U.S. EPA, Attn: RFS Program, 
6406J, 1310 L Street, NW., 6th floor, Washington, DC 20005.

[72 FR 23999, May 1, 2007]



Sec. 80.1143  What are the opt-in provisions for noncontiguous 
states and territories?

    (a) A noncontiguous state or United States territory may petition 
the Administrator to opt-in to the program requirements of this subpart.
    (b) The Administrator will approve the petition if it meets the 
provisions of paragraphs (c) and (d) of this section.
    (c) The petition must be signed by the Governor of the state or his 
authorized representative (or the equivalent official of the territory).
    (d)(1) A petition submitted under this section must be received by 
the Agency by November 1 for the state or territory to be included in 
the RFS program in the next calendar year.
    (2) A petition submitted under this section should be sent to either 
of the following addresses:
    (i) For U.S. Mail: U.S. EPA--Attn: RFS Program, 6406J, 1200 
Pennsylvania Avenue, NW., Washington, DC 20460.
    (ii) For overnight or courier services: U.S. EPA, Attn: RFS Program, 
6406J, 1310 L Street, NW., 6th floor, Washington, DC 20005.
    (e) Upon approval of the petition by the Administrator:
    (1) EPA shall calculate the standard for the following year, 
including the total gasoline volume for the State or territory in 
question.
    (2) Beginning on January 1 of the next calendar year, all gasoline 
refiners and importers in the state or territory for which a petition 
has been approved shall be obligated parties as defined in Sec. 
80.1106.
    (3) Beginning on January 1 of the next calendar year, all renewable 
fuel producers in the State or territory for which a petition has been 
approved shall, pursuant to Sec. 80.1126(a)(2), be required to generate 
RINs and assign them to batches of renewable fuel.

[72 FR 23999, May 1, 2007]



Sec. Sec. 80.1144-80.1149  [Reserved]



Sec. 80.1150  What are the registration requirements under the RFS program?

    (a) Any obligated party described in Sec. 80.1106 and any exporter 
of renewable fuel described in Sec. 80.1130 must provide EPA with the 
information specified for registration under Sec. 80.76, if such 
information has not already been provided under the provisions of this 
part. An obligated party or an exporter of renewable fuel must receive 
EPA-issued identification numbers prior to engaging in any transaction 
involving RINs. Registration information may be submitted to EPA at any 
time after promulgation of this rule in the Federal Register.
    (b) Any importer or producer of a renewable fuel must provide EPA 
the information specified under Sec. 80.76, if such information has not 
already been provided under the provisions of this part, and must 
receive EPA-issued company and facility identification numbers prior to 
generating or assigning any RINs. Registration information may be 
submitted to EPA at any time after promulgation of this rule in the 
Federal Register.
    (c) Any party who owns or intends to own RINs, but who is not 
covered by paragraphs (a) and (b) of this section, must provide EPA the 
information specified under Sec. 80.76, if such information has not 
already been provided under the provisions of this part and must receive 
an EPA-issued company identification number prior to owning any RINs. 
Registration information may be submitted to EPA at any time after 
promulgation of this rule in the Federal Register.

[[Page 1035]]

    (d) Registration shall be on forms, and following policies, 
established by the Administrator.

[72 FR 24000, May 1, 2007]



Sec. 80.1151  What are the recordkeeping requirements under the RFS program?

    (a) Beginning September 1, 2007, any obligated party (as described 
at Sec. 80.1106) or exporter of renewable fuel (as described at Sec. 
80.1130) must keep all of the following records:
    (1) Product transfer documents consistent with Sec. 80.1153 and 
associated with the obligated party's activity, if any, as transferor or 
transferee of renewable fuel.
    (2) Copies of all reports submitted to EPA under Sec. 80.1152(a).
    (3) Records related to each RIN transaction, which includes all the 
following:
    (i) A list of the RINs owned, purchased, sold, retired or expired.
    (ii) The parties involved in each RIN transaction including the 
transferor, transferee, and any broker or agent.
    (iii) The date of the transfer of the RIN(s).
    (iv) Additional information related to details of the transaction 
and its terms.
    (4) Records related to the use of RINs (by facility, if applicable) 
for compliance, which includes all the following:
    (i) Methods and variables used to calculate the Renewable Volume 
Obligation pursuant to Sec. 80.1107 or Sec. 80.1130.
    (ii) List of RINs used to demonstrate compliance.
    (iii) Additional information related to details of RIN use for 
compliance.
    (b) Beginning September 1, 2007, any producer or importer of a 
renewable fuel as defined at Sec. 80.1101(d) must keep all of the 
following records:
    (1) Product transfer documents consistent with Sec. 80.1153 and 
associated with the renewable fuel producer's or importer's activity, if 
any, as transferor or transferee of renewable fuel.
    (2) Copies of all reports submitted to EPA under Sec. 80.1152(b).
    (3) Records related to the generation and assignment of RINs for 
each facility, including all of the following:
    (i) Batch volume in gallons.
    (ii) Batch number.
    (iii) RIN number as assigned under Sec. 80.1126.
    (iv) Identification of batches meeting the definition of cellulosic 
biomass ethanol.
    (v) Date of production or import.
    (vi) Results of any laboratory analysis of batch chemical 
composition or physical properties.
    (vii) Additional information related to details of RIN generation.
    (4) Records related to each RIN transaction, including all of the 
following:
    (i) A list of the RINs owned, purchased, sold, retired or expired.
    (ii) The parties involved in each transaction including the 
transferor, transferee, and any broker or agent.
    (iii) The date of the transfer of the RIN(s).
    (iv) Additional information related to details of the transaction 
and its terms.
    (5) Records related to the production or importation of any volume 
of renewable fuel that the renewable fuel producer or importer 
designates as motor vehicle fuel and the use of the fuel as motor 
vehicle fuel.
    (c) Beginning September 1, 2007, any producer of a renewable fuel 
defined at Sec. 80.1101(d) must keep verifiable records of the 
following:
    (1) The amount and type of fossil fuel and waste material-derived 
fuel used in producing on-site thermal energy dedicated to the 
production of ethanol at plants producing cellulosic biomass ethanol 
through the displacement of 90 percent or more of the fossil fuel 
normally used in the production of ethanol, as described at Sec. 
80.1101(a)(2).
    (2) The amount and type of feedstocks used in producing cellulosic 
biomass ethanol as defined in Sec. 80.1101(a)(1).
    (3) The equivalent amount of fossil fuel (based on reasonable 
estimates) associated with the use of off-site generated waste heat that 
is used in the production of ethanol at plants producing cellulosic 
biomass ethanol through the displacement of 90 percent or more of the 
fossil fuel normally used in the production of ethanol, as described at 
Sec. 80.1101(a)(2).
    (4) The plot plan and process flow diagram for plants producing 
cellulosic

[[Page 1036]]

biomass and waste derived ethanol as defined in Sec. 80.1101(a) and 
(b), respectively.
    (5) The independent third party verification required under Sec. 
80.1155 for producers of cellulosic biomass ethanol and waste derived 
ethanol.
    (d) Beginning September 1, 2007, any party, other than those parties 
covered in paragraphs (a) and (b) of this section, that owns RINs must 
keep all of the following records:
    (1) Product transfer documents consistent with Sec. 80.1153 and 
associated with the party's activity, if any, as transferor or 
transferee of renewable fuel.
    (2) Copies of all reports submitted to EPA under Sec. 80.1152(c).
    (3) Records related to each RIN transaction, including all of the 
following:
    (i) A list of the RINs owned, purchased, sold, retired or expired.
    (ii) The parties involved in each RIN transaction including the 
transferor, transferee, and any broker or agent.
    (iii) The date of the transfer of the RIN(s).
    (iv) Additional information related to details of the transaction 
and its terms.
    (e) The records required under this section and under Sec. 80.1153 
shall be kept for five years from the date they were created, except 
that records related to transactions involving RINs shall be kept for 
five years from the date of transfer.
    (f) On request by EPA, the records required under this section and 
under Sec. 80.1153 must be made available to the Administrator or the 
Administrator's authorized representative. For records that are 
electronically generated or maintained, the equipment or software 
necessary to read the records shall be made available; or, if requested 
by EPA, electronic records shall be converted to paper documents.

[72 FR 24000, May 1, 2007]



Sec. 80.1152  What are the reporting requirements under the RFS program?

    (a) Any obligated party described in Sec. 80.1106 or exporter of 
renewable fuel described in Sec. 80.1130 must submit to EPA reports 
according to the schedule, and containing the information, that is set 
forth in this paragraph (a).
    (1) An annual compliance demonstration report for the previous 
compliance period shall be submitted every February 28, except as noted 
in paragraph (a)(1)(x) of this section, and shall include all of the 
following information:
    (i) The obligated party's name.
    (ii) The EPA company registration number.
    (iii) Whether the party is complying on a corporate (aggregate) or 
facility-by-facility basis.
    (iv) The EPA facility registration number, if complying on a 
facility-by-facility basis.
    (v) The production volume of all of the products listed in Sec. 
80.1107(c) for the reporting year.
    (vi) The renewable volume obligation (RVO), as defined in Sec. 
80.1127(a) for obligated parties and Sec. 80.1130(b) for exporters of 
renewable fuel, for the reporting year.
    (vii) Any deficit RVO carried over from the previous year.
    (viii) The total current-year gallon-RINs used for compliance.
    (ix) The total prior-years gallon-RINs used for compliance.
    (x) A list of all RINs used for compliance in the reporting year. 
For compliance demonstrations covering calendar year 2007 only, this 
list shall be reported by May 31, 2008. In all subsequent years, this 
list shall be submitted by February 28.
    (xi) Any deficit RVO carried into the subsequent year.
    (xii) Any additional information that the Administrator may require.
    (2) The quarterly RIN transaction reports required under paragraph 
(c)(1) of this section.
    (3) The quarterly gallon-RIN activity reports required under 
paragraph (c)(2) of this section.
    (4) Reports required under this paragraph (a) must be signed and 
certified as meeting all the applicable requirements of this subpart by 
the owner or a responsible corporate officer of the obligated party.
    (b) Any producer or importer of a renewable fuel must, beginning 
November 30, 2007, submit to EPA reports according to the schedule, and 
containing

[[Page 1037]]

the information, that is set forth in this paragraph (b).
    (1) A quarterly RIN-generation report for each facility owned by the 
renewable fuel producer, and each importer, shall be submitted according 
to the schedule specified in paragraph (d) of this section, and shall 
include for the reporting period all of the following information for 
each batch of renewable fuel produced or imported, where ``batch'' means 
a discreet quantity of renewable fuel produced or imported and assigned 
a unique RIN:
    (i) The renewable fuel producer's or importer's name.
    (ii) The EPA company registration number.
    (iii) The EPA facility registration number.
    (iv) The applicable quarterly reporting period.
    (v) The RINs generated for each batch according to Sec. 80.1126.
    (vi) The production date of each batch.
    (vii) The type of renewable fuel of each batch, as defined in Sec. 
80.1101(d).
    (viii) Information related to the volume of denaturant and 
applicable equivalence value of each batch.
    (ix) The volume of each batch produced or imported.
    (x) Any additional information the Administrator may require.
    (2) The RIN transaction reports required under paragraph (c)(1) of 
this section.
    (3) The quarterly gallon-RIN activity report required under 
paragraph (c)(2) of this section.
    (4) Reports required under this paragraph (b) must be signed and 
certified as meeting all the applicable requirements of this subpart by 
the owner or a responsible corporate officer of the renewable fuel 
producer.
    (c) Any party, including any party specified in paragraphs (a) and 
(b) of this section, that owns RINs during a reporting period must, 
beginning November 30, 2007, submit reports to EPA according to the 
schedule, and containing the information, that is set forth in this 
paragraph (c).
    (1) A RIN transaction report for each RIN transaction shall be 
submitted by the end of the quarter in which the transaction occurred, 
according to the schedule specified in paragraph (d) of this section. 
Each report shall include all of the following:
    (i) The submitting party's name.
    (ii) The party's EPA company registration number.
    (iii) The party's facility registration number, if the report 
required under paragraph (c)(2) of this section is submitted on a 
facility-by-facility basis.
    (iv) The applicable quarterly reporting period.
    (v) Transaction type (RIN purchase, RIN sale, expired RIN, retired 
RIN).
    (vi) Transaction date.
    (vii) For a RIN purchase or sale, the trading partner's name.
    (viii) For a RIN purchase or sale, the trading partner's EPA company 
registration number. For all other transactions, the submitting party's 
EPA company registration number.
    (ix) RIN subject to the transaction.
    (x) For a retired RIN, the reason for retiring the RIN (e.g., 
reportable spill under Sec. 80.1132, import volume correction under 
Sec. 80.1166(k), renewable fuel used in boiler or heater under Sec. 
80.1129(e), enforcement obligation).
    (xi) Any additional information that the Administrator may require.
    (2) A quarterly gallon-RIN activity report shall be submitted to EPA 
according to the schedule specified in paragraph (d) of this section. 
Each report shall summarize gallon-RIN activities for the reporting 
period, separately for RINs separated from a renewable fuel volume and 
RINs assigned to a renewable fuel volume. A RIN owner with more than one 
facility may submit the report required under this paragraph for each of 
its facilities individually, or for all of its facilities in the 
aggregate. The quarterly gallon-RIN activity report shall include all of 
the following information:
    (i) The submitting party's name.
    (ii) The party's EPA company registration number.
    (iii) Whether the party is submitting the report required under this 
paragraph on a corporate (aggregate) or facility-by-facility basis.
    (iv) The party's EPA facility registration number, if the report 
required under this paragraph is submitted on a facility-by-facility 
basis.

[[Page 1038]]

    (v) Number of current-year gallon-RINs owned at the start of the 
quarter.
    (vi) Number of prior-years gallon-RINs owned at the start of the 
quarter.
    (vii) The total current-year gallon-RINs purchased.
    (viii) The total prior-years gallon-RINs purchased.
    (ix) The total current-year gallon-RINs sold.
    (x) The total prior-years gallon-RINs sold.
    (xi) The total current-year gallon-RINs retired.
    (xii) The total prior-years gallon-RINs retired.
    (xiii) The total current-year gallon-RINs expired (fourth quarter 
only).
    (xiv) The total prior-years gallon-RINs expired (fourth quarter 
only).
    (xv) Number of current-year gallon-RINs owned at the end of the 
quarter.
    (xvi) Number of prior-years gallon-RINs owned at the end of the 
quarter.
    (xvii) For parties reporting gallon-RIN activity under this 
paragraph for RINs assigned to a volume of renewable fuel, the volume of 
renewable fuel (in gallons) owned at the end of the quarter.
    (xviii) Any additional information that the Administrator may 
require.
    (3) All reports required under this paragraph (c) must be signed and 
certified as meeting all the applicable requirements of this subpart by 
the RIN owner or a responsible corporate officer of the RIN owner.
    (d) Quarterly reports shall be submitted to EPA by: May 31st for the 
first calendar quarter of January through March; August 31st for the 
second calendar quarter of April through June; November 30th for the 
third calendar quarter of July through September; and February 28th for 
the fourth calendar quarter of October through December. For 2007, 
quarterly reports shall commence on November 30, 2007.
    (e) Reports required under this section shall be submitted on forms 
and following procedures as prescribed by EPA.

[72 FR 24000, May 1, 2007]



Sec. 80.1153  What are the product transfer document (PTD)
requirements for the RFS program?

    (a) Any time that a person transfers ownership of renewable fuels 
subject to this subpart, the transferor must provide to the transferee 
documents identifying the renewable fuel and any assigned RINs which 
include all of the following information as applicable:
    (1) The name and address of the transferor and transferee.
    (2) The transferor's and transferee's EPA company registration 
number.
    (3) The volume of renewable fuel that is being transferred.
    (4) The date of the transfer.
    (5) Whether any RINs are assigned to the volume, as follows:
    (i) If the assigned RINs are being transferred on the same PTD used 
to transfer ownership of the renewable fuel, then the assigned RINs 
shall be listed on the PTD.
    (ii) If the assigned RINs are being transferred on a separate PTD 
from that which is used to transfer ownership of the renewable fuel, 
then the PTD which is used to transfer ownership of the renewable fuel 
shall state the number of gallon-RINs being transferred as well as a 
unique reference to the PTD which is transferring the assigned RINs.
    (iii) If no assigned RINs are being transferred with the renewable 
fuel, the PTD which is used to transfer ownership of the renewable fuel 
shall state ``No RINs transferred''.
    (b) Except for transfers to truck carriers, retailers, or wholesale 
purchaser-consumers, product codes may be used to convey the information 
required under paragraphs (a)(1) through (a)(4) of this section if such 
codes are clearly understood by each transferee. The RIN number required 
under paragraph (a)(5) of this section must always appear in its 
entirety.

[72 FR 24000, May 1, 2007]



Sec. 80.1154  What are the provisions for renewable fuel producers
and importers who produce or import less than 10,000 gallons of 

renewable fuel per year?

    (a) Renewable fuel producers located within the United States that 
produce less than 10,000 gallons of renewable

[[Page 1039]]

fuel each year, and importers who import less than 10,000 gallons of 
renewable fuel each year, are not required to generate RINs or to assign 
RINs to batches of renewable fuel. Such producers and importers that do 
not generate and/or assign RINs to batches of renewable fuel are also 
exempt from all the following requirements of this subpart K, except as 
stated in paragraph (b) of this section:
    (1) The registration requirements of Sec. 80.1150.
    (2) The recordkeeping requirements of Sec. 80.1151.
    (3) The reporting requirements of Sec. 80.1152.
    (b) Renewable fuel producers and importers who produce or import 
less than 10,000 gallons of renewable fuel each year and that generate 
and/or assign RINs to batches of renewable fuel are subject to the 
provisions of Sec. Sec. 80.1150 through 80.1152.

[72 FR 24000, May 1, 2007]



Sec. 80.1155  What are the additional requirements for a producer
of cellulosic biomass ethanol or waste derived ethanol?

    (a) A producer of cellulosic biomass ethanol or waste derived 
ethanol (hereinafter referred to as ``ethanol producer'' under this 
section) is required to arrange for an independent third party to review 
the records required in Sec. 80.1151(c) and provide the ethanol 
producer with a written verification that the records support a claim 
that:
    (1) The ethanol producer's facility is a facility that has the 
capability of producing cellulosic biomass ethanol as defined in Sec. 
80.1101(a) or waste derived ethanol as defined in Sec. 80.1101(b); and
    (2) The ethanol producer produces cellulosic biomass ethanol as 
defined in Sec. 80.1101(a) or waste derived ethanol as defined in Sec. 
80.1101(b).
    (b) The verifications required under paragraph (a) of this section 
must be conducted by a Professional Chemical Engineer who is based in 
the United States and is licensed by the appropriate state agency, 
unless the ethanol producer is a foreign producer subject to Sec. 
80.1166.
    (c) To be considered an independent third party under paragraph (a) 
of this section:
    (1) The third party shall not be operated by the ethanol producer or 
any subsidiary of employee of the ethanol producer.
    (2) The third party shall be free from any interest in the ethanol 
producer's business.
    (3) The ethanol producer shall be free from any interest in the 
third party's business.
    (4) Use of a third party that is debarred, suspended, or proposed 
for debarment pursuant to the Government-wide Debarment and Suspension 
regulations, 40 CFR part 32, or the Debarment, Suspension and 
Ineligibility provisions of the Federal Acquisition Regulations, 48 CFR, 
part 9, subpart 9.4, shall be deemed noncompliance with the requirements 
of this section.
    (d) The ethanol producer must obtain the written verification 
required under paragraph (a)(1) of this section by February 28 of the 
year following the first year in which the ethanol producer claims to be 
producing cellulosic biomass ethanol or waste derived ethanol.
    (e) The verification in paragraph (a)(2) of this section is required 
for each calendar year that the ethanol producer claims to be producing 
cellulosic biomass ethanol or waste derived ethanol. The ethanol 
producer must obtain the written verification required under paragraph 
(a)(2) of this section by February 28 for the previous calendar year.
    (f) The ethanol producer must retain records of the verifications 
required under paragraph (a) of this section, as required in Sec. 
80.1151(c)(5).
    (g) The independent third party shall retain all records pertaining 
to the verification required under this section for a period of five 
years from the date of creation and shall deliver such records to the 
Administrator upon request.

[72 FR 24000, May 1, 2007]



Sec. Sec. 80.1156-80.1159  [Reserved]



Sec. 80.1160  What acts are prohibited under the RFS program?

    (a) Renewable fuels producer or importer violation. Except as 
provided in

[[Page 1040]]

Sec. 80.1154, no person shall produce or import a renewable fuel 
without assigning the proper RIN value or identifying it by a RIN number 
as required under Sec. 80.1126.
    (b) RIN generation and transfer violations. No person shall do any 
of the following:
    (1) Improperly generate a RIN (i.e., generate a RIN for which the 
applicable renewable fuel volume was not produced).
    (2) Create or transfer to any person a RIN that is invalid under 
Sec. 80.1131.
    (3) Transfer to any person a RIN that is not properly identified as 
required under Sec. 80.1125.
    (4) Transfer to any person a RIN with a K code of 1 without 
transferring an appropriate volume of renewable fuel to the same person 
on the same day.
    (c) RIN use violations. No person shall do any of the following:
    (1) Fail to acquire sufficient RINs, or use invalid RINs, to meet 
the party's renewable fuel volume obligation under Sec. 80.1127.
    (2) Fail to acquire sufficient RINs to meet the party's renewable 
fuel volume obligation under Sec. 80.1130.
    (3) Use a validly generated RIN to meet the party's renewable fuel 
volume obligation under Sec. 80.1127, or separate and transfer a 
validly generated RIN, where the party ultimately uses the renewable 
fuel volume associated with the RIN in a heater or boiler.
    (d) RIN retention violation. No person shall retain RINs in 
violation of the requirements in Sec. 80.1128(a)(5).
    (e) Causing a violation. No person shall cause another person to 
commit an act in violation of any prohibited act under this section.

[72 FR 24003, May 1, 2007]



Sec. 80.1161  Who is liable for violations under the RFS program?

    (a) Persons liable for violations of prohibited acts. (1) Any person 
who violates a prohibition under Sec. 80.1160(a) through (d) is liable 
for the violation of that prohibition.
    (2) Any person who causes another person to violate a prohibition 
under Sec. 80.1160(a) through (d) is liable for a violation of Sec. 
80.1160(e).
    (b) Persons liable for failure to meet other provisions of this 
subpart. (1) Any person who fails to meet a requirement of any provision 
of this subpart is liable for a violation of that provision.
    (2) Any person who causes another person to fail to meet a 
requirement of any provision of this subpart is liable for causing a 
violation of that provision.
    (c) Parent corporation liability. Any parent corporation is liable 
for any violation of this subpart that is committed by any of its 
subsidiaries.
    (d) Joint venture liability. Each partner to a joint venture is 
jointly and severally liable for any violation of this subpart that is 
committed by the joint venture operation.

[72 FR 24003, May 1, 2007]



Sec. 80.1162  [Reserved]



Sec. 80.1163  What penalties apply under the RFS program?

    (a) Any person who is liable for a violation under Sec. 80.1161 is 
subject to a civil penalty of up to $32,500, as specified in sections 
205 and 211(d) of the Clean Air Act, for every day of each such 
violation and the amount of economic benefit or savings resulting from 
each violation.
    (b) Any person liable under Sec. 80.1161(a) for a violation of 
Sec. 80.1160(c) for failure to meet a renewable volume obligation, or 
Sec. 80.1160(e) for causing another party to fail to meet a renewable 
volume obligation, during any averaging period, is subject to a separate 
day of violation for each day in the averaging period.
    (c) Any person liable under Sec. 80.1161(b) for failure to meet, or 
causing a failure to meet, a requirement of any provision of this 
subpart is liable for a separate day of violation for each day such a 
requirement remains unfulfilled.

[72 FR 24004, May 1, 2007]



Sec. 80.1164  What are the attest engagement requirements under
the RFS program?

    The requirements regarding annual attest engagements in Sec. Sec. 
80.125 through 80.127, and 80.130, also apply to any attest engagement 
procedures required under this subpart. In addition to any other 
applicable attest engagement procedures, the following annual attest

[[Page 1041]]

engagement procedures are required under this subpart.
    (a) The following attest procedures shall be completed for any 
obligated party as stated in Sec. 80.1106(a) or exporter of renewable 
fuel that is subject to the renewable fuel standard under Sec. 80.1105:
    (1) Annual compliance demonstration report. (i) Obtain and read a 
copy of the annual compliance demonstration report required under Sec. 
80.1152(a)(1) which contains information regarding all the following:
    (A) The obligated party's volume of finished gasoline, reformulated 
gasoline blendstock for oxygenate blending (RBOB), and conventional 
gasoline blendstock that becomes finished conventional gasoline upon the 
addition of oxygenate (CBOB) produced or imported during the reporting 
year.
    (B) Renewable volume obligation (RVO).
    (C) RINs used for compliance.
    (ii) Obtain documentation of any volumes of renewable fuel used in 
gasoline during the reporting year; compute and report as a finding the 
volumes of renewable fuel represented in these documents.
    (iii) Compare the volumes of gasoline reported to EPA in the report 
required under Sec. 80.1152(a)(1) with the volumes, excluding any 
renewable fuel volumes, contained in the inventory reconciliation 
analysis under Sec. 80.133.
    (iii) Verify that the production volume information in the obligated 
party's annual summary report required under Sec. 80.1152(a)(1) agrees 
with the volume information, excluding any renewable fuel volumes, 
contained in the inventory reconciliation analysis under Sec. 80.133.
    (iv) Compute and report as a finding the obligated party's RVO, and 
any deficit RVO carried over from the previous year or carried into the 
subsequent year, and verify that the values agree with the values 
reported to EPA.
    (v) Obtain documentation for all RINs used for compliance during the 
year being reviewed; compute and report as a finding the RIN numbers and 
year of generation of RINs represented in these documents; and state 
whether this information agrees with the report to EPA.
    (2) RIN transaction reports. (i) Obtain and read copies of a 
representative sample of all RIN transaction reports required under 
Sec. 80.1152(a)(2) for the compliance year.
    (ii) Obtain contracts or other documents for the representative 
sample of RIN transactions; compute and report as a finding the 
transaction types, transaction dates, and RINs traded; and state whether 
the information agrees with the party's reports to EPA.
    (3) Gallon-RIN activity reports. (i) Obtain and read copies of all 
quarterly gallon-RIN activity reports required under Sec. 80.1152(a)(3) 
for the compliance year.
    (ii) Obtain documentation of total RINs (including current-year RINs 
and previous-year RINs) owned at the start of the quarter, purchased, 
used for compliance, sold, expired and retired during the quarter being 
reviewed, and owned at the end of the quarter; compute and report as a 
finding the total RINs owned at the start and end of the quarter, 
purchased, used for compliance, sold, expired and retired as represented 
in these documents; and state whether this information agrees with the 
party's reports to EPA.
    (b) The following attest procedures shall be completed for any 
renewable fuel producer or importer:
    (1) RIN-generation reports. (i) Obtain and read copies of the 
quarterly RIN generation reports required under Sec. 80.1152(b)(1) for 
the compliance year.
    (ii) Obtain production data for each renewable fuel batch produced 
during the year being reviewed; compute and report as a finding the RIN 
numbers, production dates, types, volumes of denaturant and applicable 
equivalence values, and production volumes for each batch; and state 
whether this information agrees with the party's reports to EPA.
    (iii) Verify that the proper number of RINs were generated and 
assigned for each batch of renewable fuel produced, as required under 
Sec. 80.1126.
    (iv) Obtain product transfer documents for each renewable fuel batch 
produced during the year being reviewed; report as a finding any product 
transfer document that did not include the RIN for the batch.

[[Page 1042]]

    (2) RIN transaction reports. (i) Obtain and read copies of a 
representative sample of the RIN transaction reports required under 
Sec. 80.1152(b)(2) for the compliance year.
    (ii) Obtain contracts or other documents for the representative 
sample of RIN transactions; compute and report as a finding the 
transaction types, transaction dates, and the RINs traded; and state 
whether this information agrees with the party's reports to EPA.
    (3) Gallon-RIN activity reports. (i) Obtain and read copies of the 
quarterly gallon-RIN activity reports required under Sec. 80.1152(b)(3) 
for the compliance year.
    (ii) Obtain documentation of total RINs (including current-year RINs 
and previous-year RINs) owned at the start of the quarter, purchased, 
sold, expired and retired during the quarter being reviewed, and owned 
at the end of the quarter; compute and report as a finding the total 
RINs owned at the start and end of the quarter, purchased, used for 
compliance, sold, expired and retired as represented in these documents; 
and state whether this information agrees with the party's reports to 
EPA.
    (c) The following attest procedures shall be completed for any party 
other than an obligated party or renewable fuel producer or importer 
that owns any RINs during a calendar year.
    (1) RIN transaction reports. (i) Obtain and read copies of a 
representative sample of the RIN transaction reports required under 
Sec. 80.1152(c)(1) for the compliance year.
    (ii) Obtain contracts or other documents for the representative 
sample of RIN transactions; compute and report as a finding the 
transaction types, transaction dates, and the RINs traded; and state 
whether this information agrees with the party's reports to EPA.
    (2) Gallon-RIN activity reports. (i) Obtain and read copies of the 
gallon-RIN activity reports required under Sec. 80.1152(c)(2) for the 
compliance year.
    (ii) Obtain documentation of total RINs (including current-year RINs 
and previous-year RINs) owned at the start of the quarter, purchased, 
sold, expired and retired during the quarter being reviewed, and owned 
at the end of the quarter; compute and report as a finding the total 
RINs owned at the start and end of the quarter, purchased, used for 
compliance, sold, expired and retired as represented in these documents; 
and state whether this information agrees with the party's reports to 
EPA.
    (d) The following submission dates apply to the attest engagements 
required under this section.
    (1) For each compliance year, each party subject to the attest 
engagement requirements under this section shall cause the reports 
required under this section to be submitted to EPA by May 31 of the year 
following the compliance year.
    (2) For the 2007 compliance year only, the attest engagement 
required under paragraph (a) of this section may be submitted to EPA 
with the attest engagement for the 2008 compliance year.

[72 FR 24004, May 1, 2007]



Sec. 80.1165  What are the additional requirements under this
subpart for a foreign small refiner?

    (a) Definitions. The following definitions apply for this subpart:
    (1) Foreign refinery is a refinery that is located outside the 
United States, the Commonwealth of Puerto Rico, the U.S. Virgin Islands, 
Guam, American Samoa, and the Commonwealth of the Northern Mariana 
Islands (collectively referred to in this section as ``the United 
States'').
    (2) Foreign refiner is a person that meets the definition of refiner 
under Sec. 80.2(i) for a foreign refinery.
    (3) RFS-FRGAS is gasoline produced at a foreign refinery that has 
received a small refinery exemption under Sec. 80.1141 or a small 
refiner exemption under Sec. 80.1142 that is imported into the United 
States.
    (4) Non-RFS-FRGAS is one of the following:
    (i) Gasoline produced at a foreign refinery that has received a 
small refinery exemption under Sec. 80.1141 or a small refiner 
exemption under Sec. 80.1142 that is not imported into the United 
States.
    (ii) Gasoline produced at a foreign refinery that has not received a 
small refinery exemption under Sec. 80.1141 or small refiner exemption 
under Sec. 80.1142.

[[Page 1043]]

    (5) A foreign small refiner is a foreign refiner that has received a 
small refinery exemption under Sec. 80.1141 for one or more of its 
refineries or a small refiner exemption under Sec. 80.1142.
    (b) General requirements for RFS-FRGAS foreign small refineries and 
small refiners.
    (1) A foreign small refiner must designate, at the time of 
production, each batch of gasoline produced at the foreign refinery that 
is exported for use in the United States as RFS-FRGAS; and
    (2) Meet all requirements that apply to refiners who have received a 
small refinery or small refiner exemption under this subpart.
    (c) Designation, foreign refiner certification, and product transfer 
documents. (1) Any foreign small refiner must designate each batch of 
RFS-FRGAS as such at the time the gasoline is produced.
    (2) On each occasion when RFS-FRGAS is loaded onto a vessel or other 
transportation mode for transport to the United States, the foreign 
refiner shall prepare a certification for each batch of RFS-FRGAS that 
meets all the following requirements:
    (i) The certification shall include the report of the independent 
third party under paragraph (d) of this section, and all the following 
additional information:
    (A) The name and EPA registration number of the refinery that 
produced the RFS-FRGAS.
    (B) [Reserved]
    (ii) The identification of the gasoline as RFS-FRGAS.
    (iii) The volume of RFS-FRGAS being transported, in gallons.
    (3) On each occasion when any person transfers custody or title to 
any RFS-FRGAS prior to its being imported into the United States, it 
must include all the following information as part of the product 
transfer document information:
    (i) Designation of the gasoline as RFS-FRGAS.
    (ii) The certification required under paragraph (c)(2) of this 
section.
    (d) Load port independent testing and refinery identification. (1) 
On each occasion that RFS-FRGAS is loaded onto a vessel for transport to 
the United States the foreign small refiner shall have an independent 
third party do all the following:
    (i) Inspect the vessel prior to loading and determine the volume of 
any tank bottoms.
    (ii) Determine the volume of RFS-FRGAS loaded onto the vessel 
(exclusive of any tank bottoms before loading).
    (iii) Obtain the EPA-assigned registration number of the foreign 
refinery.
    (iv) Determine the name and country of registration of the vessel 
used to transport the RFS-FRGAS to the United States.
    (v) Determine the date and time the vessel departs the port serving 
the foreign refinery.
    (vi) Review original documents that reflect movement and storage of 
the RFS-FRGAS from the foreign refinery to the load port, and from this 
review determine:
    (A) The refinery at which the RFS-FRGAS was produced; and
    (B) That the RFS-FRGAS remained segregated from Non-RFS-FRGAS and 
other RFS-FRGAS produced at a different refinery.
    (2) The independent third party shall submit a report to:
    (i) The foreign small refiner containing the information required 
under paragraph (d)(1) of this section, to accompany the product 
transfer documents for the vessel; and
    (ii) The Administrator containing the information required under 
paragraph (d)(1) of this section, within thirty days following the date 
of the independent third party's inspection. This report shall include a 
description of the method used to determine the identity of the refinery 
at which the gasoline was produced, assurance that the gasoline remained 
segregated as specified in paragraph (j)(1) of this section, and a 
description of the gasoline's movement and storage between production at 
the source refinery and vessel loading.
    (3) The independent third party must:
    (i) Be approved in advance by EPA, based on a demonstration of 
ability to perform the procedures required in this paragraph (d);
    (ii) Be independent under the criteria specified in Sec. 
80.65(f)(2)(iii); and

[[Page 1044]]

    (iii) Sign a commitment that contains the provisions specified in 
paragraph (f) of this section with regard to activities, facilities, and 
documents relevant to compliance with the requirements of this paragraph 
(d).
    (e) Comparison of load port and port of entry testing. (1)(i) Any 
small foreign small refiner and any United States importer of RFS-FRGAS 
shall compare the results from the load port testing under paragraph (d) 
of this section, with the port of entry testing as reported under 
paragraph (k) of this section, for the volume of gasoline, except as 
specified in paragraph (e)(1)(ii) of this section.
    (ii) Where a vessel transporting RFS-FRGAS off loads this gasoline 
at more than one United States port of entry, the requirements of 
paragraph (e)(1)(i) of this section do not apply at subsequent ports of 
entry if the United States importer obtains a certification from the 
vessel owner that the requirements of paragraph (e)(1)(i) of this 
section were met and that the vessel has not loaded any gasoline or 
blendstock between the first United States port of entry and the 
subsequent port of entry.
    (2) If the temperature-corrected volumes determined at the port of 
entry and at the load port differ by more than one percent, the United 
States importer and the foreign small refiner shall not treat the 
gasoline as RFS-FRGAS and the importer shall include the volume of 
gasoline in the importer's RFS compliance calculations.
    (f) Foreign refiner commitments. Any small foreign small refiner 
shall commit to and comply with the provisions contained in this 
paragraph (f) as a condition to being approved for a small refinery or 
small refiner exemption under this subpart.
    (1) Any United States Environmental Protection Agency inspector or 
auditor must be given full, complete and immediate access to conduct 
inspections and audits of the foreign refinery.
    (i) Inspections and audits may be either announced in advance by 
EPA, or unannounced.
    (ii) Access will be provided to any location where:
    (A) Gasoline is produced;
    (B) Documents related to refinery operations are kept; and
    (C) RFS-FRGAS is stored or transported between the foreign refinery 
and the United States, including storage tanks, vessels and pipelines.
    (iii) Inspections and audits may be by EPA employees or contractors 
to EPA.
    (iv) Any documents requested that are related to matters covered by 
inspections and audits must be provided to an EPA inspector or auditor 
on request.
    (v) Inspections and audits by EPA may include review and copying of 
any documents related to all the following:
    (A) The volume of RFS-FRGAS.
    (B) The proper classification of gasoline as being RFS-FRGAS or as 
not being RFS-FRGAS.
    (C) Transfers of title or custody to RFS-FRGAS.
    (D) Testing of RFS-FRGAS.
    (E) Work performed and reports prepared by independent third parties 
and by independent auditors under the requirements of this section, 
including work papers.
    (vi) Inspections and audits by EPA may include taking interviewing 
employees.
    (vii) Any employee of the foreign refiner must be made available for 
interview by the EPA inspector or auditor, on request, within a 
reasonable time period.
    (viii) English language translations of any documents must be 
provided to an EPA inspector or auditor, on request, within 10 working 
days.
    (ix) English language interpreters must be provided to accompany EPA 
inspectors and auditors, on request.
    (2) An agent for service of process located in the District of 
Columbia shall be named, and service on this agent constitutes service 
on the foreign refiner or any employee of the foreign refiner for any 
action by EPA or otherwise by the United States related to the 
requirements of this subpart.
    (3) The forum for any civil or criminal enforcement action related 
to the provisions of this section for violations of the Clean Air Act or 
regulations promulgated thereunder shall be governed by the Clean Air 
Act, including the EPA administrative forum where allowed under the 
Clean Air Act.
    (4) United States substantive and procedural laws shall apply to any 
civil

[[Page 1045]]

or criminal enforcement action against the foreign refiner or any 
employee of the foreign refiner related to the provisions of this 
section.
    (5) Submitting an application for a small refinery or small refiner 
exemption, or producing and exporting gasoline under such exemption, and 
all other actions to comply with the requirements of this subpart 
relating to such exemption constitute actions or activities covered by 
and within the meaning of the provisions of 28 U.S.C. 1605(a)(2), but 
solely with respect to actions instituted against the foreign refiner, 
its agents and employees in any court or other tribunal in the United 
States for conduct that violates the requirements applicable to the 
foreign refiner under this subpart, including conduct that violates the 
False Statements Accountability Act of 1996 (18 U.S.C. 1001) and section 
113(c)(2) of the Clean Air Act (42 U.S.C. 7413).
    (6) The foreign refiner, or its agents or employees, will not seek 
to detain or to impose civil or criminal remedies against EPA inspectors 
or auditors, whether EPA employees or EPA contractors, for actions 
performed within the scope of EPA employment related to the provisions 
of this section.
    (7) The commitment required by this paragraph (f) shall be signed by 
the owner or president of the foreign refiner business.
    (8) In any case where RFS-FRGAS produced at a foreign refinery is 
stored or transported by another company between the refinery and the 
vessel that transports the RFS-FRGAS to the United States, the foreign 
refiner shall obtain from each such other company a commitment that 
meets the requirements specified in paragraphs (f)(1) through (f)(7) of 
this section, and these commitments shall be included in the foreign 
refiner's application for a small refinery or small refiner exemption 
under this subpart.
    (g) Sovereign immunity. By submitting an application for a small 
refinery or small refiner exemption under this subpart, or by producing 
and exporting gasoline to the United States under such exemption, the 
foreign refiner, and its agents and employees, without exception, become 
subject to the full operation of the administrative and judicial 
enforcement powers and provisions of the United States without 
limitation based on sovereign immunity, with respect to actions 
instituted against the foreign refiner, its agents and employees in any 
court or other tribunal in the United States for conduct that violates 
the requirements applicable to the foreign refiner under this subpart, 
including conduct that violates the False Statements Accountability Act 
of 1996 (18 U.S.C. 1001) and section 113(c)(2) of the Clean Air Act (42 
U.S.C. 7413).
    (h) Bond posting. Any foreign refiner shall meet the requirements of 
this paragraph (h) as a condition to approval of a small foreign 
refinery or small foreign refiner exemption under this subpart.
    (1) The foreign refiner shall post a bond of the amount calculated 
using the following equation:

Bond = G * $0.01

Where:

Bond = amount of the bond in United States dollars.
G = the largest volume of gasoline produced at the foreign refinery and 
exported to the United States, in gallons, during a single calendar year 
among the most recent of the following calendar years, up to a maximum 
of five calendar years: The calendar year immediately preceding the date 
the refinery's application is submitted, the calendar year the 
application is submitted, and each succeeding calendar year.

    (2) Bonds shall be posted by:
    (i) Paying the amount of the bond to the Treasurer of the United 
States;
    (ii) Obtaining a bond in the proper amount from a third party surety 
agent that is payable to satisfy United States administrative or 
judicial judgments against the foreign refiner, provided EPA agrees in 
advance as to the third party and the nature of the surety agreement; or
    (iii) An alternative commitment that results in assets of an 
appropriate liquidity and value being readily available to the United 
States, provided EPA agrees in advance as to the alternative commitment.
    (3) Bonds posted under this paragraph (h) shall:
    (i) Be used to satisfy any judicial judgment that results from an 
administrative or judicial enforcement action

[[Page 1046]]

for conduct in violation of this subpart, including where such conduct 
violates the False Statements Accountability Act of 1996 (18 U.S.C. 
1001) and section 113(c)(2) of the Clean Air Act (42 U.S.C. 7413);
    (ii) Be provided by a corporate surety that is listed in the United 
States Department of Treasury Circular 570 ``Companies Holding 
Certificates of Authority as Acceptable Sureties on Federal Bonds''; and
    (iii) Include a commitment that the bond will remain in effect for 
at least five years following the end of latest annual reporting period 
that the foreign refiner produces gasoline pursuant to the requirements 
of this subpart.
    (4) On any occasion a foreign refiner bond is used to satisfy any 
judgment, the foreign refiner shall increase the bond to cover the 
amount used within 90 days of the date the bond is used.
    (5) If the bond amount for a foreign refiner increases, the foreign 
refiner shall increase the bond to cover the shortfall within 90 days of 
the date the bond amount changes. If the bond amount decreases, the 
foreign refiner may reduce the amount of the bond beginning 90 days 
after the date the bond amount changes.
    (i) English language reports. Any document submitted to EPA by a 
foreign refiner shall be in English language, or shall include an 
English language translation.
    (j) Prohibitions. (1) No person may combine RFS-FRGAS with any Non-
RFS-FRGAS, and no person may combine RFS-FRGAS with any RFS-FRGAS 
produced at a different refinery, until the importer has met all the 
requirements of paragraph (k) of this section.
    (2) No foreign refiner or other person may cause another person to 
commit an action prohibited in paragraph (j)(1) of this section, or that 
otherwise violates the requirements of this section.
    (k) United States importer requirements. Any United States importer 
of RFS-FRGAS shall meet the following requirements:
    (1) Each batch of imported RFS-FRGAS shall be classified by the 
importer as being RFS-FRGAS.
    (2) Gasoline shall be classified as RFS-FRGAS according to the 
designation by the foreign refiner if this designation is supported by 
product transfer documents prepared by the foreign refiner as required 
in paragraph (c) of this section. Additionally, the importer shall 
comply with all requirements of this subpart applicable to importers.
    (3) For each gasoline batch classified as RFS-FRGAS, any United 
States importer shall have an independent third party do all the 
following:
    (i) Determine the volume of gasoline in the vessel.
    (ii) Use the foreign refiner's RFS-FRGAS certification to determine 
the name and EPA-assigned registration number of the foreign refinery 
that produced the RFS-FRGAS.
    (iii) Determine the name and country of registration of the vessel 
used to transport the RFS-FRGAS to the United States.
    (iv) Determine the date and time the vessel arrives at the United 
States port of entry.
    (4) Any importer shall submit reports within 30 days following the 
date any vessel transporting RFS-FRGAS arrives at the United States port 
of entry to:
    (i) The Administrator containing the information determined under 
paragraph (k)(3) of this section; and
    (ii) The foreign refiner containing the information determined under 
paragraph (k)(3)(i) of this section, and including identification of the 
port at which the product was off loaded.
    (5) Any United States importer shall meet all other requirements of 
this subpart for any imported gasoline that is not classified as RFS-
FRGAS under paragraph (k)(2) of this section.
    (l) Truck imports of RFS-FRGAS produced at a foreign refinery. (1) 
Any refiner whose RFS-FRGAS is transported into the United States by 
truck may petition EPA to use alternative procedures to meet all the 
following requirements:
    (i) Certification under paragraph (c)(2) of this section.
    (ii) Load port and port of entry testing requirements under 
paragraphs (d) and (e) of this section.
    (iii) Importer testing requirements under paragraph (k)(3) of this 
section.

[[Page 1047]]

    (2) These alternative procedures must ensure RFS-FRGAS remains 
segregated from Non-RFS-FRGAS until it is imported into the United 
States. The petition will be evaluated based on whether it adequately 
addresses the following:
    (i) Provisions for monitoring pipeline shipments, if applicable, 
from the refinery, that ensure segregation of RFS-FRGAS from that 
refinery from all other gasoline.
    (ii) Contracts with any terminals and/or pipelines that receive and/
or transport RFS-FRGAS that prohibit the commingling of RFS-FRGAS with 
Non-RFS-FRGAS or RFS-FRGAS from other foreign refineries.
    (iii) Attest procedures to be conducted annually by an independent 
third party that review loading records and import documents based on 
volume reconciliation, or other criteria, to confirm that all RFS-FRGAS 
remains segregated throughout the distribution system.
    (3) The petition described in this section must be submitted to EPA 
along with the application for a small refinery or small refiner 
exemption under this subpart.
    (m) Additional attest requirements for importers of RFS-FRGAS. The 
following additional procedures shall be carried out by any importer of 
RFS-FRGAS as part of the attest engagement required for importers under 
this subpart K.
    (1) Obtain listings of all tenders of RFS-FRGAS. Agree the total 
volume of tenders from the listings to the gasoline inventory 
reconciliation analysis required in Sec. 80.133(b), and to the volumes 
determined by the third party under paragraph (d) of this section.
    (2) For each tender under paragraph (m)(1) of this section, where 
the gasoline is loaded onto a marine vessel, report as a finding the 
name and country of registration of each vessel, and the volumes of RFS-
FRGAS loaded onto each vessel.
    (3) Select a sample from the list of vessels identified in paragraph 
(m)(2) of this section used to transport RFS-FRGAS, in accordance with 
the guidelines in Sec. 80.127, and for each vessel selected perform the 
following:
    (i) Obtain the report of the independent third party, under 
paragraph (d) of this section.
    (A) Agree the information in these reports with regard to vessel 
identification and gasoline volume.
    (B) Identify, and report as a finding, each occasion the load port 
and port of entry volume results differ by more than the amount allowed 
in paragraph (e)(2) of this section, and determine whether all of the 
requirements of paragraph (e)(2) of this section have been met.
    (ii) Obtain the documents used by the independent third party to 
determine transportation and storage of the RFS-FRGAS from the refinery 
to the load port, under paragraph (d) of this section. Obtain tank 
activity records for any storage tank where the RFS-FRGAS is stored, and 
pipeline activity records for any pipeline used to transport the RFS-
FRGAS prior to being loaded onto the vessel. Use these records to 
determine whether the RFS-FRGAS was produced at the refinery that is the 
subject of the attest engagement, and whether the RFS-FRGAS was mixed 
with any Non-RFS-FRGAS or any RFS-FRGAS produced at a different 
refinery.
    (4) Select a sample from the list of vessels identified in paragraph 
(m)(2) of this section used to transport RFS-FRGAS, in accordance with 
the guidelines in Sec. 80.127, and for each vessel selected perform the 
following:
    (i) Obtain a commercial document of general circulation that lists 
vessel arrivals and departures, and that includes the port and date of 
departure of the vessel, and the port of entry and date of arrival of 
the vessel.
    (ii) Agree the vessel's departure and arrival locations and dates 
from the independent third party and United States importer reports to 
the information contained in the commercial document.
    (5) Obtain separate listings of all tenders of RFS-FRGAS, and 
perform the following:
    (i) Agree the volume of tenders from the listings to the gasoline 
inventory reconciliation analysis in Sec. 80.133(b).
    (ii) Obtain a separate listing of the tenders under this paragraph 
(m)(5)

[[Page 1048]]

where the gasoline is loaded onto a marine vessel. Select a sample from 
this listing in accordance with the guidelines in Sec. 80.127, and 
obtain a commercial document of general circulation that lists vessel 
arrivals and departures, and that includes the port and date of 
departure and the ports and dates where the gasoline was off loaded for 
the selected vessels. Determine and report as a finding the country 
where the gasoline was off loaded for each vessel selected.
    (6) In order to complete the requirements of this paragraph (m), an 
auditor shall:
    (i) Be independent of the foreign refiner or importer;
    (ii) Be licensed as a Certified Public Accountant in the United 
States and a citizen of the United States, or be approved in advance by 
EPA based on a demonstration of ability to perform the procedures 
required in Sec. Sec. 80.125 through 80.127, 80.130, 80.1164, and this 
paragraph (m); and
    (iii) Sign a commitment that contains the provisions specified in 
paragraph (f) of this section with regard to activities and documents 
relevant to compliance with the requirements of Sec. Sec. 80.125 
through 80.127, 80.130, 80.1164, and this paragraph (m).
    (n) Withdrawal or suspension of foreign refiner status. EPA may 
withdraw or suspend a foreign refiner's small refinery or small refiner 
exemption where:
    (1) A foreign refiner fails to meet any requirement of this section;
    (2) A foreign government fails to allow EPA inspections as provided 
in paragraph (f)(1) of this section;
    (3) A foreign refiner asserts a claim of, or a right to claim, 
sovereign immunity in an action to enforce the requirements in this 
subpart; or
    (4) A foreign refiner fails to pay a civil or criminal penalty that 
is not satisfied using the foreign refiner bond specified in paragraph 
(h) of this section.
    (o) Additional requirements for applications, reports and 
certificates. Any application for a small refinery or small refiner 
exemption, alternative procedures under paragraph (l) of this section, 
any report, certification, or other submission required under this 
section shall be:
    (1) Submitted in accordance with procedures specified by the 
Administrator, including use of any forms that may be specified by the 
Administrator.
    (2) Be signed by the president or owner of the foreign refiner 
company, or by that person's immediate designee, and shall contain the 
following declaration:

    I hereby certify: (1) That I have actual authority to sign on behalf 
of and to bind [NAME OF FOREIGN REFINER] with regard to all statements 
contained herein; (2) that I am aware that the information contained 
herein is being Certified, or submitted to the United States 
Environmental Protection Agency, under the requirements of 40 CFR part 
80, subpart K, and that the information is material for determining 
compliance under these regulations; and (3) that I have read and 
understand the information being Certified or submitted, and this 
information is true, complete and correct to the best of my knowledge 
and belief after I have taken reasonable and appropriate steps to verify 
the accuracy thereof. I affirm that I have read and understand the 
provisions of 40 CFR part 80, subpart K, including 40 CFR 80.1165 apply 
to [NAME OF FOREIGN REFINER]. Pursuant to Clean Air Act section 113(c) 
and 18 U.S.C. 1001, the penalty for furnishing false, incomplete or 
misleading information in this certification or submission is a fine of 
up to $10,000 U.S., and/or imprisonment for up to five years.''

[72 FR 24004, May 1, 2007]



Sec. 80.1166  What are the additional requirements under this 
subpart for a foreign producer of cellulosic biomass ethanol

or waste derived ethanol?

    (a) Foreign producer of cellulosic biomass ethanol or waste derived 
ethanol. For purposes of this subpart, a foreign producer of cellulosic 
biomass ethanol or waste derived ethanol is a person located outside the 
United States, the Commonwealth of Puerto Rico, the Virgin Islands, 
Guam, American Samoa, and the Commonwealth of the Northern Mariana 
Islands (collectively referred to in this section as ''the United 
States'') that has been approved by EPA to assign RINs to cellulosic 
biomass ethanol or waste derived ethanol that the foreign producer 
produces and exports to the United States, hereinafter referred to as a 
``foreign producer'' under this section.

[[Page 1049]]

    (b) General requirements. (1) An approved foreign producer under 
this section must meet all requirements that apply to cellulosic biomass 
ethanol or waste derived ethanol producers under this subpart, except to 
the extent otherwise specified in paragraph (b)(2) of this section.
    (2)(i) The independent third party that conducts the facility 
verification required under Sec. 80.1155(a) must inspect the foreign 
producer's facility and submit a report to EPA which describes in detail 
the physical plant and its operation.
    (ii) The independent third party that conducts the facility 
verification required under Sec. 80.1155(a) must be a licensed 
Professional Engineer in the chemical engineering field, but need not be 
based in the United States. The independent third party must include 
documentation of its qualifications as a licensed Professional Engineer 
in the report required in paragraph (b)(2)(i) of this section.
    (iii) The requirements of paragraphs (b)(2)(i) and (ii) of this 
section must be met before a foreign entity may be approved as a foreign 
producer under this subpart.
    (c) Designation, foreign producer certification, and product 
transfer documents.
    (1) Any approved foreign producer under this section must designate 
each batch of cellulosic biomass ethanol or waste derived ethanol as 
``RFS-FRETH'' at the time the ethanol is produced.
    (2) On each occasion when RFS-FRETH is loaded onto a vessel or other 
transportation mode for transport to the United States, the foreign 
producer shall prepare a certification for each batch of RFS-FRETH; the 
certification shall include the report of the independent third party 
under paragraph (d) of this section, and all the following additional 
information:
    (i) The name and EPA registration number of the company that 
produced the RFS-FRETH.
    (ii) The identification of the ethanol as RFS-FRETH.
    (iii) The volume of RFS-FRETH being transported, in gallons.
    (3) On each occasion when any person transfers custody or title to 
any RFS-FRETH prior to its being imported into the United States, it 
must include all the following information as part of the product 
transfer document information:
    (i) Designation of the ethanol as RFS-FRETH.
    (ii) The certification required under paragraph (c)(2) of this 
section.
    (d) Load port independent testing and refinery identification. (1) 
On each occasion that RFS-FRETH is loaded onto a vessel for transport to 
the United States the foreign producer shall have an independent third 
party do all the following:
    (i) Inspect the vessel prior to loading and determine the volume of 
any tank bottoms.
    (ii) Determine the volume of RFS-FRETH loaded onto the vessel 
(exclusive of any tank bottoms before loading).
    (iii) Obtain the EPA-assigned registration number of the foreign 
producer.
    (iv) Determine the name and country of registration of the vessel 
used to transport the RFS-FRETH to the United States.
    (v) Determine the date and time the vessel departs the port serving 
the foreign producer.
    (vi) Review original documents that reflect movement and storage of 
the RFS-FRETH from the foreign producer to the load port, and from this 
review determine the following:
    (A) The facility at which the RFS-FRETH was produced.
    (B) That the RFS-FRETH remained segregated from Non-RFS-FRETH and 
other RFS-FRETH produced by a different foreign producer.
    (2) The independent third party shall submit a report to the 
following:
    (i) The foreign producer containing the information required under 
paragraph (d)(1) of this section, to accompany the product transfer 
documents for the vessel.
    (ii) The Administrator containing the information required under 
paragraph (d)(1) of this section, within thirty days following the date 
of the independent third party's inspection. This report shall include a 
description of the method used to determine the identity of the foreign 
producer facility at which

[[Page 1050]]

the ethanol was produced, assurance that the ethanol remained segregated 
as specified in paragraph (j)(1) of this section, and a description of 
the ethanol's movement and storage between production at the source 
facility and vessel loading.
    (3) The independent third party must:
    (i) Be approved in advance by EPA, based on a demonstration of 
ability to perform the procedures required in this paragraph (d);
    (ii) Be independent under the criteria specified in Sec. 
80.65(e)(2)(iii); and
    (iii) Sign a commitment that contains the provisions specified in 
paragraph (f) of this section with regard to activities, facilities and 
documents relevant to compliance with the requirements of this paragraph 
(d).
    (e) Comparison of load port and port of entry testing. (1)(i) Any 
foreign producer and any United States importer of RFS-FRETH shall 
compare the results from the load port testing under paragraph (d) of 
this section, with the port of entry testing as reported under paragraph 
(k) of this section, for the volume of ethanol, except as specified in 
paragraph (e)(1)(ii) of this section.
    (ii) Where a vessel transporting RFS-FRETH off loads the ethanol at 
more than one United States port of entry, the requirements of paragraph 
(e)(1)(i) of this section do not apply at subsequent ports of entry if 
the United States importer obtains a certification from the vessel owner 
that the requirements of paragraph (e)(1)(i) of this section were met 
and that the vessel has not loaded any ethanol between the first United 
States port of entry and the subsequent port of entry.
    (2)(i) If the temperature-corrected volumes determined at the port 
of entry and at the load port differ by more than one percent, the 
number of RINs associated with the ethanol shall be calculated based on 
the lesser of the two volumes in paragraph (e)(1)(i) of this section.
    (ii) Where the port of entry volume is the lesser of the two volumes 
in paragraph (e)(1)(i) of this section, the importer shall calculate the 
difference between the number of RINs originally assigned by the foreign 
producer and the number of RINs calculated under Sec. 80.1126 for the 
volume of ethanol as measured at the port of entry, and retire that 
amount of RINs in accordance with paragraph (k)(4) of this section.
    (f) Foreign producer commitments. Any foreign producer shall commit 
to and comply with the provisions contained in this paragraph (f) as a 
condition to being approved as a foreign producer under this subpart.
    (1) Any United States Environmental Protection Agency inspector or 
auditor must be given full, complete and immediate access to conduct 
inspections and audits of the foreign producer facility.
    (i) Inspections and audits may be either announced in advance by 
EPA, or unannounced.
    (ii) Access will be provided to any location where:
    (A) Ethanol is produced;
    (B) Documents related to ethanol producer operations are kept; and
    (C) RFS-FRETH is stored or transported between the foreign producer 
and the United States, including storage tanks, vessels and pipelines.
    (iii) Inspections and audits may be by EPA employees or contractors 
to EPA.
    (iv) Any documents requested that are related to matters covered by 
inspections and audits must be provided to an EPA inspector or auditor 
on request.
    (v) Inspections and audits by EPA may include review and copying of 
any documents related to the following:
    (A) The volume of RFS-FRETH.
    (B) The proper classification of gasoline as being RFS-FRETH;
    (C) Transfers of title or custody to RFS-FRETH.
    (D) Work performed and reports prepared by independent third parties 
and by independent auditors under the requirements of this section, 
including work papers.
    (vi) Inspections and audits by EPA may include interviewing 
employees.
    (vii) Any employee of the foreign producer must be made available 
for interview by the EPA inspector or auditor, on request, within a 
reasonable time period.
    (viii) English language translations of any documents must be 
provided to an EPA inspector or auditor, on request, within 10 working 
days.

[[Page 1051]]

    (ix) English language interpreters must be provided to accompany EPA 
inspectors and auditors, on request.
    (2) An agent for service of process located in the District of 
Columbia shall be named, and service on this agent constitutes service 
on the foreign producer or any employee of the foreign producer for any 
action by EPA or otherwise by the United States related to the 
requirements of this subpart.
    (3) The forum for any civil or criminal enforcement action related 
to the provisions of this section for violations of the Clean Air Act or 
regulations promulgated thereunder shall be governed by the Clean Air 
Act, including the EPA administrative forum where allowed under the 
Clean Air Act.
    (4) United States substantive and procedural laws shall apply to any 
civil or criminal enforcement action against the foreign producer or any 
employee of the foreign producer related to the provisions of this 
section.
    (5) Applying to be an approved foreign producer under this section, 
or producing or exporting ethanol under such approval, and all other 
actions to comply with the requirements of this subpart relating to such 
approval constitute actions or activities covered by and within the 
meaning of the provisions of 28 U.S.C. 1605(a)(2), but solely with 
respect to actions instituted against the foreign producer, its agents 
and employees in any court or other tribunal in the United States for 
conduct that violates the requirements applicable to the foreign 
producer under this subpart, including conduct that violates the False 
Statements Accountability Act of 1996 (18 U.S.C. 1001) and section 
113(c)(2) of the Clean Air Act (42 U.S.C. 7413).
    (6) The foreign producer, or its agents or employees, will not seek 
to detain or to impose civil or criminal remedies against EPA inspectors 
or auditors, whether EPA employees or EPA contractors, for actions 
performed within the scope of EPA employment related to the provisions 
of this section.
    (7) The commitment required by this paragraph (f) shall be signed by 
the owner or president of the foreign producer company.
    (8) In any case where RFS-FRETH produced at a foreign producer 
facility is stored or transported by another company between the 
refinery and the vessel that transports the RFS-FRETH to the United 
States, the foreign producer shall obtain from each such other company a 
commitment that meets the requirements specified in paragraphs (f)(1) 
through (7) of this section, and these commitments shall be included in 
the foreign producer's application to be an approved foreign producer 
under this subpart.
    (g) Sovereign immunity. By submitting an application to be an 
approved foreign producer under this subpart, or by producing and 
exporting ethanol to the United States under such approval, the foreign 
producer, and its agents and employees, without exception, become 
subject to the full operation of the administrative and judicial 
enforcement powers and provisions of the United States without 
limitation based on sovereign immunity, with respect to actions 
instituted against the foreign producer, its agents and employees in any 
court or other tribunal in the United States for conduct that violates 
the requirements applicable to the foreign producer under this subpart, 
including conduct that violates the False Statements Accountability Act 
of 1996 (18 U.S.C. 1001) and section 113(c)(2) of the Clean Air Act (42 
U.S.C. 7413).
    (h) Bond posting. Any foreign producer shall meet the requirements 
of this paragraph (h) as a condition to approval as a foreign producer 
under this subpart.
    (1) The foreign producer shall post a bond of the amount calculated 
using the following equation:

Bond = G * $ 0.01

Where:

Bond = amount of the bond in U.S. dollars.
G = The largest volume of ethanol produced at the foreign producer's 
facility and exported to the United States, in gallons, during a single 
calendar year among the most recent of the following calendar years, up 
to a maximum of five calendar years: The calendar year immediately 
preceding the date the refinery's application is submitted, the calendar 
year the application is submitted, and each succeeding calendar year.

    (2) Bonds shall be posted by any of the following methods:

[[Page 1052]]

    (i) Paying the amount of the bond to the Treasurer of the United 
States.
    (ii) Obtaining a bond in the proper amount from a third party surety 
agent that is payable to satisfy United States administrative or 
judicial judgments against the foreign producer, provided EPA agrees in 
advance as to the third party and the nature of the surety agreement.
    (iii) An alternative commitment that results in assets of an 
appropriate liquidity and value being readily available to the United 
States provided EPA agrees in advance as to the alternative commitment.
    (3) Bonds posted under this paragraph (h) shall:
    (i) Be used to satisfy any judicial judgment that results from an 
administrative or judicial enforcement action for conduct in violation 
of this subpart, including where such conduct violates the False 
Statements Accountability Act of 1996 (18 U.S.C. 1001) and section 
113(c)(2) of the Clean Air Act (42 U.S.C. 7413);
    (ii) Be provided by a corporate surety that is listed in the United 
States Department of Treasury Circular 570 ''Companies Holding 
Certificates of Authority as Acceptable Sureties on Federal Bonds''; and
    (iii) Include a commitment that the bond will remain in effect for 
at least five years following the end of the latest annual reporting 
period that the foreign producer produces ethanol pursuant to the 
requirements of this subpart.
    (4) On any occasion a foreign producer bond is used to satisfy any 
judgment, the foreign producer shall increase the bond to cover the 
amount used within 90 days of the date the bond is used.
    (5) If the bond amount for a foreign producer increases, the foreign 
producer shall increase the bond to cover the shortfall within 90 days 
of the date the bond amount changes. If the bond amount decreases, the 
foreign refiner may reduce the amount of the bond beginning 90 days 
after the date the bond amount changes.
    (i) English language reports. Any document submitted to EPA by a 
foreign producer shall be in English language, or shall include an 
English language translation.
    (j) Prohibitions. (1) No person may combine RFS-FRETH with any Non-
RFS-FRETH, and no person may combine RFS-FRETH with any RFS-FRETH 
produced at a different refinery, until the importer has met all the 
requirements of paragraph (k) of this section.
    (2) No foreign producer or other person may cause another person to 
commit an action prohibited in paragraph (j)(1) of this section, or that 
otherwise violates the requirements of this section.
    (k) Requirements for United States importers of RFS-FRETH. Any 
United States importer shall meet the following requirements:
    (1) Each batch of imported RFS-FRETH shall be classified by the 
importer as being RFS-FRETH.
    (2) Ethanol shall be classified as RFS-FRETH according to the 
designation by the foreign producer if this designation is supported by 
product transfer documents prepared by the foreign producer as required 
in paragraph (c) of this section.
    (3) For each ethanol batch classified as RFS-FRETH, any United 
States importer shall have an independent third party do all the 
following:
    (i) Determine the volume of gasoline in the vessel.
    (ii) Use the foreign producer's RFS-FRETH certification to determine 
the name and EPA-assigned registration number of the foreign producer 
that produced the RFS-FRETH.
    (iii) Determine the name and country of registration of the vessel 
used to transport the RFS-FRETH to the United States.
    (iv) Determine the date and time the vessel arrives at the United 
States port of entry.
    (4) Where the importer is required to retire RINs under paragraph 
(e)(2) of this section, the importer must report the retired RINs in the 
applicable reports under Sec. 80.1152.
    (5) Any importer shall submit reports within 30 days following the 
date any vessel transporting RFS-FRETH arrives at the United States port 
of entry to the following:

[[Page 1053]]

    (i) The Administrator containing the information determined under 
paragraph (k)(3) of this section.
    (ii) The foreign producer containing the information determined 
under paragraph (k)(3)(i) of this section, and including identification 
of the port at which the product was off loaded, and any RINs retired 
under paragraph (e)(2) of this section.
    (6) Any United States importer shall meet all other requirements of 
this subpart for any imported ethanol or other renewable fuel that is 
not classified as RFS-FRETH under paragraph (k)(2) of this section.
    (l) Truck imports of RFS-FRETH produced by a foreign producer. (1) 
Any foreign producer whose RFS-FRETH is transported into the United 
States by truck may petition EPA to use alternative procedures to meet 
all the following requirements:
    (i) Certification under paragraph (c)(2) of this section.
    (ii) Load port and port of entry testing under paragraphs (d) and 
(e) of this section.
    (iii) Importer testing under paragraph (k)(3) of this section.
    (2) These alternative procedures must ensure RFS-FRETH remains 
segregated from Non-RFS-FRETH until it is imported into the United 
States. The petition will be evaluated based on whether it adequately 
addresses the following:
    (i) Contracts with any facilities that receive and/or transport RFS-
FRETH that prohibit the commingling of RFS-FRETH with Non-RFS-FRETH or 
RFS-FRETH from other foreign producers.
    (ii) Attest procedures to be conducted annually by an independent 
third party that review loading records and import documents based on 
volume reconciliation to confirm that all RFS-FRETH remains segregated.
    (3) The petition described in this section must be submitted to EPA 
along with the application for approval as a foreign producer under this 
subpart.
    (m) Additional attest requirements for producers of RFS-FRETH. The 
following additional procedures shall be carried out by any producer of 
RFS-FRETH as part of the attest engagement required for renewable fuel 
producers under this subpart K.
    (1) Obtain listings of all tenders of RFS-FRETH. Agree the total 
volume of tenders from the listings to the volumes determined by the 
third party under paragraph (d) of this section.
    (2) For each tender under paragraph (m)(1) of this section, where 
the ethanol is loaded onto a marine vessel, report as a finding the name 
and country of registration of each vessel, and the volumes of RFS-FRETH 
loaded onto each vessel.
    (3) Select a sample from the list of vessels identified in paragraph 
(m)(2) of this section used to transport RFS-FRETH, in accordance with 
the guidelines in Sec. 80.127, and for each vessel selected perform the 
following:
    (i) Obtain the report of the independent third party, under 
paragraph (d) of this section, and of the United States importer under 
paragraph (k) of this section.
    (A) Agree the information in these reports with regard to vessel 
identification and ethanol volume.
    (B) Identify, and report as a finding, each occasion the load port 
and port of entry volume results differ by more than the amount allowed 
in paragraph (e) of this section, and determine whether the importer 
retired the appropriate amount of RINs as required under paragraph 
(e)(2) of this section, and submitted the applicable reports under Sec. 
80.1152 in accordance with paragraph (k)(4) of this section.
    (ii) Obtain the documents used by the independent third party to 
determine transportation and storage of the RFS-FRETH from the foreign 
producer's facility to the load port, under paragraph (d) of this 
section. Obtain tank activity records for any storage tank where the 
RFS-FRETH is stored, and activity records for any mode of transportation 
used to transport the RFS-FRGAS prior to being loaded onto the vessel. 
Use these records to determine whether the RFS-FRETH was produced at the 
foreign producer's facility that is the subject of the attest 
engagement, and whether the RFS-FRETH was mixed with any Non-RFS-FRETH 
or any RFS-FRETH produced at a different facility.

[[Page 1054]]

    (4) Select a sample from the list of vessels identified in paragraph 
(m)(2) of this section used to transport RFS-FRETH, in accordance with 
the guidelines in Sec. 80.127, and for each vessel selected perform the 
following:
    (i) Obtain a commercial document of general circulation that lists 
vessel arrivals and departures, and that includes the port and date of 
departure of the vessel, and the port of entry and date of arrival of 
the vessel.
    (ii) Agree the vessel's departure and arrival locations and dates 
from the independent third party and United States importer reports to 
the information contained in the commercial document.
    (5) Obtain a separate listing of the tenders under this paragraph 
(m)(5) where the gasoline is loaded onto a marine vessel. Select a 
sample from this listing in accordance with the guidelines in Sec. 
80.127, and obtain a commercial document of general circulation that 
lists vessel arrivals and departures, and that includes the port and 
date of departure and the ports and dates where the ethanol was off 
loaded for the selected vessels. Determine and report as a finding the 
country where the ethanol was off loaded for each vessel selected.
    (6) In order to complete the requirements of this paragraph (m) an 
auditor shall:
    (i) Be independent of the foreign producer;
    (ii) Be licensed as a Certified Public Accountant in the United 
States and a citizen of the United States, or be approved in advance by 
EPA based on a demonstration of ability to perform the procedures 
required in Sec. Sec. 80.125 through 80.127, 80.130, 80.1164, and this 
paragraph (m); and
    (iii) Sign a commitment that contains the provisions specified in 
paragraph (f) of this section with regard to activities and documents 
relevant to compliance with the requirements of Sec. Sec. 80.125 
through 80.127, 80.130, 80.1164, and this paragraph (m).
    (n) Withdrawal or suspension of foreign producer approval. EPA may 
withdraw or suspend a foreign producer's approval where any of the 
following occur:
    (1) A foreign producer fails to meet any requirement of this 
section.
    (2) A foreign government fails to allow EPA inspections as provided 
in paragraph (f)(1) of this section.
    (3) A foreign producer asserts a claim of, or a right to claim, 
sovereign immunity in an action to enforce the requirements in this 
subpart.
    (4) A foreign producer fails to pay a civil or criminal penalty that 
is not satisfied using the foreign producer bond specified in paragraph 
(g) of this section.
    (o) Additional requirements for applications, reports and 
certificates. Any application for approval as a foreign producer, 
alternative procedures under paragraph (l) of this section, any report, 
certification, or other submission required under this section shall be:
    (1) Submitted in accordance with procedures specified by the 
Administrator, including use of any forms that may be specified by the 
Administrator.
    (2) Signed by the president or owner of the foreign producer 
company, or by that person's immediate designee, and shall contain the 
following declaration:

    I hereby certify: (1) That I have actual authority to sign on behalf 
of and to bind [insert name of foreign producer] with regard to all 
statements contained herein; (2) that I am aware that the information 
contained herein is being Certified, or submitted to the United States 
Environmental Protection Agency, under the requirements of 40 CFR part 
80, subpart K, and that the information is material for determining 
compliance under these regulations; and (3) that I have read and 
understand the information being Certified or submitted, and this 
information is true, complete and correct to the best of my knowledge 
and belief after I have taken reasonable and appropriate steps to verify 
the accuracy thereof. I affirm that I have read and understand the 
provisions of 40 CFR part 80, subpart K, including 40 CFR 80.1165 apply 
to [insert name of foreign producer]. Pursuant to Clean Air Act section 
113(c) and 18 U.S.C. 1001, the penalty for furnishing false, incomplete 
or misleading information in this certification or submission is a fine 
of up to $10,000 U.S., and/or imprisonment for up to five years.

[72 FR 24004, May 1, 2007]

[[Page 1055]]



Sec. 80.1167  What are the additional requirements under this 
subpart for a foreign RIN owner?

    (a) Foreign RIN owner. For purposes of this subpart, a foreign RIN 
owner is a person located outside the United States, the Commonwealth of 
Puerto Rico, the Virgin Islands, Guam, American Samoa, and the 
Commonwealth of the Northern Mariana Islands (collectively referred to 
in this section as ``the United States'') that has been approved by EPA 
to own RINs.
    (b) General Requirement. An approved foreign RIN owner must meet all 
requirements that apply to persons who own RINs under this subpart.
    (c) Foreign RIN owner commitments. Any person shall commit to and 
comply with the provisions contained in this paragraph (c) as a 
condition to being approved as a foreign RIN owner under this subpart.
    (1) Any United States Environmental Protection Agency inspector or 
auditor must be given full, complete and immediate access to conduct 
inspections and audits of the foreign RIN owner's place of business.
    (i) Inspections and audits may be either announced in advance by 
EPA, or unannounced; and
    (ii) Access will be provided to any location where documents related 
to RINs the foreign RIN owner has obtained, sold, transferred or held 
are kept.
    (iii) Inspections and audits may be by EPA employees or contractors 
to EPA.
    (iv) Any documents requested that are related to matters covered by 
inspections and audits must be provided to an EPA inspector or auditor 
on request.
    (v) Inspections and audits by EPA may include review and copying of 
any documents related to the following:
    (A) Transfers of title to RINs.
    (B) Work performed and reports prepared by independent auditors 
under the requirements of this section, including work papers.
    (vi) Inspections and audits by EPA may include interviewing 
employees.
    (vii) Any employee of the foreign RIN owner must be made available 
for interview by the EPA inspector or auditor, on request, within a 
reasonable time period.
    (viii) English language translations of any documents must be 
provided to an EPA inspector or auditor, on request, within 10 working 
days.
    (ix) English language interpreters must be provided to accompany EPA 
inspectors and auditors, on request.
    (2) An agent for service of process located in the District of 
Columbia shall be named, and service on this agent constitutes service 
on the foreign RIN owner or any employee of the foreign RIN owner for 
any action by EPA or otherwise by the United States related to the 
requirements of this subpart.
    (3) The forum for any civil or criminal enforcement action related 
to the provisions of this section for violations of the Clean Air Act or 
regulations promulgated thereunder shall be governed by the Clean Air 
Act, including the EPA administrative forum where allowed under the 
Clean Air Act.
    (4) United States substantive and procedural laws shall apply to any 
civil or criminal enforcement action against the foreign RIN owner or 
any employee of the foreign RIN owner related to the provisions of this 
section.
    (5) Submitting an application to be a foreign RIN owner, and all 
other actions to comply with the requirements of this subpart constitute 
actions or activities covered by and within the meaning of the 
provisions of 28 U.S.C. 1605(a)(2), but solely with respect to actions 
instituted against the foreign RIN owner, its agents and employees in 
any court or other tribunal in the United States for conduct that 
violates the requirements applicable to the foreign RIN owner under this 
subpart, including conduct that violates the False Statements 
Accountability Act of 1996 (18 U.S.C. 1001) and section 113(c)(2) of the 
Clean Air Act (42 U.S.C. 7413).
    (6) The foreign RIN owner, or its agents or employees, will not seek 
to detain or to impose civil or criminal remedies against EPA inspectors 
or auditors, whether EPA employees or EPA contractors, for actions 
performed within the scope of EPA employment related to the provisions 
of this section.
    (7) The commitment required by this paragraph (c) shall be signed by 
the owner or president of the foreign RIN owner business.

[[Page 1056]]

    (d) Sovereign immunity. By submitting an application to be a foreign 
RIN owner under this subpart, the foreign entity, and its agents and 
employees, without exception, become subject to the full operation of 
the administrative and judicial enforcement powers and provisions of the 
United States without limitation based on sovereign immunity, with 
respect to actions instituted against the foreign RIN owner, its agents 
and employees in any court or other tribunal in the United States for 
conduct that violates the requirements applicable to the foreign RIN 
owner under this subpart, including conduct that violates the False 
Statements Accountability Act of 1996 (18 U.S.C. 1001) and section 
113(c)(2) of the Clean Air Act (42 U.S.C. 7413).
    (e) Bond posting. Any foreign entity shall meet the requirements of 
this paragraph (d) as a condition to approval as a foreign RIN owner 
under this subpart.
    (1) The foreign entity shall post a bond of the amount calculated 
using the following equation:

Bond = G * $0.01

Where:

Bond = amount of the bond in U.S. dollars.
G = The total of the number of gallon-RINs the foreign entity expects to 
sell or transfer during the first calendar year that the foreign entity 
is a RIN owner, plus the number of gallon-RINs the foreign entity 
expects to sell or transfer during the next four calendar years. After 
the first calendar year, the bond amount shall be based on the actual 
number of gallon-RINs sold or transferred during the current calendar 
year and the number held at the conclusion of the current averaging 
year, plus the number of gallon-RINs sold or transferred during the four 
most recent calendar years preceding the current calendar year. For any 
year for which there were fewer than four preceding years in which the 
foreign entity sold or transferred RINs, the bond shall be based on the 
total of the number of gallon-RINs sold or transferred during the 
current calendar year and the number held at the end of the current 
calendar year, plus the number of gallon-RINs sold or transferred during 
any calendar year preceding the current calendar year, plus the number 
of gallon-RINs expected to be sold or transferred during subsequent 
calendar years, the total number of years not to exceed four calendar 
years in addition to the current calendar year.

    (2) Bonds shall be posted by doing any of the following:
    (i) Paying the amount of the bond to the Treasurer of the United 
States.
    (ii) Obtaining a bond in the proper amount from a third party surety 
agent that is payable to satisfy United States administrative or 
judicial judgments against the foreign RIN owner, provided EPA agrees in 
advance as to the third party and the nature of the surety agreement.
    (iii) An alternative commitment that results in assets of an 
appropriate liquidity and value being readily available to the United 
States, provided EPA agrees in advance as to the alternative commitment.
    (3) Bonds posted under this paragraph (e) shall:
    (i) Be used to satisfy any judicial judgment that results from an 
administrative or judicial enforcement action for conduct in violation 
of this subpart, including where such conduct violates the False 
Statements Accountability Act of 1996 (18 U.S.C. 1001) and section 
113(c)(2) of the Clean Air Act (42 U.S.C. 7413);
    (ii) Be provided by a corporate surety that is listed in the United 
States Department of Treasury Circular 570 ``Companies Holding 
Certificates of Authority as Acceptable Sureties on Federal Bonds''; and
    (iii) Include a commitment that the bond will remain in effect for 
at least five years following the end of latest reporting period in 
which the foreign RIN owner obtains, sells, transfers or holds RINs.
    (4) On any occasion a foreign RIN owner bond is used to satisfy any 
judgment, the foreign RIN owner shall increase the bond to cover the 
amount used within 90 days of the date the bond is used.
    (f) English language reports. Any document submitted to EPA by a 
foreign RIN owner shall be in English language, or shall include an 
English language translation.
    (g) Prohibitions. (1) A foreign RIN owner is prohibited from 
obtaining, selling, transferring or holding any RIN that is in excess of 
the number for which the bond requirements of this section have been 
satisfied.

[[Page 1057]]

    (2) Any RIN that is sold, transferred or held that is in excess of 
the number for which the bond requirements of this section have been 
satisfied is an invalid RIN under Sec. 80.1131.
    (3) Any RIN that is obtained from a person located outside the 
United States that is not an approved foreign RIN owner under this 
section is an invalid RIN under Sec. 80.1131.
    (4) No foreign RIN owner or other person may cause another person to 
commit an action prohibited in this paragraph (g), or that otherwise 
violates the requirements of this section.
    (h) Additional attest requirements for foreign RIN owners. The 
following additional requirements apply to any foreign RIN owner as part 
of the attest engagement required for RIN owners under this subpart K.
    (1) The attest auditor must be independent of the foreign RIN owner.
    (2) The attest auditor must be licensed as a Certified Public 
Accountant in the United States and a citizen of the United States, or 
be approved in advance by EPA based on a demonstration of ability to 
perform the procedures required in Sec. Sec. 80.125 through 80.127, 
80.130, and 80.1164.
    (3) The attest auditor must sign a commitment that contains the 
provisions specified in paragraph (c) of this section with regard to 
activities and documents relevant to compliance with the requirements of 
Sec. Sec. 80.125 through 80.127, 80.130, and 80.1164.
    (i) Withdrawal or suspension of foreign RIN owner status. EPA may 
withdraw or suspend its approval of a foreign RIN owner where any of the 
following occur:
    (1) A foreign RIN owner fails to meet any requirement of this 
section, including, but not limited to, the bond requirements.
    (2) A foreign government fails to allow EPA inspections as provided 
in paragraph (c)(1) of this section.
    (3) A foreign RIN owner asserts a claim of, or a right to claim, 
sovereign immunity in an action to enforce the requirements in this 
subpart.
    (4) A foreign RIN owner fails to pay a civil or criminal penalty 
that is not satisfied using the foreign RIN owner bond specified in 
paragraph (e) of this section.
    (j) Additional requirements for applications, reports and 
certificates. Any application for approval as a foreign RIN owner, any 
report, certification, or other submission required under this section 
shall be:
    (1) Submitted in accordance with procedures specified by the 
Administrator, including use of any forms that may be specified by the 
Administrator.
    (2) Signed by the president or owner of the foreign RIN owner 
company, or that person's immediate designee, and shall contain the 
following declaration:

    I hereby certify: (1) That I have actual authority to sign on behalf 
of and to bind [insert name of foreign RIN owner] with regard to all 
statements contained herein; (2) that I am aware that the information 
contained herein is being Certified, or submitted to the United States 
Environmental Protection Agency, under the requirements of 40 CFR part 
80, subpart K, and that the information is material for determining 
compliance under these regulations; and (3) that I have read and 
understand the information being Certified or submitted, and this 
information is true, complete and correct to the best of my knowledge 
and belief after I have taken reasonable and appropriate steps to verify 
the accuracy thereof. I affirm that I have read and understand the 
provisions of 40 CFR part 80, subpart K, including 40 CFR 80.1167 apply 
to [insert name of foreign RIN owner]. Pursuant to Clean Air Act section 
113(c) and 18 U.S.C. 1001, the penalty for furnishing false, incomplete 
or misleading information in this certification or submission is a fine 
of up to $10,000 U.S., and/or imprisonment for up to five years.

[72 FR 24004, May 1, 2007]



                       Subpart L_Gasoline Benzene

    Source: 72 FR 8544, Feb. 26, 2007, unless otherwise noted.



Sec. Sec. 80.1200-80.1219  [Reserved]

                           General Information



Sec. 80.1220  What are the implementation dates for the gasoline
benzene program?

    (a) Benzene standard. (1) For the annual averaging period beginning 
January 1, 2011, and for each annual averaging period thereafter, 
gasoline produced at each refinery of a refiner or imported by an 
importer, must meet the benzene standard specified in

[[Page 1058]]

Sec. 80.1230(a), except as otherwise specifically provided for in this 
subpart.
    (2) For the period July 1, 2012 through December 31, 2013, and for 
each annual averaging period thereafter, gasoline produced at each 
refinery of a refiner or imported by an importer, must meet the maximum 
average benzene standard specified in Sec. 80.1230(b), except as 
otherwise specifically provided for in this subpart.
    (3) Small refiners approved under Sec. 80.1340 may defer meeting 
the benzene standard specified in Sec. 80.1230(a) until the annual 
averaging period beginning January 1, 2015 and may defer meeting the 
benzene standard specified in Sec. 80.1230(b) until the averaging 
period beginning July 1, 2016, as described in Sec. 80.1342.
    (b) Early credit generation. (1) Effective with the averaging period 
beginning June 1, 2007, a refiner for each of its refineries that has an 
approved benzene baseline per Sec. 80.1285 may generate early benzene 
credits in accordance with the provisions of Sec. 80.1275.
    (2) Early benzene credits may be generated through the end of the 
averaging period ending December 31, 2010, or through the end of the 
averaging period ending December 31, 2014 for small refiners approved 
under Sec. 80.1340.
    (c) Standard credit generation. (1) Effective with the annual 
averaging period beginning January 1, 2011, a refiner for any of its 
refineries or an importer for its imported gasoline, may generate 
standard benzene credits in accordance with the provisions of Sec. 
80.1290.
    (2) Effective with the annual averaging period beginning January 1, 
2015, a small refiner approved under Sec. 80.1340, for any of its 
refineries, may generate standard benzene credits in accordance with the 
provisions of Sec. 80.1290.



Sec. 80.1225  Who must register with EPA under the gasoline
benzene program?

    (a) Refiners and importers that are registered by EPA under Sec. 
80.76, Sec. 80.103, Sec. 80.190, or Sec. 80.810 are deemed to be 
registered for purposes of this subpart.
    (b) Refiners and importers subject to the requirements in Sec. 
80.1230 that are not registered by EPA under Sec. Sec. 80.76, 80.103, 
80.190 or 80.810 shall provide to EPA the information required in Sec. 
80.76 by September 30, 2010, or not later than three months in advance 
of the first date that such person produces or imports gasoline, 
whichever is later.
    (c) Refiners that plan to generate early credits under Sec. 80.1275 
and that are not registered by EPA under Sec. Sec. 80.76, 80.103, 
80.190, or 80.810 must provide to EPA the information required in Sec. 
80.76 not later than 60 days prior to the end of the first year of 
credit generation.

                      Gasoline Benzene Requirements



Sec. 80.1230  What are the gasoline benzene requirements for refiners
and importers?

    (a) Annual average benzene standard. (1) Except as specified in 
paragraph (c) of this section, a refinery's or importer's average 
gasoline benzene concentration in any annual averaging period shall not 
exceed 0.62 volume percent.
    (2) Compliance with the standard specified in paragraph (a)(1) of 
this section, or creation of a deficit in accordance with paragraph (c) 
of this section, is determined in accordance with Sec. 80.1240(a).
    (3) The annual averaging period for achieving compliance with the 
requirement of paragraph (a)(1) of this section is January 1 through 
December 31 of each calendar year beginning January 1, 2011, or 
beginning January 1, 2015 for small refiners approved under Sec. 
80.1340.
    (4) Refinery grouping per Sec. 80.101(h) does not apply to 
compliance with the gasoline benzene requirement specified in this 
paragraph (a).
    (5) Gasoline produced at foreign refineries that is subject to the 
gasoline benzene requirements per Sec. 80.1235 shall be included in the 
importer's compliance determination beginning January 1, 2011, or 
beginning January 1, 2015 for small foreign refiners approved under 
Sec. 80.1340.
    (b) Maximum average benzene standard. (1) A refinery's or importer's 
maximum average gasoline benzene concentration in any averaging period 
shall not exceed 1.30 volume percent.
    (2) Compliance with the standard specified in paragraph (b)(1) of 
this section is determined in accordance with Sec. 80.1240(b).

[[Page 1059]]

    (3) The averaging period for achieving compliance with the 
requirement of paragraph (b)(1) of this section is July 1, 2012 through 
December 31, 2013 and each calendar year thereafter, or July 1, 2016 
through December 31, 2017, and each calendar year thereafter for small 
refiners approved under Sec. 80.1340.
    (c) Deficit carry-forward. (1) A refinery or importer creates a 
benzene deficit for a given averaging period when its compliance benzene 
value, per Sec. 80.1240(a), is greater than the benzene standard 
specified in paragraph (a) of this section.
    (2) A refinery or importer may carry the benzene deficit forward to 
the calendar year following the year the benzene deficit is created but 
only if no deficit had been previously carried forward to the year the 
deficit is created. If a refinery or importer carries forward a deficit, 
the following provisions apply in the second year:
    (i) The refinery or importer must achieve compliance with the 
benzene standard specified in paragraph (a) of this section.
    (ii) The refinery or importer must achieve further reductions in its 
gasoline benzene concentrations sufficient to offset the benzene deficit 
of the previous year.
    (iii) Benzene credits may be used, per Sec. 80.1295, to meet the 
requirements of paragraphs (c)(2)(i) and (ii) of this section.
    (iv) A refinery that has banked credits per Sec. 80.1295(a)(3) must 
use all of its banked credits to achieve compliance with the benzene 
standard specified in paragraph (a) of this section before creating a 
deficit.
    (3) EPA may allow an extended period of deficit carry-forward if it 
grants hardship relief under Sec. Sec. 80.1335 or 80.1336 from the 
annual average standard specified in paragraph (a) of this section.



Sec. 80.1235  What gasoline is subject to the benzene requirements
of this subpart?

    (a) For the purposes of determining compliance with the requirements 
of Sec. 80.1230, all of the following products that are produced or 
imported for use in the United States during a refinery's or importer's 
applicable compliance period are collectively ``gasoline'' and are to be 
included in a refinery's or importer's compliance determination under 
Sec. 80.1240, except as provided in paragraph (b) of this section:
    (1) Reformulated gasoline.
    (2) Conventional gasoline.
    (3) Reformulated gasoline blendstock for oxygenate blending 
(``RBOB'').
    (4) Conventional gasoline blendstock that becomes finished 
conventional gasoline upon the addition of oxygenate (``CBOB'').
    (5) Blendstock that has been combined with finished gasoline, other 
blendstock, transmix, or gasoline produced from transmix to produce 
gasoline.
    (6) Blendstock that has been combined with previously certified 
gasoline (``PCG'') to produce gasoline. Such blendstock must be sampled 
in accordance with the provisions at Sec. 80.1347(a)(5).
    (b) The following products are not to be included in a refinery's or 
importer's compliance determination under Sec. 80.1240:
    (1) Blendstock that has not been combined with other blendstock or 
finished gasoline to produce gasoline.
    (2) Oxygenate added to finished gasoline, RBOB, or CBOB downstream 
of the refinery that produced the gasoline or import facility where the 
gasoline was imported.
    (3) Butane added to finished gasoline, RBOB, CBOB downstream of the 
refinery that produced the gasoline or import facility where the 
gasoline was imported.
    (4) Gasoline produced by separating gasoline from transmix.
    (5) PCG.
    (6) Gasoline produced or imported for use in Guam, American Samoa, 
and the Commonwealth of the Northern Mariana Islands.
    (7) Gasoline exported for use outside the United States.
    (8) Gasoline produced by a small refiner approved under Sec. 
80.1340 prior to January 1, 2015, or prior to the small refiner's first 
compliance period pursuant to Sec. 80.1342(a), whichever is earlier.
    (9) Gasoline that is used to fuel aircraft, racing vehicles or 
racing boats that are used only in sanctioned racing events, provided 
that --

[[Page 1060]]

    (i) Product transfer documents associated with such gasoline, and 
any pump stand from which such gasoline is dispensed, identify the 
gasoline either as gasoline that is restricted for use in aircraft, or 
as gasoline that is restricted for use in racing motor vehicles or 
racing boats that are used only in sanctioned events;
    (ii) The gasoline is completely segregated from all other gasoline 
throughout production, distribution and sale to the ultimate consumer; 
and
    (iii) The gasoline is not made available for use as motor vehicle 
gasoline, or dispensed for use in motor vehicles, except for motor 
vehicles used only in sanctioned racing events.
    (10) California gasoline, as defined in Sec. 80.1236.



Sec. 80.1236  What requirements apply to California gasoline?

    (a) Definition. For purposes of this subpart, ``California 
gasoline'' means any gasoline designated by the refiner or importer as 
for use only in California and that is actually used in California.
    (b) California gasoline exemption. California gasoline that complies 
with all the requirements of this section is exempt from the 
requirements in Sec. 80.1230.
    (c) Requirements for California gasoline. The following requirements 
apply to California gasoline:
    (1) Each batch of California gasoline must be designated as such by 
its refiner or importer.
    (2) Designated California gasoline must be kept segregated from 
gasoline that is not California gasoline at all points in the 
distribution system.
    (3) Designated California gasoline must ultimately be used in the 
State of California and not used elsewhere in the United States.
    (4) In the case of California gasoline produced outside the State of 
California, the transferors and transferees must meet the product 
transfer document requirements under Sec. 80.81(g).
    (5) Gasoline that is ultimately used in any part of the United 
States outside of the State of California must comply with the 
requirements specified in Sec. 80.1230, regardless of any designation 
as California gasoline.



Sec. 80.1238  How is a refinery's or importer's average benzene concentration determined?

    (a) The average benzene concentration of gasoline produced at a 
refinery or imported by an importer for an applicable averaging period 
is calculated according to the following equation:
[GRAPHIC] [TIFF OMITTED] TR26FE07.012

Where:

Bavg = Average benzene concentration for the applicable 
averaging period (volume percent benzene).
i = Individual batch of gasoline produced at the refinery or imported 
during the applicable averaging period.
n = Total number of batches of gasoline produced at the refinery or 
imported during the applicable annual averaging period.
Vi = Volume of gasoline in batch i (gallons).
Bi = Benzene concentration of batch i (volume percent 
benzene), per Sec. 80.46(e).

    (b) A refiner or importer may include the volume of oxygenate added 
downstream from the refinery or import facility in the calculation 
specified in paragraph (a) of this section, provided the following 
requirements are met:
    (1) For oxygenate added to conventional gasoline, the refiner or 
importer must comply with the requirements of Sec. 80.101(d)(4)(ii) and 
the calculation methodologies of Sec. 80.101(g)(3).
    (2) For oxygenate added to RBOB, the refiner or importer must comply 
with the requirements of Sec. 80.69(a).
    (c) Refiners and importers must exclude from the calculation 
specified in paragraph (a) of this section all of the following:
    (1) Gasoline that was not produced at the refinery or imported by 
the importer.
    (2) Except as provided in paragraph (b) of this section, any 
blendstocks or unfinished gasoline transferred to others.
    (3) Gasoline that has been included in the compliance calculations 
for another refinery or importer.
    (4) Gasoline exempted from the standards under Sec. 80.1235(b).

[[Page 1061]]



Sec. 80.1240  How is a refinery's or importer's compliance with 
the gasoline benzene requirements of this subpart determined?

    (a) A refinery's or importer's compliance with the annual average 
benzene standard at Sec. 80.1230(a) is determined as follows:
    (1)(i) The compliance benzene value for a refinery or importer is:
    [GRAPHIC] [TIFF OMITTED] TR26FE07.013
    
Where:

CBVy = Compliance benzene value (gallons benzene) for year y.
Vy = Gasoline volume produced or imported in year y 
(gallons).
Bavg,y = Average benzene concentration in year y (volume 
percent benzene), calculated in accordance with Sec. 80.1238.
Dy-1 = Benzene deficit from the previous reporting period, 
per Sec. 80.1230(c) (gallons benzene).
BC = Banked benzene credits used to show compliance (gallons benzene).
OC = Benzene credits obtained by the refinery or importer used to show 
compliance (gallons benzene).

    (ii) Benzene credits used in the calculation specified in paragraph 
(a)(1)(i) of this section must be used in accordance with the 
requirements at Sec. 80.1295.
    (2)(i) If CBVy <= Vy x (0.62)/100, then 
compliance with the benzene requirement at Sec. 80.1230(a) is achieved 
for calendar year y.
    (ii) If CBVy  Vy x (0.62)/100, then 
compliance with the benzene requirement at Sec. 80.1230(a) is not 
achieved for calendar year y, and a deficit is created per Sec. 
80.1230(c). The deficit value to be included in the following year's 
compliance calculation per paragraph (a) of this section is calculated 
as follows:
[GRAPHIC] [TIFF OMITTED] TR26FE07.014

Where:

Dy = Benzene deficit created in compliance period y (gallons 
benzene).

    (b) Compliance with the maximum average benzene standard at Sec. 
80.1230(b) is achieved by a refinery or importer if the value of 
Bavg calculated in accordance with Sec. 80.1238(a) is no 
greater 1.30 volume percent for an applicable averaging period per Sec. 
80.1230(b)(3).

              Averaging, Banking and Trading (ABT) Program



Sec. 80.1270  Who may generate benzene credits under the ABT program?

    (a) Early benzene credits. Early benzene credits are credits 
generated prior to 2011, or prior to 2015 if generated by a small 
refiner approved under Sec. 80.1340.
    (1)(i) Early credits may be generated under Sec. 80.1275 by a 
refiner for any refinery it owns that has an approved benzene baseline 
under Sec. 80.1285, including a refinery of a foreign refiner that is 
subject to the provisions of Sec. 80.1363.
    (ii) The refinery specified in paragraph (a)(1)(i) of this section 
must process crude oil and/or intermediate feedstocks through refinery 
processing units.
    (iii) Early benzene credits shall be calculated separately for each 
refinery of a refiner.
    (iv) A refinery that is approved for early compliance under Sec. 
80.1334 may not generate early credits for the gasoline subject to the 
early compliance provisions.
    (2)(i) A refinery that was shut down during the entire 2004-2005 
benzene baseline period is not eligible to generate early credits under 
Sec. 80.1275.
    (ii) A refinery not in full production, excluding normal refinery 
downtime, or not showing consistent or regular gasoline production 
activity during 2004-2005 may be eligible to generate early benzene 
credits under Sec. 80.1275 upon petition to and approval by EPA, 
pursuant to Sec. 80.1285(d).
    (3) Importers may not generate early credits.
    (b) Standard benzene credits. Standard benzene credits are credits 
generated after 2010, or after 2014 if generated by a small refiner 
approved under Sec. 80.1340.
    (1) Unless otherwise provided for elsewhere in this subpart, 
standard credits may be generated under Sec. 80.1290 as follows:
    (i) A refiner may generate standard credits separately for each of 
its refineries.
    (ii) An importer may generate standard credits for all of its 
imported gasoline.

[[Page 1062]]

    (2) Oxygenate blenders, butane blenders, and transmix producers may 
not generate standard credits.
    (3) Foreign refiners may not generate standard credits.



Sec. 80.1275  How are early benzene credits generated?

    (a) For each averaging period per paragraph (b) of this section in 
which a refinery plans to generate early credits, its average gasoline 
benzene concentration calculated according to Sec. 80.1238(a) must be 
at least 10% lower than its benzene baseline concentration approved 
under Sec. 80.1280.
    (b) The early credit averaging periods are as follows:
    (1) For 2007, the seven-month period from June 1, 2007 through 
December 31, 2007.
    (2) For 2008, 2009 and 2010, the 12-month calendar year.
    (3) For small refiners approved under Sec. 80.1340, the 12-month 
calendar years 2011, 2012, 2013, and 2014 in addition to the periods 
specified in paragraphs (b)(1) and (b)(2) of this section.
    (c) The number of early benzene credits generated shall be 
calculated for each applicable averaging period as follows:
[GRAPHIC] [TIFF OMITTED] TR26FE07.015

Where:

ECy = Early credits generated in averaging period y (gallons 
benzene).
BBase = Baseline benzene concentration of the refinery 
(volume percent benzene), per Sec. 80.1280(a).
Bavg,y = Average benzene concentration of gasoline produced 
at the refinery during averaging period y (volume percent benzene), per 
Sec. 80.1238.
Ve,y = Total volume of gasoline produced at the refinery 
during averaging period y (gallons).

    (d) A refinery that plans to generate early credits must also show 
that it has met all of the following requirements prior to or during the 
first early credit averaging period, per paragraph (b) of this section, 
in which it generates early credits:
    (1) Since 2005, has made operational changes and/or improvements in 
benzene control technology to reduce gasoline benzene levels, including 
at least one of the following:
    (i) Treating the heavy straight run naphtha entering the reformer 
using light naphtha splitting and/or isomerization.
    (ii) Treating the reformate stream exiting the reformer using 
benzene extraction or benzene saturation.
    (iii) Directing additional refinery streams to the reformer for 
treatment described paragraphs (d)(1)(i) and (ii) of this section.
    (iv) Directing reformate streams to other refineries with treatment 
capabilities described in paragraph (d)(1)(ii) of this section.
    (2) Has not included gasoline blendstock streams transferred to, 
from, or between refineries, except as noted in paragraph (d)(1)(iv) of 
this section.
    (e) Early benzene credits calculated in accordance with paragraph 
(c) of this section shall be expressed to the nearest gallon. Fractional 
values shall be rounded down if less than 0.50, and rounded up if 
greater than or equal to 0.50.



Sec. 80.1280  How are refinery benzene baselines calculated?

    (a) A refinery's benzene baseline is based on the refinery's 2004-
2005 average gasoline benzene concentration, calculated according to the 
following equation:
[GRAPHIC] [TIFF OMITTED] TR26FE07.016

Where:

BBase = Benzene baseline concentration (volume percent 
benzene).
i = Individual batch of gasoline produced at the refinery 
from January 1, 2004 through December 31, 2005.
n = Total number of batches of gasoline produced at the refinery from 
January 1, 2004 through December 31, 2005 (or the total number of 
batches of gasoline pursuant to Sec. 80.1285(d)).
Vi = Volume of gasoline in batch i (gallons).
Bi = Benzene content of batch i (volume percent benzene).

    (b) A refiner for a refinery that included oxygenate blended 
downstream

[[Page 1063]]

of the refinery in compliance calculations for RFG or conventional 
gasoline for calendar years 2004 or 2005 under Sec. 80.69 or Sec. 
80.101(d)(4) must include the volume and benzene concentration of this 
oxygenate in the benzene baseline calculation for that refinery under 
paragraph (a) of this section.



Sec. 80.1285  How does a refiner apply for a benzene baseline?

    (a) A benzene baseline application must be submitted for each 
refinery that plans to generate early credits under Sec. 80.1275. The 
application must include the information specified in paragraph (c) of 
this section and must be submitted to EPA at least 60 days before the 
first averaging period in which the refinery plans to generate early 
credits.
    (b) For U.S. Postal delivery, the benzene baseline application shall 
be sent to: Attn: MSAT2 Benzene, Mail Stop 6406J, U.S. Environmental 
Protection Agency, 1200 Pennsylvania Ave., NW., Washington, DC 20460. 
For commercial delivery: MSAT2 Benzene, 202-343-9038, U.S. Environmental 
Protection Agency, 1310 L Street, NW., Washington, DC 20005.
    (c) The benzene baseline application must include the following 
information:
    (1) A listing of the names and addresses of all refineries owned by 
the company.
    (2) The benzene baseline for gasoline produced in 2004-2005 at the 
refinery, calculated in accordance with Sec. 80.1280.
    (3) Copies of the annual reports required under Sec. 80.75 for RFG 
and Sec. 80.105 for conventional gasoline.
    (4) A letter signed by the president, chief operating officer, or 
chief executive officer, of the company, or his/her designee, stating 
that the information contained in the benzene baseline determination is 
true to the best of his/her knowledge.
    (5) Name, address, phone number, facsimile number and e-mail address 
of a corporate contact person.
    (d) For a refinery that may be eligible to generate early credits 
under Sec. 80.1270(a)(2)(ii), a refiner may submit to EPA a benzene 
baseline application per the requirements of this section. The refiner 
must also submit information regarding the nature and cause of the 
refinery's production activity that resulted in irregular or less than 
full production, how it affected the baseline benzene concentration, and 
whether and how an alternative calculation to the calculation specified 
in Sec. 80.1280 produces a more representative benzene baseline value. 
Upon consideration of the submitted information, EPA may approve a 
benzene baseline for such a refinery.
    (e) EPA will notify the refiner of approval of the refinery's 
benzene baseline or any deficiencies in the application. However, except 
for applications submitted in accordance with paragraph (d) of this 
section, the refinery's benzene baseline application may be considered 
approved 60 days after EPA's receipt of the baseline application, 
subject to paragraph (f) of this section.
    (f) If at any time the baseline submitted in accordance with the 
requirements of this section is determined to be incorrect, EPA will 
notify the refiner of the corrected baseline.



Sec. 80.1290  How are standard benzene credits generated?

    (a) The standard credit averaging periods are the calendar years 
beginning January 1, 2011, or beginning January 1, 2015 for small 
refiners approved under Sec. 80.1340.
    (b) [Reserved]
    (c)(1) The number of standard benzene credits generated shall be 
calculated annually for each applicable averaging period according to 
the following equation:
[GRAPHIC] [TIFF OMITTED] TR26FE07.017

Where:

SCy = Standard credits generated in year y (gallons benzene).
Bavg,y = Annual average benzene concentration for year y 
(volume percent benzene), per Sec. 80.1238.
Vy = Total volume of gasoline produced or imported in year y 
(gallons).

    (2) No credits shall be generated unless the value SCy is 
positive.
    (d) Standard benzene credits calculated in accordance with paragraph 
(c) of this section shall be expressed to

[[Page 1064]]

the nearest gallon. Fractional values shall be rounded down if less than 
0.50, and rounded up if greater than or equal to 0.50.



Sec. 80.1295  How are gasoline benzene credits used?

    (a) Credit use. (1) Gasoline benzene credits may be used to comply 
with the gasoline benzene standard of Sec. 80.1230(a) provided that--
    (i) The gasoline benzene credits were generated according to 
Sec. Sec. 80.1275 or 80.1290.
    (ii) The recordkeeping requirements for gasoline benzene credits 
under Sec. 80.1350 are met.
    (iii) The gasoline benzene credits are correctly reported according 
to Sec. Sec. 80.1352 and 80.1354.
    (iv) The conditions of this section are met.
    (2) Gasoline benzene credits generated under Sec. Sec. 80.1275 and 
80.1290 may be used interchangeably in all credit use scenarios, subject 
to the credit life provisions specified in paragraph (c) of this 
section.
    (3) Gasoline benzene credits may be used by a refiner or importer to 
comply with the gasoline benzene content standard of Sec. 80.1230(a), 
may be banked by a refiner or importer for future use or transfer, may 
be transferred to another refinery or importer within a company 
(intracompany trading), or may be transferred to another refiner or 
importer outside of the company.
    (b) Credit transfers. (1) Gasoline benzene credits obtained from 
another refinery or importer may be used to comply with the gasoline 
benzene content requirement of Sec. 80.1230(a) provided the following 
conditions are met:
    (i) The credits are generated and reported according to the 
requirements of this subpart, and the transferred credits have not 
expired, per paragraph (c) of this section.
    (ii) Any credit transfer takes place no later than the last day of 
February following the calendar year averaging period when the credits 
are used.
    (iii) The credit has not been transferred more than twice. The first 
transfer by the refinery or importer that generated the credit may only 
be made to a refiner or importer that intends to use the credit; if the 
transferee cannot use the credit, it may make the second, and final, 
transfer only to a refiner or importer that intends to use or to 
terminate the credit. In no case may a credit be transferred more than 
twice before being used or terminated.
    (iv) The credit transferor has applied any gasoline benzene credits 
necessary to meet its own annual compliance requirements (including any 
deficit carried forward, pursuant to Sec. 80.1230(c), if applicable) 
before transferring any gasoline benzene credits to any other refiner or 
importer.
    (v) The credit transferor does not create a deficit as a result of a 
credit transfer.
    (vi) The transferor supplies records to the transferee indicating 
the year the gasoline benzene credits were generated, the identity of 
the refiner (and refinery) or importer that generated the gasoline 
benzene credits, and the identity of the transferring entity if it is 
not the same entity that generated the gasoline benzene credits.
    (2) In the case of gasoline benzene credits that have been 
calculated or created improperly, or that EPA has otherwise determined 
to be invalid, the following provisions apply:
    (i) Invalid gasoline benzene credits cannot be used to achieve 
compliance with the gasoline benzene content requirement of Sec. 
80.1230(a), regardless of the transferee's good-faith belief that the 
gasoline benzene credits were valid.
    (ii) The refiner or importer that used the gasoline benzene credits 
and any transferor of the gasoline benzene credits must adjust their 
credit records, reports, and compliance calculations as necessary to 
reflect the proper gasoline benzene credits.
    (iii) Any properly created gasoline benzene credits existing in the 
transferor's credit balance following the corrections and adjustments 
specified in paragraph (b)(2)(ii) of this section must first be applied 
to correct the invalid transfers to the transferee, before the 
transferor uses, trades or banks the gasoline benzene credits.
    (c) Credit life. (1)(i) Early credits, per Sec. 80.1275, may be 
used for compliance purposes under Sec. 80.1240(a) for any of the 
following annual averaging periods: 2011, 2102, 2013.

[[Page 1065]]

    (ii) Early credits, per Sec. 80.1275, may be used for compliance 
purposes under Sec. 80.1240(a) by small refiners approved under Sec. 
80.1340 for any of the following averaging periods: 2015, 2016, 2017.
    (2)(i) Standard credits, per Sec. 80.1290, may be used for 
compliance purposes under Sec. 80.1240(a) within five years from the 
year they were generated, except as noted under paragraph (c)(2)(ii) of 
this section. Example: Standard credits generated during 2011 may be 
used to achieve compliance under Sec. 80.1240(a) for any calendar year 
averaging period prior to the 2017 averaging period.
    (ii) Standard credits, per Sec. 80.1290, may be used for compliance 
purposes under Sec. 80.1240(a) within seven years from the year they 
were generated if traded to and ultimately used by a small refiner 
approved under Sec. 80.1340. Example: Standard credits generated in 
2011 may be used to achieve compliance under Sec. 80.1240(a) for any 
calendar year averaging period prior to the 2019 averaging period if 
traded to and ultimately used by a small refiner approved under Sec. 
80.1340.
    (d) Deficit provision limitation. A refiner or importer possessing 
gasoline benzene credits must use all gasoline benzene credits in its 
possession before applying the benzene deficit provisions of Sec. 
80.1230(c).

                           Hardship Provisions



Sec. 80.1334  What are the requirements for early compliance with
the gasoline benzene program?

    (a)(1) A refinery may comply with the benzene requirements at Sec. 
80.1230 for its RFG and/or conventional gasoline (CG) prior to the 2011 
compliance period if it applies for this early compliance option as 
specified in paragraph (b) of this section, and is approved by EPA.
    (2) Only refineries that produce gasoline by processing crude and/or 
intermediate feedstocks through refinery processing units may apply for 
this early compliance option.
    (b) Refiners must submit an application in order to be considered 
for early compliance as described in this section.
    (1) Applications for early compliance as described in this section 
must be submitted to EPA by December 31, 2007.
    (2) Applications must be sent to: U.S. EPA, NVFEL-ASD, Attn: MSAT2 
Early Compliance, 2000 Traverwood Dr., Ann Arbor, MI 48105.
    (3) Application must be made separately for a refinery's RFG and CG 
pools.
    (4) The early compliance application must show that all the 
following criteria are met:
    (i) For an RFG early compliance application--
    (A) The refinery's RFG baseline value under Sec. 80.915 is greater 
than or equal to 30 percent reduction.
    (B) The refinery's 2003 RFG annual average benzene concentration was 
less than or equal to 0.62 vol%.
    (C) The refinery's 2003 RFG annual average sulfur concentration was 
less than or equal to 140 ppm.
    (D) The refinery's 2003 RFG annual average MTBE concentration was 
greater than or equal to 6 vol%.
    (ii) For a CG early compliance application--
    (A) The refinery's CG baseline under Sec. 80.915 is less than or 
equal to 80 mg/mile.
    (B) The refinery's 2003 CG annual average benzene concentration was 
less than or equal to 0.62 vol%.
    (C) The refinery's 2003 CG annual average sulfur concentration was 
less than or equal to 140 ppm.
    (D) The refinery's 2003 CG annual average MTBE concentration was 
greater than or equal to 6 vol%.
    (5) In addition, the application must demonstrate that the refinery 
has extremely limited ability to adjust its operations in order to 
comply with its applicable RFG or CG toxics performance requirements 
under Sec. 80.815.
    (6) The refiner must provide additional information as requested by 
EPA.
    (c)(1) If approved for early compliance with the provisions of this 
subpart, the refinery may comply with the provisions of Sec. 80.1230 as 
follows:
    (i) For the compliance period beginning January 1, 2007, and each 
annual compliance period through 2010; or
    (ii) For the compliance period beginning January 1, 2008, and each 
annual compliance period through 2010.

[[Page 1066]]

    (2) The refinery must notify EPA under which compliance period 
specified in paragraph (c)(1) of this section it will begin compliance.
    (3) Beginning with the compliance period chosen pursuant to 
paragraph (c)(2) of this section--
    (i) For early compliance approved for a refinery's RFG pool, the 
toxics air pollutants emissions performance requirements specified in 
Sec. Sec. 80.41(e)(1) and (f)(1) and 80.815 shall not apply to the 
reformulated gasoline produced by the refinery.
    (ii) For early compliance approved for a refinery's CG pool, the 
annual average exhaust toxics emissions requirements specified in 
Sec. Sec. 80.101(c)(2) and 80.815 shall not apply to conventional 
gasoline produced by the refinery.
    (4) Refineries approved for early compliance under this section may 
not generate early credits under Sec. 80.1275.
    (d) If EPA finds that a refiner provided false or inaccurate 
information in its application for early compliance, the early 
compliance approval will be void ab initio.



Sec. 80.1335  Can a refiner seek relief from the requirements of
this subpart?

    (a) A refiner may apply for relief from the requirements specified 
in Sec. 80.1230(a) or (b) for a refinery, if it can show that--
    (1) Unusual circumstances exist that impose extreme hardship and 
significantly affect the ability to comply with the gasoline benzene 
standards at Sec. 80.1230(a) or (b) by the applicable date(s); and
    (2) It has made best efforts to comply with the requirements of this 
subpart.
    (b) A refiner must apply for and be approved for relief under this 
section.
    (1) An application must include the following information:
    (i) A plan demonstrating how the refiner will comply with the 
requirements of Sec. 80.1230(a) or (b), as applicable, as expeditiously 
as possible. The plan shall include a showing that contracts are or will 
be in place for engineering and construction of benzene reduction 
technology, a plan for applying for and obtaining any permits necessary 
for construction, a description of plans to obtain necessary capital, 
and a detailed estimate of when the requirements of Sec. 80.1230(a) or 
(b), as applicable, will be met.
    (ii) A detailed description of the refinery configuration and 
operations including, at minimum, the following information:
    (A) The refinery's total reformer unit throughput capacity;
    (B) The refinery's total crude capacity;
    (C) Total crude capacity of any other refineries owned by the same 
entity;
    (D) Total volume of gasoline production at the refinery;
    (E) Total volume of other refinery products;
    (F) Geographic location(s) where the refinery's gasoline will be 
sold;
    (G) Detailed descriptions of efforts to obtain capital for refinery 
investments;
    (H) Bond rating of entity that owns the refinery; and
    (I) Estimated capital investment needed to comply with the 
requirements of this subpart.
    (iii) For a hardship related to complying with the requirement at 
Sec. 80.1230(a), detailed descriptions of efforts to obtain credits, 
including the prices of credits available, but deemed uneconomical by 
the refiner.
    (2) Applicants must also provide any other relevant information 
requested by EPA.
    (3) An application for relief from the requirements specified in 
Sec. 80.1230(b) must be submitted to EPA by January 1, 2008, or by 
January 1, 2013 for small refiners approved under Sec. 80.1340.
    (c)(1) Approval of a hardship application under this section for 
relief from the annual average benzene standard at Sec. 80.1230(a) 
shall be in the form of an extended period of deficit carry-forward, per 
Sec. 80.1230(c), for such period of time as EPA determines is 
appropriate.
    (2) Approval of a hardship application under this section for relief 
from the maximum average benzene standard at Sec. 80.1230(b) shall be 
in the form of a waiver of the standard for such period of time as EPA 
determines is appropriate.
    (3) EPA may deny any application for appropriate reasons, including 
unacceptable environmental impact.
    (d) EPA may impose any other reasonable conditions on relief 
provided

[[Page 1067]]

under this section, including rescinding, or reducing the length of, the 
extended deficit carry-forward period if conditions or situations change 
between approval of the hardship application and the end of the approved 
relief period.



Sec. 80.1336  What if a refiner or importer cannot produce gasoline 
conforming to the requirements of this subpart?

    In extreme, unusual, and unforeseen circumstances (for example, a 
natural disaster or a refinery fire) that are clearly outside the 
control of the refiner or importer and that could not have been avoided 
by the exercise of prudence, diligence, and due care, EPA may permit a 
refinery or importer to exceed the allowable average benzene levels 
specified in Sec. 80.1230(a) or (b), as applicable, if--
    (a) It is in the public interest to do so;
    (b) The refiner or importer exercised prudent planning and was not 
able to avoid the violation and has taken all reasonable steps to 
minimize the extent of the nonconformity;
    (c) The refiner or importer can show how the requirements at Sec. 
80.1230(a) or (b), as applicable, will be achieved as expeditiously as 
possible;
    (d) The refiner or importer agrees to make up any air quality 
detriment associated with the nonconformity, where practicable; and
    (e) The refiner or importer pays to the U.S. Treasury an amount 
equal to the economic benefit of the nonconformity minus the amount 
expended making up the air quality detriment pursuant to paragraph (d) 
of this section.

                        Small Refiner Provisions



Sec. 80.1338  What criteria must be met to qualify as a small refiner
for the gasoline benzene requirements of this subpart?

    (a) A small refiner is any person that demonstrates that it--
    (1) Produced gasoline at a refinery by processing crude oil through 
refinery processing units from January 1, 2005 through December 31, 
2005.
    (2) Employed an average of no more than 1,500 people, based on the 
average number of employees for all pay periods from January 1, 2005 
through December 31, 2005.
    (3) Had a corporate average crude oil capacity less than or equal to 
155,000 barrels per calendar day (bpcd) for 2005.
    (4) Following the submission of a small refiner application, 
pursuant to Sec. 80.1340, has been approved as a small refiner for this 
subpart.
    (b) For the purpose of determining the number of employees and the 
crude oil capacity under paragraph (a) of this section, the following 
determinations shall be observed:
    (1) The refiner shall include the employees and crude oil capacity 
of any subsidiary companies, any parent company, subsidiaries of the 
parent company in which the parent has a controlling interest, and any 
joint venture partners.
    (2) For any refiner owned by a governmental entity, the number of 
employees and total crude oil capacity as specified in paragraph (a) of 
this section shall include all employees and crude oil production of the 
government to which the governmental entity is a part.
    (3) Any refiner owned and controlled by an Alaska Regional or 
Village Corporation organized pursuant to the Alaska Native Claims 
Settlement Act (43 U.S.C. 1601) is not considered an affiliate of such 
entity, or with other concerns owned by such entity, solely because of 
their common ownership.
    (c) Notwithstanding the provisions of paragraph (a) of this section, 
a refiner that reactivates a refinery that it had previously operated, 
and that was shut down or non-operational for the entire period between 
January 1, 2005 and December 31, 2005, may apply for small refiner 
status in accordance with the provisions of Sec. 80.1340.



Sec. 80.1339  Who is not eligible for the provisions for small refiners?

    The following are not eligible for the hardship provisions for small 
refiners:
    (a) A refiner with one or more refineries built after December 31, 
2005.
    (b) A refiner that exceeds the employee or crude oil capacity 
criteria

[[Page 1068]]

under Sec. 80.1338 but that meets these criteria after December 31, 
2005, regardless of whether the reduction in employees or crude capacity 
is due to operational changes at the refinery or a company sale or 
reorganization.
    (c) Importers.
    (d) A refiner that produce gasoline other than by processing crude 
oil through refinery processing units.
    (e)(1) A small refiner approved under Sec. 80.1340 that 
subsequently ceases production of gasoline from processing crude oil 
through refinery processing units, employs more than 1,500 people, or 
exceeds the 155,000 bpcd crude oil capacity limit after December 31, 
2005 as a result of merger with or acquisition of or by another entity, 
is disqualified as a small refiner, except that this shall not apply in 
the case of a merger between two previously approved small refiners. If 
disqualification occurs, the refiner shall notify EPA in writing no 
later than 20 days following this disqualifying event.
    (2) Except as provided under paragraph (e)(3) of this section, any 
refiner whose status changes as specified in paragraph (e)(1) under this 
paragraph (b) shall meet the applicable standards of Sec. 80.1230 
within 30 months of the disqualifying event for all its refineries. 
However, such period shall not extend beyond December 31, 2014.
    (3) A refiner may apply to EPA for an additional six months to 
comply with the standards of Sec. 80.1230 if it believes that more than 
30 months will be required for the necessary engineering, permitting, 
construction, and start-up work to be completed. Such applications must 
include detailed technical information supporting the need for 
additional time. EPA will base its decision to approve additional time 
on the information provided by the refiner and on other relevant 
information. In no case will EPA extend the compliance date beyond 
December 31, 2014.
    (4) During the period provided under paragraph (e)(2) of this 
section, and any extension provided under paragraph (e)(3) of this 
section, the refiner may not generate gasoline benzene credits under 
Sec. 80.1275 or Sec. 80.1290.
    (f) A small refiner approved under Sec. 80.1340 which notifies EPA 
that it wishes to withdraw its small refiner status pursuant to Sec. 
80.1340(g).



Sec. 80.1340  How does a refiner obtain approval as a small refiner?

    (a) Applications for small refiner status must be submitted to EPA 
by December 31, 2007.
    (b) For U.S. Postal delivery, applications for small refiner status 
must be sent to: Attn: MSAT2 Benzene, Mail Stop 6406J, U.S. 
Environmental Protection Agency, 1200 Pennsylvania Ave., NW., 
Washington, DC 20460. For commercial delivery: MSAT2 Benzene, 202-343-
9038, U.S. Environmental Protection Agency, 1310 L Street, NW., 
Washington, DC 20005.
    (c) The small refiner status application must contain the following 
information for the company seeking small refiner status, and for all 
subsidiary companies, all parent companies, all subsidiaries of the 
parent companies, and all joint venture partners:
    (1) Employees. For joint ventures, the total number of employees 
includes the combined employee count of all corporate entities in the 
venture. For government-owned refiners, the total employee count 
includes all government employees.
    (i) Pursuant to paragraph (c) of this section, a listing of each 
company facility and each facility's address where any employee, as 
specified in paragraph (a)(1) of this section, worked during the 12 
months preceding January 1, 2006.
    (ii) The average number of employees at each facility based upon the 
number of employees for each pay period for the 12 months preceding 
January 1, 2006.
    (iii) The type of business activities carried out at each location.
    (iv) In the case of a refiner that reactivates a refinery that it 
previously owned and operated and that was shut down or non-operational 
between January 1, 2005 and January 1, 2006, include the following:
    (A) Pursuant to paragraph (c) of this section, a listing of each 
company refinery each refinery's address where any employee, as 
specified in paragraph (a)(1) of this section, worked since the refiner 
acquired or reactivated the refinery.

[[Page 1069]]

    (B) The average number of employees at any such reactivated refinery 
during each calendar year since the refiner reactivated the refinery.
    (C) The type of business activities carried out at each location.
    (2) Crude oil capacity.
    (i) The total corporate crude oil capacity of each refinery as 
reported to the Energy Information Administration (EIA) of the U.S. 
Department of Energy (DOE), for the period January 1, 2005 through 
December 31, 2005.
    (ii) The information submitted to EIA is presumed to be correct. In 
cases where a company disagrees with this information, the company may 
petition EPA with appropriate data to correct the record when the 
company submits its application for small refiner status.
    (3) The type of business activity carried out at each location.
    (4) For each refinery, an indication of the small refiner option(s), 
pursuant to Sec. 80.1342, intended to be utilized at the refinery.
    (5) A letter signed by the president, chief operating officer or 
chief executive officer of the company, or his/her designee, stating 
that the information contained in the application is true to the best of 
his/her knowledge, and that the company owned the refinery as of January 
1, 2006.
    (6) Name, address, phone number, facsimile number, and e-mail 
address of a corporate contact person.
    (d) Approval of a small refiner status application will be based on 
the information submitted under paragraph (c) of this section and any 
other relevant information.
    (e) EPA will notify a refiner of approval or disapproval of small 
refiner status by letter.
    (1) If approved, all refineries of the refiner may defer meeting the 
standard specified in Sec. 80.1230(a) until the annual averaging period 
beginning January 1, 2015, and the standard specified in Sec. 
80.1230(b) until the averaging period beginning July 1, 2016.
    (2) If disapproved, all refineries of the refiner must meet the 
standard specified in Sec. 80.1230(a) beginning with the annual 
averaging period beginning January 1, 2011, and must meet the standard 
specified in Sec. 80.1230(b) beginning with the averaging period 
beginning July 1, 2012.
    (f) If EPA finds that a refiner provided false or inaccurate 
information on its application for small refiner status, the refiner's 
small refiner status will be void ab initio.
    (g) Prior to January 1, 2014, and upon notification to EPA, a small 
refiner approved per this section may withdraw its status as a small 
refiner. Effective on January 1 of the year following such notification, 
the small refiner will become subject to the standards at Sec. 80.1230.



Sec. 80.1342  What compliance options are available to small
refiners under this subpart?

    (a) A refiner that has been approved as a small refiner under Sec. 
80.1340 may--
    (1)(i) Defer meeting the standard specified in Sec. 80.1230(a) 
until the annual averaging period beginning January 1, 2015; or
    (ii) Meet the standard specified in Sec. 80.1230(a) in any annual 
averaging period from 2011 through 2014, inclusive, provided it notifies 
EPA in writing no later than November 15 prior to the year in which it 
will produce compliant gasoline.
    (2)(i) Defer meeting the standard specified in Sec. 80.1230(b) 
until the averaging period beginning July 1, 2016; or
    (ii) Meet the standard specified in Sec. 80.1230(b) in any 
averaging period specified in Sec. 80.1230(b)(3) prior to the averaging 
period beginning July 1, 2016 provided it notifies EPA in writing no 
later than November 15 prior to the year in which it will produce 
compliant gasoline.
    (b) Any refiner that makes an election under paragraphs (a)(1) or 
(a)(2) of this section must comply with the applicable benzene standards 
at Sec. 80.1230 beginning with the first averaging period subsequent to 
the status change.
    (c) The provisions of paragraph (a) of this section shall apply 
separately for each of an approved small refiner's refineries.

[[Page 1070]]



Sec. 80.1343  What hardship relief provisions are available only
to small refiners?

    (a)(1) In the case of a small refiner approved under Sec. 80.1340 
for which compliance with the requirement at Sec. 80.1230(a) would be 
feasible only through the purchase of credits, but for whom purchase of 
credits is not practically or economically feasible, EPA may approve a 
delay of the requirements applicable to the first compliance period for 
that refiner for up to two years.
    (2) No delay in accordance with paragraph (a) of this section will 
be granted to any small refiner prior to the EPA issuing a review of the 
credit program.
    (3) A small refiner may request one or more extensions of an 
approved delay if it can continue to demonstrate extreme difficulty in 
achieving compliance, through the use of credits, with the annual 
average benzene standard at Sec. 80.1230(a).
    (b) In the case of a small refiner approved under Sec. 80.1340 for 
which compliance with the maximum average benzene requirement at Sec. 
80.1230(b) is not feasible, the refiner may apply for hardship relief 
under Sec. 80.1335.



Sec. 80.1344  What provisions are available to a non-small refiner
that acquires one or more of a small refiner's refineries?

    (a) In the case of a refiner that is not an approved small refiner 
under Sec. 80.1340 and that acquires a refinery from a small refiner 
approved under Sec. 80.1340, the small refiner provisions of the 
gasoline benzene program of this subpart continue to apply to the 
acquired refinery for a period of up to 30 months from the date of 
acquisition of the refinery. In no case shall this period extend beyond 
December 31, 2014.
    (b) A refiner may apply to EPA for up to an additional six months to 
comply with the standards of Sec. 80.1230 for the acquired refinery if 
it believes that more than 30 months would be required for the necessary 
engineering, permitting, construction, and start-up work to be 
completed. Such applications must include detailed technical information 
supporting the need for additional time. EPA will base a decision to 
approve additional time on information provided by the refiner and on 
other relevant information. In no case shall this period extend beyond 
December 31, 2014.
    (c) A refiner that acquires a refinery from a small refiner approved 
per Sec. 80.1340 shall notify EPA in writing no later than 20 days 
following the acquisition.

              Sampling, Testing and Retention Requirements



Sec. 80.1347  What are the sampling and testing requirements for 
refiners and importers?

    (a) Sample and test each batch of gasoline. (1) The sampling and 
testing requirements specified in subpart D for reformulated gasoline 
shall continue to apply to reformulated gasoline and shall be extended 
to conventional gasoline (CG) for the purpose of complying with the 
benzene requirements of this subpart, except as modified by paragraphs 
(a)(2), (a)(3) and (a)(4) of this section.
    (2) Refiners and importers shall collect a representative sample 
from each batch of gasoline produced or imported, according to the 
earliest applicable date in the following schedule:
    (i) Beginning January 1, 2011;
    (ii) Beginning January 1, 2015 for small refiners approved under 
Sec. 80.1340;
    (iii) Beginning January 1 of the year prior to 2015 in which a small 
refiner approved under Sec. 80.1340 has opted, per Sec. 80.1342(a), to 
begin meeting the standards at Sec. 80.1230;
    (iv) Beginning June 1, 2007, for any refinery planning to generate 
early credits for the averaging period specified at Sec. 80.1275(b)(1);
    (v) Beginning January 1 of each averaging period specified at Sec. 
80.1275(b)(2) or (b)(3) for which the refinery plans to generate early 
credits;
    (vi) Beginning January 1 of the year, per Sec. 80.1334(c)(1), in 
which a refinery approved for early compliance under Sec. 80.1334 opts 
to begin early compliance. The provisions shall only apply to the type 
of gasoline, RFG or CG, for which early compliance was approved.
    (3)(i) Each sample shall be tested in accordance with the 
methodology specified at Sec. 80.46(e) to determine its benzene 
concentration for compliance with the requirements of this subpart.

[[Page 1071]]

    (ii) Independent sample analysis, under Sec. 80.65(f), is not 
required for conventional gasoline.
    (4) Any refiner or importer may release CG prior to obtaining the 
test results for benzene required under paragraph (a)(1) of this 
section.
    (5) Exclusion of previously certified gasoline.
    (i) Any refiner who uses previously certified reformulated or 
conventional gasoline or RBOB to produce conventional gasoline at a 
refinery, must exclude the previously certified gasoline (``PCG'') for 
purposes of demonstrating compliance with the benzene standards at Sec. 
80.1230.
    (ii) To accomplish the exclusion required in paragraph (a)(5)(i) of 
this section, the refiner must determine the volume and benzene content 
of the previously certified gasoline used at the refinery and the volume 
and benzene content of gasoline produced at the refinery, and use the 
compliance calculation procedures in paragraphs (a)(5)(iii) and 
(a)(5)(iv) of this section.
    (iii) For each batch of previously certified gasoline that is used 
to produce conventional gasoline the refiner must include the volume and 
benzene content of the previously certified gasoline as a negative 
volume and a negative benzene content in the refiner's compliance 
calculations in accordance with the requirements at Sec. 80.1238.
    (iv) For each batch of conventional gasoline produced at the 
refinery using previously certified gasoline, the refiner must determine 
the volume and benzene content and include each batch in the refinery's 
compliance calculations at Sec. 80.1240 without regard to the presence 
of previously certified gasoline in the batch.
    (v) The refiner must use any previously certified gasoline that it 
includes as a negative batch in its compliance calculations pursuant to 
Sec. 80.1240 as a component in gasoline production during the annual 
averaging period in which the previously certified gasoline was included 
as a negative batch in the refiner's compliance calculations.
    (b) Batch numbering. The batch numbering convention of Sec. 
80.365(b) shall apply to batches of conventional gasoline beginning with 
earliest applicable date specified in paragraph (a)(2) of this section.



Sec. 80.1348  What gasoline sample retention requirements apply to 
refiners and importers?

    Beginning with earliest applicable date specified in Sec. 
80.1347(a)(2), the gasoline sample retention requirements specified in 
subpart H of this part for the gasoline sulfur provisions apply for the 
purpose of complying with the requirements of this subpart, except that 
in addition to including the sulfur test result as provided by Sec. 
80.335(a)(4)(ii), the refiner, importer, or independent laboratory shall 
also include with the retained sample the test result for benzene as 
conducted pursuant to Sec. 80.46(e).

                Recordkeeping and Reporting Requirements



Sec. 80.1350  What records must be kept?

    (a) General requirements. The recordkeeping requirements specified 
in Sec. Sec. 80.74 and 80.104, as applicable, apply for the purpose of 
complying with the requirements of this subpart; however, duplicate 
records are not required.
    (b) Additional records that refiners and importers shall keep. (1) 
Beginning with earliest applicable date specified in Sec. 
80.1347(a)(2), any refiner for each of its refineries, and any importer 
for the gasoline it imports, shall keep records that include the 
following information, as applicable:
    (i) Its compliance benzene value per Sec. 80.1240, and the 
calculations used to obtain that value.
    (ii) Its benzene baseline value, per Sec. 80.1280, if the refinery 
or importer submitted a benzene baseline application to EPA per Sec. 
80.1285.
    (iii) The number of early benzene credits generated under Sec. 
80.1275, separately by year of generation.
    (iv) The number of early benzene credits obtained, separately by 
generating refinery and year of generation.
    (v) The number of valid credits in possession of the refinery or 
importer at the beginning of each averaging period, separately by 
generating facility and year of generation.
    (vi) The number of standard credits generated by the refinery or 
importer under Sec. 80.1290, separately by transferor

[[Page 1072]]

(if applicable), by facility and by year of generation.
    (vii) The number of credits used, separately by generating facility 
and year of generation.
    (viii) If any credits were obtained from, or transferred to, other 
parties, for each other party, its name, its EPA refinery or importer 
registration number, and the number of credits obtained from, or 
transferred to, the other party, and the price per credit.
    (ix) The number of credits that expired at the end of each averaging 
period, separately by generating facility and year of generation.
    (x) The number of credits that will be carried over into a 
subsequent averaging period, separately by generating facility and year 
of generation.
    (xi) Contracts or other commercial documents that establish each 
transfer of credits from the transferor to the transferee.
    (xii) A copy of all reports submitted to EPA under Sec. Sec. 
80.1352 and 80.1354; however, duplicate records are not required.
    (2)(i) Beginning July 1, 2012, any refiner for each of its 
refineries, and any importer for the gasoline it imports, shall include, 
in the records required by paragraph (b)(1) of this section, its maximum 
average benzene value for the period July 1, 2012 through December 31, 
2013, and for each annual compliance period thereafter.
    (ii) Notwithstanding the requirements specified in paragraph 
(b)(2)(i) of this section, beginning July 1, 2016, a small refiner 
approved under Sec. 80.1340, for each of its refineries, shall include, 
in the records required by paragraph (b)(1) of this section, its maximum 
average benzene value for the period July 1, 2016 through December 31, 
2017, and for each annual compliance period thereafter.
    (3) Records of all supporting calculations pursuant to paragraphs 
(b)(1) or (b)(2) of this section shall also be kept.
    (c) Length of time records shall be kept. Records required in this 
section shall be kept for five years from the date they were created, 
except that records relating to credit transfers shall be kept by the 
transferor for five years from the date the credits were transferred, 
and shall be kept by the transferee for five years from the date the 
credits were transferred, used or terminated, whichever is later.
    (d) Make records available to EPA. On request by EPA, the records 
specified in this section shall be provided to the Administrator. For 
records that are electronically generated or maintained, the equipment 
and software necessary to read the records shall be made available, or 
upon approval by EPA, electronic records shall be converted to paper 
documents which shall be provided to the Administrator.



Sec. 80.1352  What are the pre-compliance reporting requirements for 
the gasoline benzene program?

    (a) Except as provided in paragraph (c) of this section, a refiner 
for each of its refineries shall submit the following information, as 
applicable, to EPA by June 1, 2008 and annually thereafter through June 
1, 2011, or through June 1, 2015 for small refiners approved under Sec. 
80.1340:
    (1) Changes to the information submitted in the company's 
registration;
    (2) Changes to the information submitted for any refinery or import 
facility registration;
    (3) Gasoline production.
    (i) An estimate of the average daily volume (in gallons) of gasoline 
produced at each refinery. This estimate shall include RFG, RBOB, 
conventional gasoline and conventional gasoline blendstock that becomes 
finished gasoline solely upon the addition of oxygenate but shall 
exclude gasoline exempted pursuant to Sec. 80.1235.
    (ii) The volume estimates specified in paragraph (a)(3)(i) of this 
section must be provided for the periods of June 1, 2007 through 
December 31, 2007, and calendar years 2008 through 2015.
    (4) Benzene concentration. An estimate of the average gasoline 
benzene concentration corresponding to the time periods specified in 
paragraph (a)(3)(ii) of this section.
    (5) ABT participation. For each year through 2015, the following 
information related to crdits shall be provided to EPA, if applicable:
    (i) If the refinery is expecting to generate benzene credits per 
Sec. 80.1275 and/or Sec. 80.1290, the actual or estimated, as 
applicable, numbers of early credits

[[Page 1073]]

and standard credits expected to be generated.
    (ii) If the refinery is expecting to use benzene credits per Sec. 
80.1295, the actual or estimated, as applicable, numbers of early 
credits and standard credits expected to be banked, transferred or used 
to achieve compliance in accordance with Sec. 80.1240.
    (6) Information on any project schedule by quarter of known or 
projected completion date, by the stage of the project. See, for 
example, the five project phases described in EPA's June 2002 Highway 
Diesel Progress Review report (EPA420-R-02-016, http://www.epa.gov/otaq/
regs/hd2007/420r02016.pdf): Strategic planning, Planning and front-end 
engineering, Detailed engineering and permitting, Procurement and 
Construction, and Commissioning and startup.
    (7) Basic information regarding the selected technology pathway for 
compliance (e.g., precursor re-routing or other technologies, revamp vs. 
grassroots, etc.).
    (8) Whether capital commitments have been made or are projected to 
be made.
    (b) The pre-compliance reports due in 2008 and succeeding years must 
provide an update of the progress in each of these areas and include 
actual values where available.
    (c) The pre-compliance reporting requirements of this section do not 
apply to refineries that only produce products exempt from the 
requirements of this subpart per Sec. 80.1235(b).



Sec. 80.1354  What are the reporting requirements for the gasoline
benzene program?

    (a) Beginning with earliest applicable date specified in Sec. 
80.1347(a)(2), any refiner for each of its refineries, and any importer 
for the gasoline it imports, shall submit to EPA an Annual Gasoline 
Benzene Report that contains the information required in this section, 
and such other information as EPA may require for each applicable 
averaging period.
    (b) The Annual Gasoline Benzene Report shall contain the following 
information:
    (1) Benzene volume percent and volume of any RFG, RBOB, and 
conventional gasoline, separately by batch, produced by the refinery or 
imported, and the sum of the volumes and the volume-weighted benzene 
concentration, in volume percent.
    (2)(i) The annual average benzene concentration, per Sec. 80.1238.
    (ii) The maximum average benzene concentration per Sec. 80.1240(b).
    (3) Any benzene deficit from the previous reporting period, per 
Sec. 80.1230(b).
    (4) The number of banked benzene credits from the previous reporting 
period.
    (5) The number of benzene credits generated under Sec. 80.1275, if 
applicable.
    (6) The number of benzene credits generated under Sec. 80.1290, if 
applicable.
    (7) The number of benzene credits transferred to the refinery or 
importer, per Sec. 80.1295(c), and the cost of the credits, if 
applicable.
    (8) The number of benzene credits transferred from the refinery or 
importer, per Sec. 80.1295(c), and the price of the credits, if 
applicable.
    (9) The number of benzene credits terminated or expired.
    (10) The compliance benzene value per Sec. 80.1240.
    (11) The number of banked benzene credits.
    (12) Projected credit generation through compliance year 2015.
    (13) Projected credit use through compliance year 2015.
    (c) EPA may require submission of additional information to verify 
compliance with the requirements of this subpart.
    (d) The report required by paragraph (a) of this section shall be--
    (1) Submitted on forms and following procedures specified by the 
Administrator.
    (2) Submitted to EPA by the last day of February each year for the 
prior calendar year averaging period.
    (3) Signed and certified as correct by the owner or a responsible 
corporate officer of the refiner or importer.

                           Attest Engagements



Sec. 80.1356  What are the attest engagement requirements for
gasoline benzene compliance?

    In addition to the requirements for attest engagements that apply to 
refiners and importers under Sec. Sec. 80.125

[[Page 1074]]

through 80.130, 80.410, and 80.1030, the attest engagements for refiners 
and importers must include the following:
    (a) EPA Early Credit Generation Baseline Years' Reports. (1) Obtain 
and read a copy of the refinery's or importer's annual reports and batch 
reports filed with EPA for 2004 and 2005 that contain gasoline benzene 
and gasoline volume information.
    (2) Agree the yearly volumes of gasoline and benzene concentration, 
in volume percent and benzene gallons, reported to EPA in the reports 
specified in paragraph (a)(1) of this section with the inventory 
reconciliation analysis under Sec. 80.128.
    (3) Verify that the information in the refinery's or importer's 
batch reports filed with EPA under Sec. Sec. 80.75 and 80.105, and any 
laboratory test results, agree with the information contained in the 
reports specified in paragraph (a)(1) of this section.
    (4) Calculate the average benzene concentration for all of the 
refinery's or importer's gasoline volume over 2004 and 2005 and verify 
that those values agree with the values reported to EPA per Sec. 
80.1285.
    (b) Baseline for Early Credit Generation. Take the following steps 
for the first attest reporting period following approval of a benzene 
baseline:
    (1) Obtain the EPA benzene baseline approval letter for the refinery 
to determine the refinery's applicable benzene baseline under Sec. 
80.1285.
    (2) Obtain a written statement from the company representative 
identifying the benzene value used as the refinery's baseline and agree 
that number to paragraph (b)(1) of this section and to the reports to 
EPA.
    (c) Early Credit Generation. The following procedures shall be 
completed for a refinery or importer that generates early benzene 
credits per Sec. 80.1275:
    (1) Obtain the baseline benzene concentration and gasoline volume 
from paragraph (a)(4) of this section.
    (2) Obtain the annual benzene report per Sec. 80.1354.
    (3) If the benzene value under paragraph (c)(2) of this section is 
at least 10 percent less than the value in paragraph (c)(1) of this 
section, compute and report as a finding the difference according to 
Sec. 80.1275.
    (4) Compute and report as a finding the total number of benzene 
credits generated by multiplying the value calculated in paragraph 
(c)(3) of this section by the volume of gasoline listed in the report 
specified in paragraph (c)(2) of this section, and agree this number 
with the number reported to EPA.
    (d) Standard Credit Generation. The following procedures shall be 
completed for a refinery or importer that generates benzene credits per 
Sec. 80.1290:
    (1) Obtain the annual average benzene value from the annual benzene 
report per Sec. 80.1285.
    (2) If the annual average benzene value under paragraph (d)(1) of 
this section is less than 0.62 percent by volume, compute and report as 
a finding the difference according to Sec. 80.1290.
    (3) Compute and report as a finding the total number of benzene 
credits generated by multiplying the value calculated in paragraph 
(d)(2) of this section by the volume of gasoline listed in the report 
specified in paragraph (d)(1) of this section, and agree this number 
with the number reported to EPA.
    (e) Credits Required. The following attest procedures shall be 
completed for refineries and importers:
    (1) Obtain the annual average benzene concentration and volume from 
the annual benzene report per Sec. 80.1285.
    (2) If the value in paragraph (e)(1) of this section is greater than 
0.62 percent by volume, compute and report as a finding the difference 
between 0.62 percent by volume and the value in paragraph (e)(1) of this 
section.
    (3) Compute and report as a finding the total benzene credits 
required by multiplying the value in paragraph (e)(2) of this section 
times the volume of gasoline in paragraph (e)(1) of this section, and 
agree this number with the report to EPA.
    (4) Obtain a statement from the refiner or importer as to the 
portion of the deficit under paragraph (e)(3) of this section that was 
resolved with credits, or that was carried forward as a deficit under 
Sec. 80.1230(b), and agree these figures with the report to EPA.

[[Page 1075]]

    (f) Credit Purchases and Sales. The following attest procedures 
shall be completed for a refinery or importer that is a transferor or 
transferee of credits during an averaging period:
    (1) Obtain contracts or other documents for all credits transferred 
to another refinery or importer during the year being reviewed; compute 
and report as a finding the number and year of creation of credits 
represented in these documents as being transferred; and agree these 
figures with the report to EPA.
    (2) Obtain contracts or other documents for all credits received 
during the year being reviewed; compute and report as a finding the 
number and year of creation of credits represented in these documents as 
being received; and agree with the report to EPA.
    (g) Credit Reconciliation. The following attest procedures shall be 
completed each year credits were in the refiner's or importer's 
possession at any time during the year:
    (1) Obtain the credits remaining or the credit deficit from the 
previous year from the refiner's or importer's report to EPA for the 
previous year.
    (2) Compute and report as a finding the net credits remaining at the 
conclusion of the year being reviewed by totaling credits as follows:
    (i) Credits remaining from the previous year; plus
    (ii) Credits generated under paragraphs (c) and (d) of this section; 
plus
    (iii) Credits purchased under paragraph (f) of this section; minus
    (iv) Credits sold under paragraph (f) of this section; minus
    (v) Credits used under paragraphs (e) of this section; minus
    (vi) Credits expired; minus
    (vii) Credit deficit from the previous year.
    (3) Agree the credits remaining or the credit deficit at the 
conclusion of the year being reviewed with the report to EPA.
    (4) If the refinery or importer had a credit deficit for both the 
previous year and the year being reviewed, report this fact as a 
finding.

                        Violations and Penalties



Sec. 80.1358  What acts are prohibited under the gasoline 
benzene program?

    No person shall--
    (a)(1) Produce or import gasoline subject to this subpart that does 
not comply with the applicable benzene standards under Sec. 80.1230.
    (2) Fail to meet any other requirements of this subpart.
    (b) Cause another person to commit an act in violation of paragraph 
(a) of this section.



Sec. 80.1359  What evidence may be used to determine compliance with
the prohibitions and requirements of this subpart and liability

for violations of this 
          subpart?

    (a) Compliance with the benzene standards of this subpart shall be 
determined based on the benzene concentration of the gasoline, measured 
using the methodologies specified in Sec. 80.46(e), and other allowable 
adjustments. Any evidence or information, including the exclusive use of 
such evidence or information, may be used to establish the benzene 
concentration of the gasoline if the evidence or information is relevant 
to whether the benzene concentration of the gasoline would have been in 
compliance with the standard if the appropriate sampling and testing 
methodologies had been correctly performed. Such evidence may be 
obtained from any source or location and may include, but is not limited 
to, test results using methods other than those specified in Sec. 
80.46(e), business records, and commercial documents.
    (b) Determinations of compliance with the requirements of this 
subpart other than the benzene standards, and determinations of 
liability for any violation of this subpart, may be based on information 
from any source or location. Such information may include, but is not 
limited to, business records and commercial documents.



Sec. 80.1360  Who is liable for violations under the gasoline benzene program?

    (a) The following persons are liable for violations of prohibited 
acts:

[[Page 1076]]

    (1) Any refiner or importer that violates Sec. 80.1358(a) is liable 
for the violation.
    (2) Any person that causes another party to violate Sec. 80.1358(a) 
is liable for a violation of Sec. 80.1358(b).
    (3) Any parent corporation is liable for any violations of this 
subpart that are committed by any of its wholly-owned subsidiaries.
    (4) Each partner to a joint venture, or each owner of a facility 
owned by two or more owners, is jointly and severally liable for any 
violation of this subpart that occurs at the joint venture facility or a 
facility that is owned by the joint owners, or a facility that is 
committed by the joint venture operation or any of the joint owners of 
the facility.
    (b) Any person who violates Sec. 80.1358 is liable for the 
violation.



Sec. 80.1361  What penalties apply under the gasoline benzene program?

    (a) Any person liable for a violation under Sec. 80.1360 is subject 
to civil penalties as specified in sections 205 and 211(d) of the Clean 
Air Act for every day of each such violation and the amount of economic 
benefit or savings resulting from each violation.
    (b) Any person liable under Sec. 80.1358(a) and (b) for a violation 
of the applicable benzene standards or causing another person to violate 
the requirements during any averaging period, is subject to a separate 
day of violation for each and every day in the averaging period. Any 
person liable under Sec. 80.1360(b) for a failure to fulfill any 
requirement of credit generation, transfer, use, banking, or deficit 
carry-forward correction is subject to a separate violation for each and 
every day in the averaging period in which invalid credits are 
generated, banked, transferred or used.
    (c) Any person liable under Sec. 80.1360(b) for failure to meet, or 
causing a failure to meet, a provision of this subpart is liable for a 
separate day of violation for each and every day such provision remains 
unfulfilled.

                            Foreign Refiners



Sec. 80.1363  What are the additional requirements under this subpart
for gasoline produced at foreign refineries?

    (a) Definitions.
    (1) A foreign refinery is a refinery that is located outside the 
United States, the Commonwealth of Puerto Rico, the Virgin Islands, 
Guam, American Samoa, and the Commonwealth of the Northern Mariana 
Islands (collectively referred to in this section as ``the United 
States'').
    (2) A foreign refiner is a person that meets the definition of 
refiner under Sec. 80.2(i) for a foreign refinery.
    (3) Benzene-FRGAS means gasoline produced at a foreign refinery that 
has been assigned an individual refinery benzene baseline under Sec. 
80.1285, has been approved as a small refiner under Sec. 80.1340, or 
has been granted temporary relief under Sec. 80.1335, and that is 
imported into the United States.
    (4) Non-Benzene-FRGAS means
    (i) Gasoline meeting any of the conditions specified in paragraph 
(a)(3) of this section that is not imported into the United States.
    (ii) Gasoline meeting any of the conditions specified in paragraph 
(a)(3) of this section during a year when the foreign refiner has opted 
to not participate in the Benzene-FRGAS program under paragraph (c)(3) 
of this section.
    (iii) Gasoline produced at a foreign refinery that has not been 
assigned an individual refinery benzene baseline under Sec. 80.1285, or 
that has not been approved as a small refiner under Sec. 80.1340, or 
that has not been granted temporary relief under Sec. 80.1335.
    (5) Certified Benzene-FRGAS means Benzene-FRGAS the foreign refiner 
intends to include in the foreign refinery's benzene compliance 
calculations under Sec. 80.1240 or credit calculations under Sec. 
80.1275 and does include in these calculations when reported to EPA.
    (6) Non-Certified Benzene-FRGAS means Benzene-FRGAS that is not 
Certified Benzene-FRGAS.
    (b) Baseline for Early Credits. For any foreign refiner to obtain 
approval under the benzene foreign refiner program of this subpart for 
any refinery in order to generate early credits under Sec. 80.1275, it 
must apply for approval

[[Page 1077]]

under the applicable provisions of this subpart.
    (1) The refiner shall follow the procedures specified in Sec. Sec. 
80.1280 and 80.1285 to establish a baseline of the volume of gasoline 
that was produced at the refinery and imported into the United States 
during the applicable years.
    (2) In making determinations for foreign refinery baselines EPA will 
consider all information supplied by a foreign refiner, and in addition 
may rely on any and all appropriate assumptions necessary to make such 
determinations.
    (3) Where a foreign refiner submits a petition that is incomplete or 
inadequate to establish an accurate baseline, and the refiner fails to 
correct this deficiency after a request for more information, EPA will 
not assign an individual refinery baseline.
    (c) General requirements for Benzene-FRGAS foreign refiners. A 
foreign refiner of a refinery that is approved under the benzene foreign 
refiner program of this subpart must designate each batch of gasoline 
produced at the foreign refinery that is exported to the United States 
as either Certified Benzene-FRGAS or as Non-Certified Benzene-FRGAS, 
except as provided in paragraph (c)(3) of this section.
    (1) In the case of Certified Benzene-FRGAS, the foreign refiner must 
meet all requirements that apply to refiners under this subpart.
    (2) In the case of Non-Certified Benzene-FRGAS, the foreign refiner 
shall meet all the following requirements:
    (i) The designation requirements in this section;
    (ii) The recordkeeping requirements in this section and in Sec. 
80.1350;
    (iii) The reporting requirements in this section and in Sec. Sec. 
80.1352 and 80.1354;
    (iv) The product transfer document requirements in this section;
    (v) The prohibitions in this section and in Sec. 80.1358; and
    (vi) The independent audit requirements in this section and in Sec. 
80.1356.
    (3)(i) Any foreign refiner that generates early benzene credits 
under Sec. 80.1275 shall designate all Benzene-FRGAS as Certified 
Benzene-FRGAS for any year that such credits are generated.
    (ii) Any foreign refiner that has been approved to produce gasoline 
subject to the benzene foreign refiner program for a foreign refinery 
under this subpart may elect to classify no gasoline imported into the 
United States as Benzene-FRGAS provided the foreign refiner notifies EPA 
of the election no later than November 1 preceding the beginning of the 
next compliance period.
    (iii) An election under paragraph (c)(3)(ii) of this section shall 
be for a 12 month compliance period and apply to all gasoline that is 
produced by the foreign refinery that is imported into the United 
States, and shall remain in effect for each succeeding year unless and 
until the foreign refiner notifies EPA of the termination of the 
election. The change in election shall take effect at the beginning of 
the next annual compliance period.
    (d) Designation, product transfer documents, and foreign refiner 
certification. (1) Any foreign refiner of a foreign refinery that has 
been approved by EPA to produce gasoline subject to the benzene foreign 
refiner program must designate each batch of Benzene-FRGAS as such at 
the time the gasoline is produced, unless the refiner has elected to 
classify no gasoline exported to the United States as Benzene-FRGAS 
under paragraph (c)(3) of this section.
    (2) On each occasion when any person transfers custody or title to 
any Benzene-FRGAS prior to its being imported into the United States, it 
must include the following information as part of the product transfer 
document information:
    (i) Designation of the gasoline as Certified Benzene-FRGAS or as 
Non-Certified Benzene-FRGAS; and
    (ii) The name and EPA refinery registration number of the refinery 
where the Benzene-FRGAS was produced.
    (3) On each occasion when Benzene-FRGAS is loaded onto a vessel or 
other transportation mode for transport to the United States, the 
foreign refiner shall prepare a certification for each batch of the 
Benzene-FRGAS that meets the following requirements.
    (i) The certification shall include the report of the independent 
third party under paragraph (f) of this section, and the following 
additional information:

[[Page 1078]]

    (A) The name and EPA registration number of the refinery that 
produced the Benzene-FRGAS;
    (B) The identification of the gasoline as Certified Benzene-FRGAS or 
Non-Certified Benzene-FRGAS;
    (C) The volume of Benzene-FRGAS being transported, in gallons;
    (D) In the case of Certified Benzene-FRGAS:
    (1) The benzene content as determined under paragraph (f) of this 
section, and the applicable designations stated in paragraph (d)(2)(i) 
of this section; and
    (2) A declaration that the Benzene-FRGAS is being included in the 
applicable compliance calculations required by EPA under this subpart.
    (ii) The certification shall be made part of the product transfer 
documents for the Benzene-FRGAS.
    (e) Transfers of Benzene-FRGAS to non-United States markets. The 
foreign refiner is responsible to ensure that all gasoline classified as 
Benzene-FRGAS is imported into the United States. A foreign refiner may 
remove the Benzene-FRGAS classification, and the gasoline need not be 
imported into the United States, but only if:
    (1) The foreign refiner excludes:
    (i) The volume of gasoline from the refinery's compliance report 
under Sec. 80.1354; and
    (ii) In the case of Certified Benzene-FRGAS, the volume of the 
gasoline from the compliance report under Sec. 80.1354.
    (2) The foreign refiner obtains sufficient evidence in the form of 
documentation that the gasoline was not imported into the United States.
    (f) Load port independent sampling, testing and refinery 
identification.
    (1) On each occasion that Benzene-FRGAS is loaded onto a vessel for 
transport to the United States a foreign refiner shall have an 
independent third party:
    (i) Inspect the vessel prior to loading and determine the volume of 
any tank bottoms;
    (ii) Determine the volume of Benzene-FRGAS loaded onto the vessel 
(exclusive of any tank bottoms before loading);
    (iii) Obtain the EPA-assigned registration number of the foreign 
refinery;
    (iv) Determine the name and country of registration of the vessel 
used to transport the Benzene-FRGAS to the United States; and
    (v) Determine the date and time the vessel departs the port serving 
the foreign refinery.
    (2) On each occasion that Certified Benzene-FRGAS is loaded onto a 
vessel for transport to the United States a foreign refiner shall have 
an independent third party:
    (i) Collect a representative sample of the Certified Benzene-FRGAS 
from each vessel compartment subsequent to loading on the vessel and 
prior to departure of the vessel from the port serving the foreign 
refinery;
    (ii) Determine the benzene content value for each compartment using 
the methodology as specified in Sec. 80.46(e) by one of the following:
    (A) The third party analyzing each sample; or
    (B) The third party observing the foreign refiner analyze the 
sample;
    (iii) Review original documents that reflect movement and storage of 
the Certified Benzene-FRGAS from the refinery to the load port, and from 
this review determine:
    (A) The refinery at which the Benzene-FRGAS was produced; and
    (B) That the Benzene-FRGAS remained segregated from:
    (1) Non-Benzene-FRGAS and Non-Certified Benzene-FRGAS; and
    (2) Other Certified Benzene-FRGAS produced at a different refinery.
    (3) The independent third party shall submit a report:
    (i) To the foreign refiner containing the information required under 
paragraphs (f)(1) and (f)(2) of this section, to accompany the product 
transfer documents for the vessel; and
    (ii) To the Administrator containing the information required under 
paragraphs (f)(1) and (f)(2) of this section, within thirty days 
following the date of the independent third party's inspection. This 
report shall include a description of the method used to determine the 
identity of the refinery at which the gasoline was produced, assurance 
that the gasoline remained

[[Page 1079]]

segregated as specified in paragraph (n)(1) of this section, and a 
description of the gasoline's movement and storage between production at 
the source refinery and vessel loading.
    (4) The independent third party must:
    (i) Be approved in advance by EPA, based on a demonstration of 
ability to perform the procedures required in this paragraph (f);
    (ii) Be independent under the criteria specified in Sec. 
80.65(f)(2)(iii); and
    (iii) Sign a commitment that contains the provisions specified in 
paragraph (i) of this section with regard to activities, facilities and 
documents relevant to compliance with the requirements of this paragraph 
(f).
    (g) Comparison of load port and port of entry testing. (1)(i) Any 
foreign refiner and any United States importer of Certified Benzene-
FRGAS shall compare the results from the load port testing under 
paragraph (f) of this section, with the port of entry testing as 
reported under paragraph (o) of this section, for the volume of gasoline 
and the benzene content value; except as specified in paragraph 
(g)(1)(ii) of this section.
    (ii) Where a vessel transporting Certified Benzene-FRGAS off loads 
this gasoline at more than one United States port of entry, and the 
conditions of paragraph (g)(2)(i) of this section are met at the first 
United States port of entry, the requirements of paragraph (g)(2) of 
this section do not apply at subsequent ports of entry if the United 
States importer obtains a certification from the vessel owner that meets 
the requirements of paragraph (s) of this section, that the vessel has 
not loaded any gasoline or blendstock between the first United States 
port of entry and the subsequent port of entry.
    (2)(i) The requirements of this paragraph (g)(2) apply if--
    (A) The temperature-corrected volumes determined at the port of 
entry and at the load port differ by more than one percent; or
    (B) The benzene content value determined at the port of entry is 
higher than the benzene content value determined at the load port, and 
the amount of this difference is greater than the reproducibility amount 
specified for the port of entry test result by the American Society of 
Testing and Materials (ASTM) for the test method specified at Sec. 
80.46(e).
    (ii) The United States importer and the foreign refiner shall treat 
the gasoline as Non-Certified Benzene-FRGAS, and the foreign refiner 
shall exclude the gasoline volume from its gasoline volumes calculations 
and benzene standard designations under this subpart.
    (h) Attest requirements. Refiners, for each annual compliance 
period, must arrange to have an attest engagement performed of the 
underlying documentation that forms the basis of any report required 
under this subpart. The attest engagement must comply with the 
procedures and requirements that apply to refiners under Sec. Sec. 
80.125 through 80.130, Sec. 80.1356, and other applicable attest 
engagement provisions, and must be submitted to the Administrator of EPA 
for the prior annual compliance period within the time period required 
under Sec. 80.130. The following additional procedures shall be carried 
out for any foreign refiner of Benzene-FRGAS.
    (1) The inventory reconciliation analysis under Sec. 80.128(b) and 
the tender analysis under Sec. 80.128(c) shall include Non-Benzene-
FRGAS.
    (2) Obtain separate listings of all tenders of Certified Benzene-
FRGAS and of Non-Certified Benzene-FRGAS, and obtain separate listings 
of Certified Benzene-FRGAS based on whether it is small refiner 
gasoline, gasoline produced through the use of credits, or other 
applicable designation under this subpart. Agree the total volume of 
tenders from the listings to the gasoline inventory reconciliation 
analysis in Sec. 80.128(b), and to the volumes determined by the third 
party under paragraph (f)(1) of this section.
    (3) For each tender under paragraph (h)(2) of this section, where 
the gasoline is loaded onto a marine vessel, report as a finding the 
name and country of registration of each vessel, and the volumes of 
Benzene-FRGAS loaded onto each vessel.
    (4) Select a sample from the list of vessels identified in paragraph 
(h)(3) of this section used to transport Certified Benzene-FRGAS, in 
accordance with the guidelines in Sec. 80.127, and for each vessel 
selected perform the following:

[[Page 1080]]

    (i) Obtain the report of the independent third party, under 
paragraph (f) of this section, and of the United States importer under 
paragraph (o) of this section.
    (A) Agree the information in these reports with regard to vessel 
identification, gasoline volumes and benzene content test results.
    (B) Identify, and report as a finding, each occasion the load port 
and port of entry benzene content and volume results differ by more than 
the amounts allowed in paragraph (g) of this section, and determine 
whether the foreign refiner adjusted its refinery calculations as 
required in paragraph (g) of this section.
    (ii) Obtain the documents used by the independent third party to 
determine transportation and storage of the Certified Benzene-FRGAS from 
the refinery to the load port, under paragraph (f) of this section. 
Obtain tank activity records for any storage tank where the Certified 
Benzene-FRGAS is stored, and pipeline activity records for any pipeline 
used to transport the Certified Benzene-FRGAS, prior to being loaded 
onto the vessel. Use these records to determine whether the Certified 
Benzene-FRGAS was produced at the refinery that is the subject of the 
attest engagement, and whether the Certified Benzene-FRGAS was mixed 
with any Non-Certified Benzene-FRGAS, Non-Benzene-FRGAS, or any 
Certified Benzene-FRGAS produced at a different refinery.
    (5) Select a sample from the list of vessels identified in paragraph 
(h)(3) of this section used to transport Certified and Non-Certified 
Benzene-FRGAS, in accordance with the guidelines in Sec. 80.127, and 
for each vessel selected perform the following:
    (i) Obtain a commercial document of general circulation that lists 
vessel arrivals and departures, and that includes the port and date of 
departure of the vessel, and the port of entry and date of arrival of 
the vessel.
    (ii) Agree the vessel's departure and arrival locations and dates 
from the independent third party and United States importer reports to 
the information contained in the commercial document.
    (6) Obtain separate listings of all tenders of Non-Benzene-FRGAS, 
and perform the following:
    (i) Agree the total volume and benzene content of tenders from the 
listings to the gasoline inventory reconciliation analysis in Sec. 
80.128(b).
    (ii) Obtain a separate listing of the tenders under this paragraph 
(h)(6) where the gasoline is loaded onto a marine vessel. Select a 
sample from this listing in accordance with the guidelines in Sec. 
80.127, and obtain a commercial document of general circulation that 
lists vessel arrivals and departures, and that includes the port and 
date of departure and the ports and dates where the gasoline was off 
loaded for the selected vessels. Determine and report as a finding the 
country where the gasoline was off loaded for each vessel selected.
    (7) In order to complete the requirements of this paragraph (h) an 
auditor shall:
    (i) Be independent of the foreign refiner;
    (ii) Be licensed as a Certified Public Accountant in the United 
States and a citizen of the United States, or be approved in advance by 
EPA based on a demonstration of ability to perform the procedures 
required in Sec. Sec. 80.125 through 80.130 and this paragraph (h); and
    (iii) Sign a commitment that contains the provisions specified in 
paragraph (i) of this section with regard to activities and documents 
relevant to compliance with the requirements of Sec. Sec. 80.125 
through 80.130 and this paragraph (h).
    (i) Foreign refiner commitments. Any foreign refiner shall commit to 
and comply with the provisions contained in this paragraph (i) as a 
condition to being approved as a foreign refiner under this subpart.
    (1) Any United States Environmental Protection Agency inspector or 
auditor must be given full, complete and immediate access to conduct 
inspections and audits of the foreign refinery.
    (i) Inspections and audits may be either announced in advance by 
EPA, or unannounced.
    (ii) Access will be provided to any location where:
    (A) Gasoline is produced;

[[Page 1081]]

    (B) Documents related to refinery operations are kept;
    (C) Gasoline or blendstock samples are tested or stored; and
    (D) Benzene-FRGAS is stored or transported between the foreign 
refinery and the United States, including storage tanks, vessels and 
pipelines.
    (iii) Inspections and audits may be by EPA employees or contractors 
to EPA.
    (iv) Any documents requested that are related to matters covered by 
inspections and audits must be provided to an EPA inspector or auditor 
on request.
    (v) Inspections and audits by EPA may include review and copying of 
any documents related to:
    (A) Refinery baseline establishment, if applicable, including the 
volume and benzene content of gasoline; transfers of title or custody of 
any gasoline or blendstocks whether Benzene-FRGAS or Non-Benzene-FRGAS, 
produced at the foreign refinery during the period January 1, 2004 
through December 31, 2005, and any work papers related to refinery 
baseline establishment;
    (B) The volume and benzene content of Benzene-FRGAS;
    (C) The proper classification of gasoline as being Benzene-FRGAS or 
as not being Benzene-FRGAS, or as Certified Benzene-FRGAS or as Non-
Certified Benzene-FRGAS, and all other relevant designations under this 
subpart;
    (D) Transfers of title or custody to Benzene-FRGAS;
    (E) Sampling and testing of Benzene-FRGAS;
    (F) Work performed and reports prepared by independent third parties 
and by independent auditors under the requirements of this section, 
including work papers; and
    (G) Reports prepared for submission to EPA, and any work papers 
related to such reports.
    (vi) Inspections and audits by EPA may include taking samples of 
gasoline, gasoline additives or blendstock, and interviewing employees.
    (vii) Any employee of the foreign refiner must be made available for 
interview by the EPA inspector or auditor, on request, within a 
reasonable time period.
    (viii) English language translations of any documents must be 
provided to an EPA inspector or auditor, on request, within 10 working 
days.
    (ix) English language interpreters must be provided to accompany EPA 
inspectors and auditors, on request.
    (2) An agent for service of process located in the District of 
Columbia shall be named, and service on this agent constitutes service 
on the foreign refiner or any employee of the foreign refiner for any 
action by EPA or otherwise by the United States related to the 
requirements of this subpart.
    (3) The forum for any civil or criminal enforcement action related 
to the provisions of this section for violations of the Clean Air Act or 
regulations promulgated thereunder shall be governed by the Clean Air 
Act, including the EPA administrative forum where allowed under the 
Clean Air Act.
    (4) United States substantive and procedural laws shall apply to any 
civil or criminal enforcement action against the foreign refiner or any 
employee of the foreign refiner related to the provisions of this 
section.
    (5) Submitting a petition for participation in the benzene foreign 
refiner program or producing and exporting gasoline under any such 
program, and all other actions to comply with the requirements of this 
subpart relating to participation in any benzene foreign refiner 
program, or to establish an individual refinery gasoline benzene 
baseline under this subpart constitute actions or activities covered by 
and within the meaning of the provisions of 28 U.S.C. 1605(a)(2), but 
solely with respect to actions instituted against the foreign refiner, 
its agents and employees in any court or other tribunal in the United 
States for conduct that violates the requirements applicable to the 
foreign refiner under this subpart, including conduct that violates the 
False Statements Accountability Act of 1996 (18 U.S.C. 1001) and section 
113(c)(2) of the Clean Air Act (42 U.S.C. 7413).
    (6) The foreign refiner, or its agents or employees, will not seek 
to detain or to impose civil or criminal remedies against EPA inspectors 
or auditors, whether EPA employees or EPA contractors, for actions 
performed within the scope of EPA employment related to the provisions 
of this section.

[[Page 1082]]

    (7) The commitment required by this paragraph (i) shall be signed by 
the owner or president of the foreign refiner business.
    (8) In any case where Benzene-FRGAS produced at a foreign refinery 
is stored or transported by another company between the refinery and the 
vessel that transports the Benzene-FRGAS to the United States, the 
foreign refiner shall obtain from each such other company a commitment 
that meets the requirements specified in paragraphs (i)(1) through (7) 
of this section, and these commitments shall be included in the foreign 
refiner's petition to participate in any benzene foreign refiner 
program.
    (j) Sovereign immunity. By submitting a petition for participation 
in any benzene foreign refiner program under this subpart (and baseline, 
if applicable) under this section, or by producing and exporting 
gasoline to the United States under any such program, the foreign 
refiner, and its agents and employees, without exception, become subject 
to the full operation of the administrative and judicial enforcement 
powers and provisions of the United States without limitation based on 
sovereign immunity, with respect to actions instituted against the 
foreign refiner, its agents and employees in any court or other tribunal 
in the United States for conduct that violates the requirements 
applicable to the foreign refiner under this subpart, including conduct 
that violates the False Statements Accountability Act of 1996 (18 U.S.C. 
1001) and section 113(c)(2) of the Clean Air Act (42 U.S.C. 7413).
    (k) Bond posting. Any foreign refiner shall meet the requirements of 
this paragraph (k) as a condition to approval as benzene foreign refiner 
under this subpart.
    (1) The foreign refiner shall post a bond of the amount calculated 
using the following equation:

Bond = G x $0.01

Where:

Bond = amount of the bond in U.S. dollars

G = the largest volume of gasoline produced at the foreign refinery and 
exported to the United States, in gallons, during a single calendar year 
among the most recent of the following calendar years, up to a maximum 
of five calendar years: the calendar year immediately preceding the date 
the refinery's baseline petition is submitted, the calendar year the 
baseline petition is submitted, and each succeeding calendar year.

    (2) Bonds shall be posted by:
    (i) Paying the amount of the bond to the Treasurer of the United 
States;
    (ii) Obtaining a bond in the proper amount from a third party surety 
agent that is payable to satisfy United States administrative or 
judicial judgments against the foreign refiner, provided EPA agrees in 
advance as to the third party and the nature of the surety agreement; or
    (iii) An alternative commitment that results in assets of an 
appropriate liquidity and value being readily available to the United 
States, provided EPA agrees in advance as to the alternative commitment.
    (3) Bonds posted under this paragraph (k) shall--
    (i) Be used to satisfy any judicial judgment that results from an 
administrative or judicial enforcement action for conduct in violation 
of this subpart, including where such conduct violates the False 
Statements Accountability Act of 1996 (18 U.S.C. 1001) and section 
113(c)(2) of the Clean Air Act (42 U.S.C. 7413);
    (ii) Be provided by a corporate surety that is listed in the United 
States Department of Treasury Circular 570 ``Companies Holding 
Certificates of Authority as Acceptable Sureties on Federal Bonds''; and
    (iii) Include a commitment that the bond will remain in effect for 
at least five years following the end of latest annual reporting period 
that the foreign refiner produces gasoline pursuant to the requirements 
of this subpart.
    (4) On any occasion a foreign refiner bond is used to satisfy any 
judgment, the foreign refiner shall increase the bond to cover the 
amount used within 90 days of the date the bond is used.
    (5) If the bond amount for a foreign refiner increases, the foreign 
refiner shall increase the bond to cover the shortfall within 90 days of 
the date the bond amount changes. If the bond amount decreases, the 
foreign refiner may reduce the amount of the bond beginning 90 days 
after the date the bond amount changes.

[[Page 1083]]

    (l) [Reserved]
    (m) English language reports. Any report or other document submitted 
to EPA by a foreign refiner shall be in English language, or shall 
include an English language translation.
    (n) Prohibitions. (1) No person may combine Certified Benzene-FRGAS 
with any Non-Certified Benzene-FRGAS or Non-Benzene-FRGAS, and no person 
may combine Certified Benzene-FRGAS with any Certified Benzene-FRGAS 
produced at a different refinery, until the importer has met all the 
requirements of paragraph (o) of this section, except as provided in 
paragraph (e) of this section.
    (2) No foreign refiner or other person may cause another person to 
commit an action prohibited in paragraph (n)(1) of this section, or that 
otherwise violates the requirements of this section.
    (o) United States importer requirements. Any United States importer 
shall meet the following requirements:
    (1) Each batch of imported gasoline shall be classified by the 
importer as being Benzene-FRGAS or as Non-Benzene-FRGAS, and each batch 
classified as Benzene-FRGAS shall be further classified as Certified 
Benzene-FRGAS or as Non-Certified Benzene-FRGAS.
    (2) Gasoline shall be classified as Certified Benzene-FRGAS or as 
Non-Certified Benzene-FRGAS according to the designation by the foreign 
refiner if this designation is supported by product transfer documents 
prepared by the foreign refiner as required in paragraph (d) of this 
section, unless the gasoline is classified as Non-Certified Benzene-
FRGAS under paragraph (g) of this section. Additionally, the importer 
shall comply with all requirements of this subpart applicable to 
importers.
    (3) For each gasoline batch classified as Benzene-FRGAS, any United 
States importer shall perform the following procedures.
    (i) In the case of both Certified and Non-Certified Benzene-FRGAS, 
have an independent third party:
    (A) Determine the volume of gasoline in the vessel;
    (B) Use the foreign refiner's Benzene-FRGAS certification to 
determine the name and EPA-assigned registration number of the foreign 
refinery that produced the Benzene-FRGAS;
    (C) Determine the name and country of registration of the vessel 
used to transport the Benzene-FRGAS to the United States; and
    (D) Determine the date and time the vessel arrives at the United 
States port of entry.
    (ii) In the case of Certified Benzene-FRGAS, have an independent 
third party:
    (A) Collect a representative sample from each vessel compartment 
subsequent to the vessel's arrival at the United States port of entry 
and prior to off loading any gasoline from the vessel;
    (B) Obtain the compartment samples; and
    (C) Determine the benzene content value of each compartment sample 
using the methodology specified at Sec. 80.46(e) by the third party 
analyzing the sample or by the third party observing the importer 
analyze the sample.
    (4) Any importer shall submit reports within 30 days following the 
date any vessel transporting Benzene-FRGAS arrives at the United States 
port of entry:
    (i) To the Administrator containing the information determined under 
paragraph (o)(3) of this section; and
    (ii) To the foreign refiner containing the information determined 
under paragraph (o)(3)(ii) of this section, and including identification 
of the port at which the product was offloaded.
    (5) Any United States importer shall meet all other requirements of 
this subpart for any imported gasoline that is not classified as 
Certified Benzene-FRGAS under paragraph (o)(2) of this section.
    (p) Truck imports of Certified Benzene-FRGAS produced at a foreign 
refinery.
    (1) Any refiner whose Certified Benzene-FRGAS is transported into 
the United States by truck may petition EPA to use alternative 
procedures to meet the following requirements:
    (i) Certification under paragraph (d)(5) of this section;
    (ii) Load port and port of entry sampling and testing under 
paragraphs (f) and (g) of this section;
    (iii) Attest under paragraph (h) of this section; and

[[Page 1084]]

    (iv) Importer testing under paragraph (o)(3) of this section.
    (2) These alternative procedures must ensure Certified Benzene-FRGAS 
remains segregated from Non-Certified Benzene-FRGAS and from Non-
Benzene-FRGAS until it is imported into the United States. The petition 
will be evaluated based on whether it adequately addresses the 
following:
    (i) Provisions for monitoring pipeline shipments, if applicable, 
from the refinery, that ensure segregation of Certified Benzene-FRGAS 
from that refinery from all other gasoline;
    (ii) Contracts with any terminals and/or pipelines that receive and/
or transport Certified Benzene-FRGAS, that prohibit the commingling of 
Certified Benzene-FRGAS with any of the following:
    (A) Other Certified Benzene-FRGAS from other refineries.
    (B) All Non-Certified Benzene-FRGAS.
    (C) All Non-Benzene-FRGAS;
    (iii) Procedures for obtaining and reviewing truck loading records 
and United States import documents for Certified Benzene-FRGAS to ensure 
that such gasoline is only loaded into trucks making deliveries to the 
United States;
    (iv) Attest procedures to be conducted annually by an independent 
third party that review loading records and import documents based on 
volume reconciliation, or other criteria, to confirm that all Certified 
Benzene-FRGAS remains segregated throughout the distribution system and 
is only loaded into trucks for import into the United States.
    (3) The petition required by this section must be submitted to EPA 
along with the application for temporary refiner relief individual 
refinery benzene standard under this subpart.
    (q) Withdrawal or suspension of foreign refiner status. EPA may 
withdraw or suspend a foreign refiner's benzene baseline or standard 
approval for a foreign refinery where--
    (1) A foreign refiner fails to meet any requirement of this section;
    (2) A foreign government fails to allow EPA inspections as provided 
in paragraph (i)(1) of this section;
    (3) A foreign refiner asserts a claim of, or a right to claim, 
sovereign immunity in an action to enforce the requirements in this 
subpart; or
    (4) A foreign refiner fails to pay a civil or criminal penalty that 
is not satisfied using the foreign refiner bond specified in paragraph 
(k) of this section.
    (r) Early use of a foreign refiner benzene baseline.
    (1) A foreign refiner may begin using an individual refinery benzene 
baseline under this subpart before EPA has approved the baseline, 
provided that:
    (i) A baseline petition has been submitted as required in paragraph 
(b) of this section;
    (ii) EPA has made a provisional finding that the baseline petition 
is complete;
    (iii) The foreign refiner has made the commitments required in 
paragraph (i) of this section;
    (iv) The persons that will meet the independent third party and 
independent attest requirements for the foreign refinery have made the 
commitments required in paragraphs (f)(3)(iii) and (h)(7)(iii) of this 
section; and
    (v) The foreign refiner has met the bond requirements of paragraph 
(k) of this section.
    (2) In any case where a foreign refiner uses an individual refinery 
baseline before final approval under paragraph (r)(1) of this section, 
and the foreign refinery baseline values that ultimately are approved by 
EPA are more stringent than the early baseline values used by the 
foreign refiner, the foreign refiner shall recalculate its compliance, 
ab initio, using the baseline values approved by the EPA, and the 
foreign refiner shall be liable for any resulting violation of the 
requirements of this subpart.
    (s) Additional requirements for petitions, reports and certificates. 
Any petition for approval to produce gasoline subject to the benzene 
foreign refiner program, any alternative procedures under paragraph (p) 
of this section, any report or other submission required by paragraph 
(c), (f)(2), or (i) of this section, and any certification under 
paragraph (d)(3) of this section shall be--

[[Page 1085]]

    (1) Submitted in accordance with procedures specified by the 
Administrator, including use of any forms that may be specified by the 
Administrator.
    (2) Be signed by the president or owner of the foreign refiner 
company, or by that person's immediate designee, and shall contain the 
following declaration:

    I hereby certify: (1) That I have actual authority to sign on behalf 
of and to bind [insert name of foreign refiner] with regard to all 
statements contained herein; (2) that I am aware that the information 
contained herein is being Certified, or submitted to the United States 
Environmental Protection Agency, under the requirements of 40 CFR part 
80, subpart L, and that the information is material for determining 
compliance under these regulations; and (3) that I have read and 
understand the information being Certified or submitted, and this 
information is true, complete and correct to the best of my knowledge 
and belief after I have taken reasonable and appropriate steps to verify 
the accuracy thereof. I affirm that I have read and understand the 
provisions of 40 CFR part 80, subpart L, including 40 CFR 80.1363 apply 
to [insert name of foreign refiner]. Pursuant to Clean Air Act section 
113(c) and 18 U.S.C. 1001, the penalty for furnishing false, incomplete 
or misleading information in this certification or submission is a fine 
of up to $10,000 U.S., and/or imprisonment for up to five years.



Sec. Appendix A to Part 80--Test for the Determination of Phosphorus in 
                                Gasoline

                                1. Scope.

    1.1 This method was developed for the determination of phosphorus 
generally present as pentavalent phosphate esters or salts, or both, in 
gasoline. This method is applicable for the determination of phosphorus 
in the range from 0.0008 to 0.15 g P/U.S. gal, or 0.2 to 49 mg P/liter.

                        2. Applicable documents.

    2.1 ASTM Standards:
    D 1100 Specification for Filter Paper for Use in Chemical Analysis.

                          3. Summary of method.

    3.1 Organic matter in the sample is decomposed by ignition in the 
presence of zinc oxide. The residue is dissolved in sulfuric acid and 
reacted with ammonium molybdate and hydrazine sulfate. The absorbance of 
the ``Molybdenum Blue'' complex is proportional to the phosphorus 
concentration in the sample and is read at approximately 820 nm in a 5-
cm cell.

                              4. Apparatus.

    4.1 Buret, 10-ml capacity, 0.05-ml subdivisions.
    4.2 Constant-Temperature Bath, equipped to hold several 100-ml 
volumetric flasks submerged to the mark. Bath must have a large enough 
reservoir or heat capacity to keep the temperature at 180 to 190 [deg]F 
(82.2 to 87.8 [deg]C) during the entire period of sample heating.

    Note 1: If the temperature of the hot water bath drops below 180 
[deg]F (82.2 [deg]C) the color development may not be complete.

    4.3 Cooling Bath, equipped to hold several 100-ml volumetric flasks 
submerged to the mark in ice water.
    4.4 Filter Paper, for quantitative analysis, Class G for fine 
precipitates as defined in Specification D 1100.
    4.5 Ignition Dish--Coors porcelain evaporating dish, glazed inside 
and outside, with pourout (size no. 00A, diameter 75 mm. capacity 70 
ml).
    4.6 Spectrophotometer, equipped with a tungsten lamp, a red-
sensitive phototube capable of operating at 830 nm and with absorption 
cells that have a 5-cm light path.
    4.7 Thermometer, range 50 to 220 [deg]F (10 to 105 [deg]C).
    4.8 Volumetric Flask, 100-ml with ground-glass stopper.
    4.9 Volumetric Flask, 1000-ml with ground-glass stopper.
    4.10 Syringe, Luer-Lok, 10-ml equipped with 5-cm. 22-gage needle.

                              5. Reagents.

    5.1 Purity of Reagents--Reagent grade chemicals shall be used in all 
tests. Unless otherwise indicated, it is intended that all reagents 
shall conform to the specifications of the Committee on Analytical 
Reagents of the American Chemical Society, where such specifications are 
available. Other grades may be used, provided it is first ascertained 
that the reagent is of sufficiently high purity to permit its use 
without lessening the accuracy of the determination.
    5.2 Purity of Water--Unless otherwise indicated, references to water 
shall be understood to mean distilled water or water of equal purity.
    5.3 Ammonium Molybdate Solution--Using graduated cylinders for 
measurement add slowly (Note 2), with continuous stirring, 225 ml of 
concentrated sulfuric acid to 500 ml of water contained in a beaker 
placed in a bath of cold water. Cool to room temperature and add 20 g of 
ammonium molybdate tetrahydrate ((NH4)6 
Mo7 O24[middot]4H2 O). Stir until 
solution is complete and transfer to a 1000-ml flask. Dilute to the mark 
with water.

    Note 2: Wear a face shield, rubber gloves, and a rubber apron when 
adding concentrated sulfuric acid to water.


[[Page 1086]]


    5.4 Hydrazine Sulfate Solution--Dissolve 1.5 of hydrazine sulfate 
(H2 NNH2[middot] H2 SO4) in 
1 litre of water, measured with a graduated cylinder.

    Note 3: This solution is not stable. Keep it tightly stoppered and 
in the dark. Prepare a fresh solution after 3 weeks.

    5.5 Molybdate-Hydrazine Reagent--Pipet 25 ml of ammonium molybdate 
solution into a 100-ml volumetric flask containing approximately 50 ml 
of water, add by pipet 10 ml of N2 NNH2[middot] 
H2 SO4 solution, and dilute to 100 ml with water.

    Note 4: This reagent is unstable and should be used within about 4 
h. Prepare it immediately before use. Each determination (including the 
blank) uses 50 ml.

    5.6 Phosphorus, Standard Solution (10.0 [micro]g P/ml)--Pipet 10 ml 
of stock standard phosphorus solution into a 1000-ml volumetric flask 
and dilute to the mark with water.
    5.7 Phosphorus, Stock Standard Solution (1.00 mg P/ml)--Dry 
approximately 5 g of potasium dihydrogen phosphate (KH2 
PO4 in an oven at 221 to 230 [deg]F (105 to 110 [deg]C) for 3 
h. Dissolve 4.393 0.002 g of the reagent in 150 
ml, measured with a graduated cylinder, of H2 
SO4(1+10) contained in a 1000-ml volumetric flask. Dilute 
with water to the mark.
    5.8 Sulfuric Acid (1+10)--Using graduated cylinders for measurement 
add slowly (Note 2), with continuous stirring, 100-ml of concentrated 
sulfuric acid (H2 SO4, sp gr 1.84) to 1 litre of 
water contained in a beaker placed in a bath of cold water.
    5.9 Zinc Oxide.

    Note 5: High-bulk density zinc oxide may cause spattering. Density 
of approximately 0.5 g/cm \3\ has been found satisfactory.

                             6. Calibration.

    6.1 Transfer by buret, or a volumetric transfer pipet, 0.0, 0.5, 
1.0, 1.5, 2.0, 3.0, 3.5, and 4.0 ml of phosphorus standard solution into 
100-ml volumetric flasks.
    6.2 Pipet 10 ml of H2 SO4 (1+10) into each 
flask. Mix immediately by swirling.
    6.3 Prepare the molybdate-hydrazine solution. Prepare sufficient 
volume of reagent based on the number of samples being analyzed.
    6.4 Pipet 50 ml of the molybdate-hydrazine solution to each 
volumetric flask. Mix immediately by swirling.
    6.5 Dilute to 100 ml with water.
    6.6 Mix well and place in the constant-temperature bath so that the 
contents of the flask are submerged below the level of the bath. 
Maintain bath temperature at 180 to 190 [deg]F (82.2 to 87.8 [deg]C) for 
25 min (Note 1).
    6.7 Transfer the flask to the cooling bath and cool the contents 
rapidly to room temperature. Do not allow the samples to cool more than 
5 [deg]F (2.8 [deg]C) below room temperature.

    Note 6: Place a chemically clean thermometer in one of the flasks to 
check the temperature.

    6.8 After cooling the flasks to room temperature, remove them from 
the cooling water bath and allow them to stand for 10 min. at room 
temperature.
    6.9 Using the 2.0-ml phosphorus standard in a 5-cm cell, determine 
the wavelength near 820 nm that gives maximum absorbance. The wavelength 
giving maximum absorbance should not exceed 830 nm.
    6.9.1 Using a red-sensitive phototube and 5-cm cells, adjust the 
spectrophotometer to zero absorbance at the wavelength of maximum 
absorbance using distilled water in both cells. Use the wavelength of 
maximum absorbance in the determination of calibration readings and 
future sample readings.
    6.9.2 The use of 1-cm cells for the higher concentrations is 
permissible.
    6.10 Measure the absorbance of each calibration sample including the 
blank (0.0 ml phosphorus standard) at the wavelength of maximum 
absorbance with distilled water in the reference cell.

    Note 7: Great care must be taken to avoid possible contamination. If 
the absorbance of the blank exceeds 0.04 (for 5-cm cell), check for 
source of contamination. It is suggested that the results be disregarded 
and the test be rerun with fresh reagents and clean glassware.

    6.11 Correct the absorbance of each standard solution by subtracting 
the absorbance of the blank (0 ml phosphorus standard).
    6.12 Prepare a calibration curve by plotting the corrected 
absorbance of each standard solution against micrograms of phosphorus. 
One millilitre of phosphorus standard solution provides 10 [micro]g of 
phosphorus.

                              7. Sampling.

    7.1 Selection of the size of the sample to be tested depends on the 
expected concentration of phosphorous in the sample. If a concentration 
of phosphorus is suspected to be less than 0.0038 g/gal (1.0 mg/litre), 
it will be necessary to use 10 ml of sample.

    Note 8: Two grams of zinc oxide cannot absorb this volume of 
gasoline. Therefore the 10-ml sample is ignited in aliquots of 2 ml in 
the presence of 2 g of zinc oxide.

    7.2 The following table serves as a guide for selecting sample size:

------------------------------------------------------------------------
                                                                Sample
  Phosphorus, milligrams per liter     Equivalent, grams per     size,
                                              gallon          milliliter
------------------------------------------------------------------------
2.5 to 40...........................  0.01 to 0.15..........        1.00
1.3 to 20...........................  0.005 to 0.075........        2.00
0.9 to 13...........................  0.0037 to 0.05........        3.00
1 or less...........................  0.0038 or less........       10.00
------------------------------------------------------------------------


[[Page 1087]]

                              8. Procedure.

    8.1 Transfer 2 0.2 g of zinc oxide into a 
conical pile in a clean, dry, unetched ignition dish.

    Note 9: In order to obtain satisfactory accuracy with the small 
amounts of phosphorus involved, it is necessary to take extensive 
precautions in handling. The usual precautions of cleanliness, careful 
manipulation, and avoidance of contamination should be scrupulously 
observed; also, all glassware should be cleaned before use, with 
cleaning acid or by some procedure that does not involve use of 
commercial detergents. These compounds often contain alkali phosphates 
which are strongly adsorbed by glass surfaces and are not removed by 
ordinary rinsing. It is desirable to segregate a special stock of 
glassware for use only in the determination of phosphorus.

    8.2 Make a deep depression in the center of the zinc oxide pile with 
a stirring rod.
    8.3 Pipet the gasoline sample (Note 10) (see 7.2 for suggested 
sample volume) into the depression in the zinc oxide. Record the 
temperature of the fuel if the phosphorus content is required at 60 
[deg]F (15.6 [deg]C) and make correction as directed in 9.2.

    Note 10: For the 10-ml sample use multiple additions and a syringe. 
Hold the tip of the needle at approximately \2/3\ of the depth of the 
zinc oxide layer and slowly deliver 2 ml of the sample: fast sample 
delivery may give low results. Give sufficient time for the gasoline to 
be absorbed by the zinc oxide. Follow step 8.6. Cool the dish to room 
temperature. Repeat steps 8.3 and 8.6 until all the sample has been 
burned. Safety--cool the ignition dish before adding the additional 
aliquots of gasoline to avoid a flash fire.

    8.4 Cover the sample with a small amount of fresh zinc oxide from 
reagent bottle (use the tip of a small spatula to deliver approximately 
0.2 g). Tap the sides of the ignition dish to pack the zinc oxide.
    8.5 Prepare the blank, using the same amount of zinc oxide in an 
ignition dish.
    8.6 Ignite the gasoline, using the flame from a bunsen burner. Allow 
the gasoline to burn to extinction (Note 10).
    8.7 Place the ignition dishes containing the sample and blank in a 
hot muffle furnace set at a temperature of 1150 to 1300 [deg]F (621 to 
704 [deg]C) for 10 min. Remove and cool the ignition dishes. When cool 
gently tap the sides of the dish to loosen the zinc oxide. Again place 
the dishes in the muffle furnace for 5 min. Remove and cool the ignition 
dishes to room temperature. The above treatment is usually sufficient to 
burn the carbon. If the carbon is not completely burned off place the 
dish into the oven for further 5-min. periods.

    Note 11: Step 8.7 may also be accomplished by heating the ignition 
dish with a Meker burner gradually increasing the intensity of heat 
until the carbon from the sides of the dish has been burned, then cool 
to room temperature.

    8.8 Pipet 25 ml of H2 SO4 (1+10) to each 
ignition dish. While pipeting, carefully wash all traces of zinc oxide 
from the sides of the ignition dish.
    8.9 Cover the ignition dish with a borosilicate watch glass and warm 
the ignition dish on a hot plate until the zinc oxide is completely 
dissolved.
    8.10 Transfer the solution through filter paper to a 100-ml 
volumetric flask. Rinse the watch glass and the dish several times with 
distilled water (do not exceed 25 ml) and transfer the washings through 
the filter paper to the volumetric flask.
    8.11 Prepare the molybdate-hydrazine solution.
    8.12 Add 50 ml of the molybdate-hydrazine solution by pipet to each 
100-ml volumetric flask. Mix immediately by swirling.
    8.13 Dilute to 100 ml with water and mix well. Remove stoppers from 
flasks after mixing.
    8.14 Place the 100-ml flasks in the constant-temperature bath for 25 
min. so that the contents of the flasks are below the liquid level of 
the bath. The temperature of the bath should be 180 to 190 [deg]F (82.2 
to 87.8 [deg]C) (Note 1).
    8.15 Transfer the 100-ml flasks to the cooling bath and cool the 
contents rapidly to room temperature (Note 6).
    8.16 Allow the samples to stand at room temperature before measuring 
the absorbance.

    Note 12: The color developed is stable for at least 4 h.

    8.17 Set the spectrophotometer to the wavelength of maximum 
absorbance as determined in 6.9. Adjust the spectrophotometer to zero 
absorbance, using distilled water in both cells.
    8.18 Measure the absorbance of the samples at the wavelength of 
maximum absorbance with distilled water in the reference cell.
    8.19 Subtract the absorbance of the blank from the absorbance of 
each sample (Note 7).
    8.20 Determine the micrograms of phosphorous in the sample, using 
the calibration curve from 6.12 and the corrected absorbance.

                            9. Calculations.

    9.1 Calculate the milligrams of phosphorus per litre of sample as 
follows:

P, mg/litre = P/V

where:

P = micrograms of phosphorus read from calibration curve, and
V = millilitres of gasoline sample.

To convert to grams of phosphorus per U.S. gallon of sample, multiply mg 
P/litre by 0.0038.

[[Page 1088]]

    9.2 If the gasoline sample was taken at a temperature other than 60 
[deg]F (15.6 [deg]C) make the following temperature correction:

mg P/litre at 15.6 [deg]C = [mg P/litre at t] [1+0.001 (t-15.6)]

where:

t = observed temperature of the gasoline, [deg]C.

    9.3 Concentrations below 2.5 mg/litre or 0.01 g/gal should be 
reported to the nearest 0.01 mg/litre or 0.0001 g/U.S. gal.
    9.3.1 For higher concentrations, report results to the nearest 1 mg 
P/litre or 0.005 g P/U.S. gal.

                             10. Precision.

    10.1 The following criteria should be used for judging the 
acceptability of results (95 percent confidence):
    10.2 Repeatability--Duplicate results by the same operator should be 
considered suspect if they differ by more than the following amounts:

------------------------------------------------------------------------
     g P/U.S. gal (mg[middot]P/litre)               Repeatability
------------------------------------------------------------------------
0.0008 to 0.005 (0.2 to 1.3)..............  0.0002 g P/U.S. gal (0.05 mg
                                             P/litre).
0.005 to 0.15 (1.3 to 40).................  7% of the mean.
------------------------------------------------------------------------

    10.3 Reproducibility--The results submitted by each of two 
laboratories should not be considered suspect unless they differ by more 
than the following amounts:

------------------------------------------------------------------------
     g P/U.S. gal (mg[middot]P/litre)              Reproducibility
------------------------------------------------------------------------
0.0008 to 0.005 (0.2 to 1.3)..............  0.0005 g P/U.S. gal (0.13 mg
                                             P/litre).
0.005 to 0.15 (1.3 to 40).................  13% of the mean.
------------------------------------------------------------------------


[39 FR 24891, July 8, 1974; 39 FR 25653, July 12, 1974]



      Sec. Appendix B to Part 80--Test Methods for Lead in Gasoline

Method 1--Standard Method Test for Lead in Gasoline by Atomic Absorption 
                              Spectrometry

                                1. Scope.

    1.1. This method covers the determination of the total lead content 
of gasoline. The procedure's calibration range is 0.010 to 0.10 gram of 
lead/U.S. gal. Samples above this level should be diluted to fall within 
this range or a higher level calibration standard curve must be 
prepared. The higher level curve must be shown to be linear and 
measurement of lead at these levels must be shown to be accurate by the 
analysis of control samples at a higher level of alkyl lead content. The 
method compensates for variations in gasoline composition and is 
independent of lead alkyl type.

                          2. Summary of method.

    2.1 The gasoline sample is diluted with methyl isobutyl ketone and 
the alkyl lead compounds are stabilized by reaction with iodine and a 
quarternary ammonium salt. The lead content of the sample is determined 
by atomic absorption flame spectrometry at 2833 A, using standards 
prepared from reagent grade lead chloride. By the use of this treatment, 
all alkyl lead compounds give identical response.

                              3. Apparatus.

    3.1 Atomic Absorption Spectometer, capable of scale expansion and 
nebulizer adjustment, and equipped with a slot burner and premix chamber 
for use with an air-acetylene flame.
    3.2 Volumetric Flasks, 50-ml, 100-ml, 250-ml, and one litre sizes.
    3.3 Pipets, 2-ml, 5-ml, 10-ml, 20-ml, and 50-ml sizes.
    3.4 Micropipet, 100-[micro]l, Eppendorf type or equivalent.

                              4. Reagents.

    4.1 Purity of Reagents--Reagent grade chemicals shall be used in all 
tests. Unless otherwise indicated, it is intended that all reagents 
shall conform to the specifications of the Committee on Analytical 
Reagents of the American Chemical Society, where such specifications are 
available. Other grades may be used, provided it is first ascertained 
that the reagent is of sufficiently high purity to permit its use 
without lessening the accuracy of the determination.
    4.2 Purity of Water--Unless otherwise indicated, references to water 
shall be understood to mean distilled water or water of equal purity.
    4.3 Aliquat 336 (tricapryl methyl ammonium chloride).
    4.4 Aliquat 336/MIBK Solution (10 percent v/v)--Dissolve and dilute 
100 ml (88.0 g) of Aliquat 336 with MIBK to one liter.
    4.5 Aliquat 336/MIBK Solution (1 percent v/v)--Dissolve and dilute 
10 ml (8.8 g) of Aliquat 336 with MIBK to one liter.
    4.6 Iodine Solution--Dissolve and dilute 3.0 g iodine crystals with 
Toluene to 100 ml.
    4.7 Lead Chloride.
    4.8 Lead-Sterile Gasoline--Gasoline containing less than 0.005 g Pb/
gal.
    4.9 Lead, Standard Solution (5.0 g Pb/gal)--Dissolve 0.4433 g of 
lead chloride (PbCl2) previously dried at 105 [deg]C for 3 h 
in about 200 ml of 10 percent Aliquat 336/MIBK solution in a 250-ml 
volumetric flask. Dilute to the mark with the 10 percent Aliquat 
solution, mix, and store in a brown bottle having a polyethylene-lined 
cap. This solution contains 1,321 [micro]g Pb/ml, which is equivalent to 
5.0 g Pb/gal.

[[Page 1089]]

    4.10 Lead, Standard Solution (1.0 g Pb/gal)--By means of a pipet, 
accurately transfer 50.0 ml of the 5.0 g Pb/gal solution to a 250-ml 
volumetric flask, dilute to volume with 1 percent Aliquat/MIBK solution. 
Store in a brown bottle having a polyethylene-lined cap.
    4.11 Lead, Standard Solutions (0.02, 0.05, and 0.10 g Pb/gal)--
Transfer accurately by means of pipets 2.0, 5.0, and 10.0 ml of the 1.0-
g Pb/gal solution to 100-ml volumetric flasks; add 5.0 ml of 1 percent 
Aliquat 336 solution to each flask; dilute to the mark with MIBK. Mix 
well and store in bottles having polyethylene-lined caps.
    4.12 Methyl Isobutyl Ketone (MIBK). (4-methyl-2-pentanone).

                             5. Calibration.

    5.1 Preparation of Working Standards--Prepare three working 
standards and a blank using the 0.02, 0.05, and 0.10-g Pb/gal standard 
lead solutions described in 4.11.
    5.1.1 To each of four 50-ml volumetric flasks containing 30 ml of 
MIBK, add 5.0 ml of low lead standard solution and 5.0 ml of lead-free 
gasoline. In the case of the blank, add only 5.0 ml of lead-free 
gasoline.
    5.1.2 Add immediately 0.1 ml of iodine/toluene solution by means of 
the 100-[micro]l Eppendorf pipet. Mix well.\1\
---------------------------------------------------------------------------

    \1\ EPA practice will be to mix well by shaking vigorously for 
approximately one minute.
---------------------------------------------------------------------------

    5.1.3 Add 5 ml of 1 percent Aliquat 336 solution and mix.
    5.1.4 Dilute to volume with MIBK and mix well.
    5.2 Preparation of Instrument--Optimize the atomic absorption 
equipment for lead at 2833 A. Using the reagent blank, adjust the gas 
mixture and the sample aspiration rate to obtain an oxidizing flame.
    5.2.1 Aspirate the 0.1-g Pb/gal working standard and adjust the 
burner position to give maximum response. Some instruments require the 
use of scale expansion to produce a reading of 0.150 to 0.170 for this 
standard.
    5.2.2 Aspirate the reagent blank to zero the instrument and check 
the absorbances of the three working standards for linearity.

                              6. Procedure.

    6.1 To a 50 ml volumetric flask containing 30 ml MIBK, add 5.0 ml of 
gasoline sample and mix.\2\
---------------------------------------------------------------------------

    \2\ The gasoline should be allowed to come to room temperature (25 
[deg]C).
---------------------------------------------------------------------------

    6.1.1 Add 0.10 ml (100 [micro]l) of iodine/toluene solution and 
allow the mixture to react about 1 minute.\3\
---------------------------------------------------------------------------

    \3\ See footnote 1 of section 5.1.2.
---------------------------------------------------------------------------

    6.1.2 Add 5.0 ml of 1 percent Aliquot 336/MIBK solution and mix.
    6.1.3 Dilute to volume with MIBK and mix.
    6.2 Aspirate the samples and working standards and record the 
absorbance values with frequent checks of the zero.
    6.3 Any sample resulting in a peak greater than 0.05 g Pb/gal will 
be run in duplicate. Samples registering greater than 0.10 g Pb/gal 
should be diluted with iso-octane or unleaded fuel to fall within the 
calibration range or a higher level calibration standard curve must be 
prepared. The higher level curve must be shown to be linear and 
measurement of lead at these levels must be shown to be accurate by the 
analysis of control samples at a higher level of alkyl lead content.

                            7. Calculations.

    7.1 Plot the absorbance values versus concentration represented by 
the working standards and read the concentrations of the samples from 
the graph.

                              8. Precision.

    8.1 The following criteria should be used for judging the 
acceptability of results (95 percent confidence):
    8.1.1 Repeatability--Duplicate results by the same operator should 
be considered suspect if they differ by more than 0.005 g/gal.
    8.1.2 Reproductibility--The results submitted by each of two 
laboratories should not be considered suspect unless the two results 
differ by more than 0.01 g/gal.

     Method 2--Automated Method Test for Lead in Gasoline by Atomic 
                         Absorption Spectrometry

                        1. Scope and application.

    1.1 This method covers the determination of the total lead content 
of gasoline. The procedure's calibration range is 0.010 to 0.10 gram of 
lead/U.S. gal. Samples above this level should be diluted to fall within 
this range or a higher level calibration standard curve must be 
prepared. The higher level curve must be shown to be linear and 
measurement of lead at these levels must be shown to be accurate by the 
analysis of control samples at a higher level of alkyl lead content. The 
method compensates for variations in gasoline composition and is 
independent of lead alkyl type.
    1.2 This method may be used as an alternative to the Standard Method 
set forth above.
    1.3 Where trade names or specific products are noted in the method, 
equivalent apparatus and chemical reagents may be used. Mention of trade 
names or specific products is for the assistance of the user and does 
not constitute endorsement by the U.S. Environmental Protection Agency.

[[Page 1090]]

                          2. Summary of method.

    2.1 The gasoline sample is diluted with methly isobutyl ketone 
(MIBK) and the alkyl lead compounds are stabilized by reacting with 
iodine and a quarternary ammonium salt. An automated system is used to 
perform the diluting and the chemical reactions and feed the products to 
the atomic absorption spectrometer with an air-acetylene flame.
    2.2 The dilution of the gasoline with MIBK compensates for severe 
non-atomic absorption, scatter from unburned carbon containing species 
and matrix effects caused in part by the burning characteristics of 
gasoline.
    2.3 The in-situ reaction of alkyl lead in gasoline with iodine 
eliminates the problem of variations in response due to different alkyl 
types by leveling the response of all alkyl lead compounds.
    2.4 The addition of the quarternary ammonium salt improves response 
and increases the stability of the alkyl iodide complex.

                  3. Sample handling and preservation.

    3.1 Samples should be collected and stored in containers which will 
protect them from changes in the lead content of the gasoline such as 
from loss of volatile fractions of the gasoline by evaporation or 
leaching of the lead into the container or cap.
    3.2 If samples have been refrigerated they should be brought to room 
temperature prior to analysis.

                              4. Apparatus.

    4.1 AutoAnalyzer system consisting of:
    4.1.1 Sampler 20/hr cam, 30/hr cam.
    4.1.2 Proportioning pump.
    4.1.3 Lead in gas manifold.
    4.1.4 Disposable test tubes.
    4.1.5 Two 2-liter and one 0.5 liter Erlenmeyer solvent displacement 
flasks. Alternatively, high pressure liquid chromatography (HPLC) or 
syringe pumps may be used.
    4.2 Atomic Absorption Spectroscopy (AAS) Detector System consisting 
of:
    4.2.1 Atomic absorption spectrometer.
    4.2.2 10 strip chart recorder.
    4.2.3 Lead hollow cathode lamp or electrodeless discharge lamp 
(EDL).

                              5. Reagents.

    5.1 Aliquat 336/MIBK solution (10% v/v): Dissolve and dilute 100 ml 
(88.0 g) of Aliquat 336 (Aldrich Chemical Co., Milwaukee, Wisconsin) 
with MIBK (Burdick & Jackson Lab., Inc., Muskegon, Michigan) to one 
liter.
    5.2 Aliquat 336/iso-octane solution (1% v/v): Dissolve and dilute 10 
ml (8.8 g) of Alquat 336 (reagent 5.1) with iso-octane to one liter.
    5.3 Iodine solution (3% w/v): Dissolve and dilute 3.0 g iodine 
crystals (American Chemical Society) with toluene (Burdick & Jackson 
Lab., Inc., Muskegon, Michigan) to 100 ml.
    5.4 Iodine working solution (0.24% w/v): Dilute 8 ml of reagent 5.3 
to 100 ml with toluene.
    5.5 Methyl isobutyl ketone (MIBK) (4-methlyl-2-pentanone).
    5.6 Certified unleaded gasoline (Phillips Chemical Co., Borger, 
Texas) or iso-octane (Burdick & Jackson Lab, Inc., Muskegon, Michigan).

                        6. Calibration standards.

    6.1 Stock 5.0 g Pb/gal Standard:
    Dissolve 0.4433 gram of lead chloride (PbCl2) previously 
dried at 105 [deg]C for 3 hours in 200 ml of 10% v/v Aliquat 336/MIBK 
solution (reagent 5.1) in a 250 ml volumetric flask. Dilute to volume 
with reagent 5.1 and store in an amber bottle.
    6.2 Intermediate 1.0 g Pb/gal Standard:
    Pipet 50 ml of the 5.0 g Pb/gal standard into a 250 ml volumetric 
flask and dilute to volume with a 1% v/v Aliquat 336/iso-octane solution 
(reagent 5.2). Store in an amber bottle.
    6.3 Working 0.02, 0.05, 0.10 g Pb/gal Standards:
    Pipet 2.0, 5.0, and 10.0 ml of the 1.0 g Pb/gal solution to 100 ml 
volumetric flasks. Add 5 ml of a 1% Aliquat 336/iso-octane solution to 
each flask. Dilute to volume with iso-octane. These solutions contain 
0.02, 0.05, and 0.10 g Pb/gal in a 0.05% Aliquat 336/iso-octane 
solution.

                     7. AAS Instrumental conditions.

    7.1 Lead hollow cathode lamp.
    7.2 Wavelength: 283.3 nm.
    7.3 Slit: 4 (0.7mm).
    7.4 Range: UV.
    7.5 Fuel: Acetylene (approx. 20 ml/min at 8 psi).
    7.6 Oxidant: Air (approx. 65 ml/min at 31 psi).
    7.7 Nebulizer: 5.2 ml/min.
    7.8 Chart speed: 10 in/hr.

                             8. Procedures.

    8.1 AAS start-up.
    8.1.1 Assure that instrumental conditions have been optimized and 
aligned according to Section 7 and the instrument has had substantial 
time for warm-up.
    8.2 Auto Analyzer start-up [see figure 1].
    8.2.1 Check all pump tubing and replace as necessary. Iodine tubing 
should be changed daily. All pump tubing should be replaced after one 
week of use. Place the platen on the pump.
    8.2.2 Withdraw any water from the sample wash cup and fill with 
certified unleaded gasoline (reagent 5.6).
    8.2.3 Fill the 2-liter MIBK dilution displacement Erlenmeyer flask 
(reagent 5.5)

[[Page 1091]]

and the 0.5 liter Aliquat 336/MIBK 1% v/v (reagent 5.2) displacement 
flask and place the rubber stopper glass tubing assemblies in their 
respective flasks.
    8.2.4 Fill a 2-liter Erlenmeyer flask with distilled water. The 
water will be used to displace the solvents. Therefore, place the 
appropriate lines in this flask. This procedure is not relevant if 
syringe pumps are used.
    8.2.5 Fill the final debubbler reverse displacement 2-liter 
Erlenmeyer flask with distilled water and place the rubber stopper glass 
tubing assembly in the flask.
    8.2.6 Place the appropriate lines for the iodine reagent (reagent 
5.4) and the wash solution (reagent 5.6) in their respective bottles.
    8.2.7 Start the pump and connect the aspiration line from the 
manifold to the AAS.
    8.2.8 Some initial checks to assure that the reagents are being 
added are:
    a. A good uniform bubble pattern.
    b. Yellow color evident due to iodine in the system.
    c. No surging in any tubing.
    8.3 Calibration.
    8.3.1 Turn the chart drive on and obtain a steady baseline.
    8.3.2 Load standards and samples into sample tray.
    8.3.3 Start the sampler and run the standards (Note: first check the 
sample probe positioning with an empty test tube).
    8.3.4 Check the linearity of calibration standards response and 
slope by running a least squares fit. Check these results against 
previously obtained results. They should agree within 10%.
    8.3.5 If the above is in control then start the sample analysis.
    8.4 Sample Analysis.
    8.4.1 To minimize gasoline vapor in the laboratory, load the sample 
tray about 5-10 test tubes ahead of the sampler.
    8.4.2 Record the sample number on the strip chart corresponding to 
the appropriate peak.
    8.4.3 Every ten samples run the high calibration standard and a 
previously analyzed sample (duplicate). Also let the sampler skip to 
check the baseline.
    8.4.4 After an acceptable peak (within the calibration range) is 
obtained, pour the excess sample from the test tube into the waste 
gasoline can.
    8.4.5 Any sample resulting in a peak greater than 0.05 g Pb/gal will 
be run in duplicate. Samples registering greater than 0.10 g Pb/gal 
should be diluted with iso-octane or unleaded fuel to fall within the 
calibration range or a higher level calibration standard curve must be 
prepared. The higher level curve must be shown to be linear and 
measurement of lead at these levels must be shown to be accurate by the 
analysis of control samples at a higher level of alkyl lead content.
    8.5 Shut Down.
    8.5.1 Replace the solvent displacement flask with flasks filled with 
distilled water. Also place all other lines in a beaker of distilled 
water. Rinse the system with distilled water for 15 minutes.
    8.5.2 Withdraw the gasoline from the wash cup and fill with water.
    8.5.3 Dispose of all solvent waste in waste glass bottles.
    8.5.4 Turn the AAS off after extinguishing the flame. Also turn the 
recorder and pump off. Remove the platen and release the pump tubing.
    8.5.5 Shut the acetylene off at the tank and bleed the line.

                           9. Quality control.

    9.1 Precision.
    9.1.1 All duplicate results should be considered suspect if they 
differ by more than 0.005 g Pb/gal.
    9.2 Accuracy.
    9.2.1 All quality control standard checks should agree within 10% of 
the nominal value of the standard.
    9.2.2 All spikes should agree within 10% of the known addition.

                     10. Past quality control data.

    10.1 Precision.
    10.1.1 Duplicate analysis for 156 samples in a single laboratory has 
resulted in an average difference of 0.00011 g Pb/gal with a standard 
deviation of 0.0023.
    10.1.2 Replicate analysis in a single laboratory (greater than 5 
determinations) of samples at concentrations of 0.010, 0.048, and 0.085 
g Pb/gal resulted in relative standard deviations of 4.2%, 3.5%, and 
3.3% respectively.
    10.2 Accuracy.
    10.2.1 The analysis of National Bureau of Standards (NBS) lead in 
reference fuel of known concentrations in a single laboratory has 
resulted in found values deviating from the true value for 11 
determinations of 0.0322 g Pb/gal by an average of 0.56% with a standard 
deviation of 6.8%, for 15 determinations of 0.0519 g Pb/gal by an 
average of -1.1% with a standard deviation of 5.8%, and for 7 
determinations of 0.0725 g Pb/gal by an average of 3.5% with a standard 
deviation of 4.8%.
    10.2.2 Twenty-three analyses of blind reference samples in a single 
laboratory (U.S. EPA, RTP, N.C.) have resulted in found values differing 
from the true value by an average of -0.0009 g Pb/gal with a standard 
deviation of 0.004.
    10.2.3 In a single laboratory, the average percent recovery of 108 
spikes made to samples was 101% with a standard deviation of 5.6%.

[[Page 1092]]

[GRAPHIC] [TIFF OMITTED] TC01SE92.139


[[Page 1093]]



        Method 3--Test for Lead in Gasoline by X-Ray Spectrometry

                        1. Scope and application.

    1.1 This method covers the determination of the total lead content 
of gasoline. The procedure's calibration range is 0.010 to 5.0 grams of 
lead/U.S. gallon. Samples above this level should be diluted to fall 
within the range of 0.05 to 5.0 grams of lead/U.S. gallon. The method 
compensates for variations in gasoline composition and is independent of 
lead alkyl type.
    1.2 This method may be used as an alternative to Method 1--Standard 
Method Test for Lead in Gasoline by Atomic Absorption Spectrometry, or 
to Method 2--Automated Method Test for Lead in Gasoline by Atomic 
Absorption Spectrometry.
    1.3 Where trade names or specific products are noted in the method, 
equivalent apparatus and chemical reagents may be used. Mention of trade 
names or specific products is for the assistance of the user and does 
not constitute endorsement by the U.S. Environmental Protection Agency.

                          2. Summary of method.

    2.1 A portion of the gasoline sample is placed in an appropriate 
holder and loaded into an X-ray spectrometer. The ratio of the net X-ray 
intensity of the lead L alpha radiation to the net intensity of the 
incoherently scattered tungsten L alpha radiation is measured. The lead 
content is determined by reference to a linear calibration equation 
which relates the lead content to the measured ratio.
    2.2 The incoherently scattered tungsten radiation is used to 
compensate for variations in gasoline samples.

                  3. Sample handling and preservation.

    3.1 Samples should be collected and stored in containers which will 
protect them from changes in the lead content of the gasoline, such as 
loss of volatile fractions of the gasoline by evaporation or leaching of 
the lead into the container or cap.
    3.2 If samples have been refrigerated they should be brought to room 
temperature prior to analysis.
    3.3 Gasoline is extremely flammable and should be handled cautiously 
and with adequate ventilation. The vapors are harmful if inhaled and 
prolonged breathing of vapors should be avoided. Skin contact should be 
minimized. See precautionary statements in Annex Al.3.

                              4. Apparatus.

    4.1 X-ray Spectrometer, capable of exciting and measuring the 
fluorescence lines mentioned in 2.1 and of being operated under the 
following instrumental conditions or others giving equivalent results: a 
tungsten target tube operated at 50 kV, a lithium fluoride analyzing 
crystal, an air or helium optical path and a proportional or 
scintillation detector.
    4.2 Some manufacturers of X-ray Spectrometer units no longer allow 
use of air as the beam path medium because the X-ray beam produces 
ozone, which may degrade seals and electronics. In addition, use of the 
equipment with liquid gasoline in close proximity to the hot X-ray tube 
could pose flammability problems with any machine in case of a rupture 
of the sample container. Therefore, use of the helium alternative is 
recommended.

                              5. Reagents.

    5.1 Isooctane. Isooctane is flammable and the vapors may be harmful. 
See precautions in Annex Al.1.
    5.2 Lead standard solution, in isooctane, toluene or a mixture of 
these two solvents, containing approximately 5 gm Pb/U.S. gallon may be 
prepared from a lead-in-oil concentrate such as those prepared by 
Conostan (Conoco, Inc., Ponca City, Oklahoma). Isooctane and toluene are 
flammable and the vapors may be harmful. See precautionary statements in 
Annex Al.1 and Al.2.

                             6. Calibration.

    6.1 Make exact dilutions with isooctane of the lead standard 
solution to give solutions with concentrations of 0.01, 0.05, 0.10, 
0.50, 1.0, 3.0 and 5.0 g Pb/U.S. gallon. If a more limited range is 
desired as required for linearity, such range shall be covered by at 
least five standard solutions approximately equally spaced and this 
range shall not be exceeded by any of the samples. Place each of the 
standard solutions in a sample cell using techniques consistent with 
good operating practice for the spectrometer employed. Insert the sample 
in the spectrometer and allow the spectrometer atmosphere to reach 
equilibrium (if appropriate). Measure the intensity of the lead L alpha 
peak at 1.175 angstroms, the Compton scatter peak of the tungsten L 
alpha line at 1.500 angstroms and the background at 1.211 angstroms. 
Each measured intensity should exceed 200,000 counts or the time of 
measurement should be at least 30 seconds. The relative standard 
deviation of each measurement, based on counting statistics, should be 
one percent or less. The Compton scatter peak given above is for 90[deg] 
instrument geometry and should be changed for other geometries. The 
Compton scatter peak (in angstroms) is found at the wavelength of the 
tungsten L alpha line plus 0.024 (1-cos phi), where phi is the angle 
between the incident radiation and the take-off collimator.
    6.2 For Each of the standards, as well as for an isooctane blank, 
determine the net lead intensity by subtracting the corrected

[[Page 1094]]

background from the gross intensity. Determine the corrected background 
by multiplying the intensity of the background at 1.211 angstroms by the 
following ratio obtained on an isooctane blank:
[GRAPHIC] [TIFF OMITTED] TC10NO91.007

    6.3 Determine the corrected lead intensity ratio, which is the net 
lead intensity corrected for matrix effects by division by the net 
incoherently scattered tungsten radiation. The net scattered intensity 
is calculated by subtracting the background intensity at 1.211 angstroms 
from the gross intensity of the incoherently scattered tungsten L alpha 
peak. The equation for the corrected lead intensity ratio follows:
[GRAPHIC] [TIFF OMITTED] TC10NO91.008

    6.4 Obtain a linear calibration curve by performing a least squares 
fit of the corrected lead intensity ratios to the standard 
concentrations.

                              7. Procedure.

    7.1 Prepare a calibration curve as described in 6. Since the 
scattered tungsten radiation serves as an internal standard, the 
calibration curve should serve for at least several days. Each day the 
suitability of the calibration curve should be checked by analyzing 
several National Bureau of Standards (NBS) lead-in-reference-fuel 
standards or other suitable standards.
    7.2 Determine the corrected lead intensity ratio for a sample in the 
same manner as was done for the standards. The samples should be brought 
to room temperature before analysis.
    7.3 Determine the lead concentration of the sample from the 
calibration curve. If the sample concentration is greater than 5.0 g Pb/
U.S. gallon or the range calibrated for in 6.1, the sample should be 
diluted so that the result is within the calibration span of the 
instrument.
    7.4 Quality control standards, such as NBS standard reference 
materials, should be analyzed at least once every testing session.
    7.5 For each group of ten samples, a spiked sample should be 
prepared by adding a known amount of lead to a sample. This known 
addition should be at least 0.05 g Pb/U.S. gallon, at least 50% of the 
measured lead content of the unspiked sample, and not more than 200% of 
the measured lead content of the unspiked sample (unless the minimum 
addition of 0.05 g Pb/U.S. gallon exceeds 200%). Both the spiked and 
unspiked samples should be analyzed.

                           8. Quality control.

    8.1 The difference between duplicates should not exceed 0.005 g Pb/
U.S. gallon or a relative difference of 6%.
    8.2 All quality control standard check samples should agree within 
10% of the nominal value of the standard.
    8.3 All spiked samples should have a percent recovery of 100% 10%. The percent recovery, P, is calculated as follows:

P = 100 x (A - B) / K

where
A = the analytical result from the spiked sample, B = the analytical 
result from the unspiked sample, and K = the known addition.

    8.4 The difference between independent analyses of the same sample 
in different laboratories should not exceed 0.01 g Pb/U.S. gallon or a 
relative difference of 12%.

9. Past quality control data.

    9.1 Duplicate analysis for 26 samples in the range of 0.01 to 0.10 g 
Pb/U.S. gallon resulted in an average relative difference of 5.2% with a 
standard deviation of 5.4%. Duplicate analysis of 14 samples in the 
range 0.1 to 0.5 g Pb/U.S. gallon resulted in an average relative 
difference of 2.3% with a standard deviation of 2.0. Duplicate analysis 
of 47 samples in the range of 0.5 to 5 g Pb/U.S. gallon resulted in an 
average relative difference of 2.1% with a standard deviation of 1.8%.
    9.2 The average percent recovery for 23 spikes made to samples in 
the 0.0 to 0.1 g Pb/U.S. gallon range was 103% with a standard deviation 
of 3.2%. For 42 spikes made to samples in the 0.1 to 5.0 g Pb/U.S. 
gallon range, the average percent recovery was 102% with a standard 
deviation of 4.2%.
    9.3 The analysis of National Bureau of Standards lead-in-reference-
fuel standards of known concentrations in a single laboratory has 
resulted in found values deviating from the true value for 14 
determinations of 0.0490 g Pb/U.S. gallon by an average of 2.8% with a 
standard deviation of 6.4%, for 11 determinations of 0.065 g Pb/U.S. 
gallon by an average of 4.4% with a standard deviation of 2.9%, and for 
15 determinations of 1.994 g Pb/U.S. gallon by an average of 0.3% with a 
standard deviation of 1.3%.

[[Page 1095]]

    9.4 Eighteen analyses of reference samples (U.S. EPA, Research 
Triangle Park, NC) have resulted in found values differing from the true 
value by an average of 0.0004 g Pb/U.S. gallon with a standard deviation 
of 0.004 g Pb/U.S. gallon.

                                  Annex

                      A1. Precautionary Statements

                             A1.1 Isooctane

Danger--Extremely flammable. Vapors harmful if inhaled.
Vapor may cause flash fire.
Keep away from heat, sparks, and open flame.
Vapors are heavier than air and may gather in low places, resulting in 
explosion hazard.
Keep container closed.
Use adequate ventilation.
Avoid buildup of vapors.
Avoid prolonged breathing of vapor or spray mist.
Avoid prolonged or repeated skin contact.

                              A1.2 Toluene

Warning--Flammable. Vapor harmful.
Keep away from heat, sparks, and open flame.
Keep container closed.
Use with adequate ventilation.
Avoid breathing of vapor or spray mist.
Avoid prolonged or repeated contact with skin.

                              A1.3 Gasoline

Danger--Extremely flammable. Vapors harmful if inhaled.
Vapor may cause flash fire.
Keep away from heat, sparks, and open flame.
Vapors are heavier than air and may gather in low places, resulting in 
explosion hazard.
Keep container closed.
Use adequate ventilation.
Avoid buildup of vapors.
Avoid prolonged breathing of vapor or spray mist.
Avoid prolonged or repeated skin contact.

[39 FR 24891, July 8, 1974; 39 FR 25653, July 12, 1974; 39 FR 26287, 
July 18, 1974, as amended at 47 FR 765, Jan. 7, 1982; 52 FR 259, Jan. 5, 
1987; 56 FR 13768, Apr. 4, 1991]



                Sec. Appendixes C-G to Part 80 [Reserved]


[[Page 1097]]



                              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.

  Material Approved for Incorporation by Reference
  Table of CFR Titles and Chapters
  Alphabetical List of Agencies Appearing in the CFR
  List of CFR Sections Affected

[[Page 1099]]

            Material Approved for Incorporation by Reference

                      (Revised as of July 1, 2008)

  The Director of the Federal Register has approved under 5 U.S.C. 
552(a) and 1 CFR Part 51 the incorporation by reference of the following 
publications. This list contains only those incorporations by reference 
effective as of the revision date of this volume. Incorporations by 
reference found within a regulation are effective upon the effective 
date of that regulation. For more information on incorporation by 
reference, see the preliminary pages of this volume.


40 CFR (PARTS 72 TO 80):

ENVIRONMENTAL PROTECTION AGENCY
                                                                  40 CFR


American Gas Association

  1515 Wilson Blvd., Arlington, VA 22209
AGA Report No. 3: Orifice Metering of Natural Gas   75.20; Appendices D 
  and Other Related Hydrocarbon Fluids, Part 1,         and E of Part 75
  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).
AGA Report No. 7: Measurement of Gas by Turbine                    75.20
  Meters (1985 edition).
AGA Report No. 7: Measurement of Gas by Turbine     75.6, Appendix D of 
  Meters (2nd revision, 1996 edition).                           part 75


American Institute of Certified Public Accountants, Inc.

  1211 Avenue of the Americas, New York, NY 10036
Codification of Statements on Auditing Standards,                 80.125
  ``Statements on Standards for Attestation 
  Engagements, 1991, Identification Number 059021.


American Petroleum Institute

  1220 L Street NW., Washington, DC 20005-4070; 
  Telephone: (202) 682-8000
API Manual of Petroleum Management Standard                        75.19
  (MPMS), Chapter 3, section 1A, Standard Practice 
  for the Manual Gauging of Petroleum and 
  Petroleum Products, First Edition, December 
  1994.
API Manual of Petroleum Measurement Standards,                      75.6
  Chapter 3, Section 1A, Standard Practice for the 
  Manual Gauging of Petroleum and Petroleum 
  Products, August 2005, Second Edition.
API Manual of Petroleum Management Standard                        75.19
  (MPMS), Chapter 3, section 1B, Standard Practice 
  for Level Measurement of Liquid Hydrocarbons in 
  Stationary Tanks by Automatic Tank Gauging, 
  First Edition, April 1992, Reaffirmed January 
  1997.
API Manual of Petroleum Measurement Standards,                      75.6
  Chapter 3, Section 1B, Standard Practice for 
  Level Measurement of Liquid Hydrocarbons in 
  Stationary Tanks by Automatic Tank Gauging, June 
  2001, Second Edition.
API Manual of Petroleum Management Standard                  75.6; 75.19
(MPMS), Chapter 3, section 2, Standard Practice 
[[Page 1100]]Petroleum and Petroleum Products in 
  Tank Cars, First Edition, September 1995.
API Manual of Petroleum Management Standard                  75.6; 75.19
  (MPMS), Chapter 3, section 3, Standard Practice 
  for Level Measurement of Liquid Hydrocarbons in 
  Stationary Pressurized Storage Tanks by 
  Automatic Tank Gauging, First Edition, June 
  1996.
API Manual of Petroleum Management Standard                  75.6; 75.19
  (MPMS), Chapter 3, section 4, Standard Practice 
  for Level Measurement of Liquid Hydrocarbons on 
  Marine Vessels by Automatic Tank Gauging, First 
  Edition, April 1995.
API Manual of Petroleum Management Standard                        75.19
  (MPMS), Chapter 3, section 5, Standard Practice 
  for Level Measurement of Light Hydrocarbon 
  Liquids Onboard Marine Vessels by Automatic Tank 
  Gauging, First Edition, March 1997.
API Manual of Petroleum Measurement Standards,                      75.6
  Chapter 3, Section 5, Standard Practice for 
  Level Measurement of Light Hydrocarbon Liquids 
  Onboard Marine Vessels by Automatic Tank 
  Gauging, March 1997 (reaffirmed, March 2003), 
  First Edition.
API Manual of Petroleum Measurement Standards,                      75.6
  Chapter 4, Section 2, Pipe Provers (Provers 
  Accumulating at Least 10,000 Pulses), March 
  2001, Second Edition.
API Manual of Petroleum Measurement Standards,                      75.6
  Chapter 4, Section 5, Master-Meter Provers, May 
  2000, Second Edition.
API Manual of Petroleum Measurement Standards,                      75.6
  Chapter 22, Section 2, Differential Pressure 
  Flow Measurement Devices, August 2005, First 
  Edition.
API Bulletin 2509B, Shop Testing of Automatic                75.6; 75.19
  Liquid Level Gauges, December 1961; reaffirmed 
  August 1987 and October 1992.


American Society of Mechanical Engineers (ASME)

  Three Park Avenue, New York, NY 10016-5990; 
  Order inquiries: 22 Law Drive, P.O. Box 2900, 
  Fairfield, New Jersey 07007; Phone: 1-800-843-
  2763
ASME MFC-3M-1989 with September 1990 Errata        75.20 and Appendix D 
  Measurement of Fluid Flow in Pipes Using                    of Part 75
  Orifice, Nozzle, and Venturi.
ASME MFC-3M-2004 (Revision of ASME MFC-3M-1989                      75.6
  (R1995)), Measurement of Fluid Flow in Pipes 
  Using Orifice, Nozzle, and Venturi, 2004.
ASME MFC-4M-1986 (Reaffirmed 1990) Measurement of  75.20 and Appendix D 
  Gas Flow by Turbine Meters.                                 of Part 75
ASME MFC-4M-1986 (reaffirmed 1997), Measurement of                  75.6
  Gas Flow by Turbine Meters, 1997.
ASME MFC-5M-1985 Measurement of Liquid Flow in     75.20 and Appendix D 
  Closed Conduits Using Transit-Time Ultrasonic               of Part 75
  Flowmeters.
ASME MFC-5M-1985 (reaffirmed 1994), Measurement of                  75.6
  Liquid Flow in Closed Conduits Using Transit-
  Time Ultrasonic Flowmeters, 1994.
ASME MFC-6M-1987 with June 1987 Errata Measurement 75.20 and Appendix D 
  of Fluid Flow in Pipes Using Vortex Flow Meters.            of Part 75
ASME MFC-6M-1998, Measurement of Fluid Flow in                      75.6
  Pipes Using Vortex Flowmeters, 1998.
ASME MFC-7M-1987 (Reaffirmed 1992) Measurement of  75.20 and Appendix D 
  Gas Flow by Means of Critical Flow Venturi                  of Part 75
  Nozzles.
ASME MFC-7M-1987 (reaffirmed 1992), Measurement of                  75.6
  Gas Flow by Means of Critical Flow Venturi 
  Nozzles, 1992.
ASME MFC-9M-1988 with December 1989 Errata         75.20 and Appendix D 
  Measurement of Liquid Flow in Closed Conduits by            of Part 75
Weighing Method.
[[Page 1101]]

ASME MFC-9M-1988 (reaffirmed 2001), Measurement of                  75.6
  Liquid Flow in Closed Conduits by Weighing 
  Method, 2001.
ASME Performance Test Code 4.2 (1991), Test Code             76.4; 76.15
  for Coal Pulverizers.


American Society for Testing and Materials

  100 Barr Harbor Drive, West Conshohocken, PA 
  19428-2959; Telephone: (610) 832-9585, FAX: 
  (610) 832-9555
ASTM D 86-01, Standard Test Method for                      80.46; 80.84
  Distillation of Petroleum Products at 
  Atmospheric Pressure.
ASTM D 86-90, Standard Test Method for                             80.46
  Distillation of Petroleum Products.
ASTM D 129-91 Standard Test Method for Sulfur in   Appendices A and D of 
  Petroleum Products (General Bomb Method).             Part 75 and 72.7
ASTM D 129-00, Standard Test Method for Sulfur in                   75.6
  Petroleum Products (General Bomb Method), 2000.
ASTM D 240-87 (Reapproved 1991) Standard Test      Appendices A, D, and 
  Method for Heat of Combustion of Liquid                   F of Part 75
  Hydrocarbon Fuels by Bomb Calorimeter.
ASTM D 240-00, Standard Test Method for Heat of                     75.6
  Combustion of Liquid Hydrocarbon Fuels by Bomb 
  Calorimeter, 2000.
ASTM D 287-82 (Reapproved 1987) Standard Test      Appendix D of Part 75
  Method for API Gravity of Crude Petroleum and 
  Petroleum Products (Hydrometer Method).
ASTM D 287-92 (Reapproved 2000), Standard Test                      75.6
  Method for API Gravity of Crude Petroleum and 
  Petroleum Products (Hydrometer Method), 2000.
ASTM D 388-92 Standard Classification of Coals by   72.2 and Appendix F 
  Rank.                                                       of Part 75
ASTM D 388-99, Standard Classification of Coals by                  75.6
  Rank, 1999.
ASTM D 396-90a Standard Specification for Fuel                      72.2
  Oils.
ASTM D 439-81, Standard Specifications for             80.2(d); 80.22(b)
  Automotive Gasoline.
ASTM D 941-88 Standard Test Method for Density and Appendix D of Part 75
  Relative Density (Specific Gravity) of Liquids 
  by Lipkin Bicapillary Pycnometer.
ASTM D 975-91 Standard Specification for Diesel                     72.2
  Fuel Oils.
ASTM D 975-93, Standard Specification for Diesel        79.56(d)(5) and 
  Fuel Oils.                                                      (e)(3)
ASTM D 975-04, Standard Specification for Diesel                    80.2
  Fuel Oils.
ASTM D 976-80 Standard Methods for Calculated                    80.2(w)
  Cetane Index of Distillate Fuels.
ASTM D 1072-90 Standard Test Method for Total      Appendix D of Part 75 
  Sulfur in Fuel Gases.                                         and 72.7
ASTM D 1072-06, Standard Test Method for Total                      75.6
  Sulfur in Fuel Gases by Combustion and Barium 
  Chloride Titration, 2006.
ASTM D 1217-91 Standard Test Method for Density    Appendix D of Part 75
  and Relative Density (Specific Gravity) of 
  Liquids by Bingham Pycnometer.
ASTM D 1217-93 (Reapproved 1998), Standard Test                     75.6
  Method for Density and Relative Density 
  (Specific Gravity) of Liquids by Bingham, 
  Pycnometer, 1998.
ASTM D 1250-80 (Reapproved 1990) Standard Guide    Appendix D of Part 75
  for Petroleum Measurement Tables.
ASTM D 1250-07, Standard Guide for Use of                           75.6
Petroleum Measurement Tables, 2007.
[[Page 1102]]

ASTM D 1265-92 Standard Practice for Sampling                       72.7
  Liquified Petroleum (LP) Gases (Manual Method).
ASTM D 1298-85 (Reapproved 1990) Standard Practice Appendix D of Part 75
  for Density, Relative Density (Specific Gravity) 
  or API Gravity of Crude Petroleum and Liquid 
  Petroleum Products by Hydrometer Method.
ASTM D 1298-99, Standard Test Method for Density,                   75.6
  Relative Density (Specific Gravity), or API 
  Gravity of Crude Petroleum and Liquid Petroleum 
  Products by Hydrometer Method, 1999.
ASTM D 1319-03, Standard Test Method for                  80.2(z); 80.46
  Hydrocarbon Types in Liquid Petroleum Products 
  by Fluorescent Indicator Adsorption.
ASTM D 1319B-03, Standard Test Method for                          80.46
  Hydrocarbon Types in Liquid Petroleum Products 
  by Fluorescent Indicator Adsorption.
ASTM D1480-91 Standard Test Method for Density and Appendix D of Part 75
  Relative Density (Specific Gravity) of Viscous 
  Materials by Bingham Pycnometer.
ASTM D 1480-93 (Reapproved 1997), Standard Test                     75.6
  Method for Density and Relative Density 
  (Specific Gravity) of Viscous Materials by 
  Bingham Pycnometer, 1997.
ASTM D 1481-91 Standard Test Method for Density    Appendix D of Part 75
  and Relative Density (Specific Gravity) of 
  Viscous Materials by Lipkin Bicapillary 
  Pycnometer.
ASTM D 1481-93 (Reapproved 1997), Standard Test                     75.6
  Method for Density and Relative Density 
  (Specific Gravity) of Viscous Materials by 
  Lipkin Bicapillary Pycnometer, 1997.
ASTM D 1552-90 Standard Test Method for Sulfur in  Appendices A and D of 
  Petroleum Products (High Temperature Method).                  Part 75
ASTM D 1552-01, Standard Test Method for Sulfur in                  75.6
  Petroleum Products (High-Temperature Method), 
  2001.
ASTM D 1826-88 Standard Test Method for Calorific  Appendix F of Part 75
  (Heating) Value of Gases in Natural Gas Range by 
  Continuous Recording Calorimeter.
ASTM D 1826-94 (Reapproved 1998), Standard Test                     75.6
  Method for Calorific (Heating) Value of Gases in 
  Natural Gas Range by Continuous Recording 
  Calorimeter, 1998.
ASTM D 1945-91 Standard Test Method for Analysis   Appendices F and G of 
  of Natural Gas by Gas Chromatography.                          Part 75
ASTM D 1945-96 (Reapproved 2001), Standard Test                     75.6
  Method for Analysis of Natural Gas by Gas 
  Chromatography, 2001.
ASTM D 1946-90 Standard Practice for Analysis of   Appendices F and G of 
  Reformed Gas by Gas Chromatography.                            Part 75
ASTM D 1946-90 (Reapproved 2006), Standard                          75.6
  Practice for Analysis of Reformed Gas by Gas 
  Chromatography, 2006.
ASTM D 1989-92 Standard Test Method for Gross      Appendix F of Part 75
  Caloric Value of Coal and Coke by Microprocessor 
  Controlled Isoperibol Calorimeters.
ASTM D 2013-86 Standard Method of Preparing Coal     Appendix F of Part 
  Samples for Analysis.                                        75; 75.15
ASTM D 2013-01, Standard Practice for Preparing                     75.6
  Coal Samples for Analysisl 2001.
ASTM D 2015-91 Standard Test Method for Gross      Appendices A, D, and 
  Calorific Value of Coal and Coke by the            F of Part 75; 75.15
  Adiabatic Bomb Calorimeter.
ASTM D 2234-89 Standard Test Methods for             Appendix F of Part 
  Collection of a Gross Sample of Coal.                        75; 75.15

[[Page 1103]]

ASTM D 2234-00, Standard Practice for Collection                    75.6
  of a Gross Sample of Coal, 2000.
ASTM D 2382-88 Standard Test Method for Heat of     Appendices D, and F 
  Combustion of Hydrocarbon Fuels by Bomb                     of Part 75
  Calorimeter (High-Precision Method).
ASTM D 2502-87 Standard Test Method for Estimation Appendix G of Part 75
  of Molecular Weight (Relative Molecular Mass) of 
  Petroleum Oils from Viscosity Measurements.
ASTM D 2502-92 (Reapproved 1996), Standard Test                     75.6
  Method for Estimation of Molecular Weight 
  (Relative Molecular Mass) of Petroleum Oils from 
  Viscosity Measurements, 1996.
ASTM D 2503-82 (Reapproved 1987) Standard Test     Appendix G of Part 75
  Method for Molecular Weight (Relative Molecular 
  Mass) of Hydrocarbons by Thermoelectric 
  Measurement of Vapor Pressure.
ASTM D 2503-92 (Reapproved 1997), Standard Test                     75.6
  Method for Relative Molecular Mass (Molecular 
  Weight) of Hydrocarbons by Thermoelectric 
  Measurement of Vapor Pressure, 1997.
ASTM D 2622-92 Standard Test Method for Sulfur in    72.7; Appendices A 
  Petroleum Products by X-Ray Spectrometry.           and D of Part 75; 
                                                                   80.46
ASTM D 2622-98, Standard Test Method for Sulfur in                  75.6
  Petroleum Products by Wavelength Dispersive X-
  ray Fluorescence Spectrometry, 1998.
ASTM D 2622-03 Standard Test Method for Sulfur in          80.46; 80.580
  Petroleum Products by Wavelength Dispersive X-
  ray Fluorescence Spectrometry.
ASTM D 2880-90a, Standard Specification for Gas                     72.2
  Turine Fuel Oils.
ASTM D2892-84, Standard Test Method for            Appendix E to Part 80
  Distillation of Crude Petroleum (15-Theoretical 
  Plate Column).
ASTM D 3120-03a, Standard Test Method for Trace            80.46; 80.580
  Quantities of Sulfur in Light Liquid Petroleum 
  Hydrocarbons by Oxidative Microcoulometry.
ASTM D 3172-89, Standard Practice for Proximate              76.4; 76.15
  Analysis of Coal and Coke.
ASTM D3174-89 Standard Test Method for Ash in the  Appendix G of Part 75
  Analysis Sample of Coal and Coke from Coal.
ASTM D 3174-00, Standard Test Method for Ash in                     75.6
  the Analysis Sample of Coal and Coke from Coal, 
  2000.
ASTM D 3176-89 Standard Practice for Ultimate      Appendices A and F of 
  Analysis of Coal and Coke.                        Part 75; 76.4; 76.15
ASTM D 3176-89 (Reapproved 2002), Standard                          75.6
  Practice for Ultimate Analysis of Coal and 
  Coke,2002.
ASTM D 3177-89 Standard Test Methods for Total       Appendix A of Part 
  Sulfur in the Analysis Sample of Coal and Coke.              75; 75.15
ASTM D 3177-02 (Reapproved 2007), Standard Test                     75.6
  Methods for Total Sulfur in the Analysis Sample 
  of Coal and Coke, 2007.
ASTM D 3178-89 Standard Test Methods for Carbon    Appendix G of Part 75
  and Hydrogen in the Analysis Sample of Coal and 
  Coke.
ASTM D 3178-89 (Reapproved 2002), Standard Test                     75.6
Methods for Carbon and Hydrogen in the Analysis 
[[Page 1104]]al and Coke, 2002.

ASTM D 3238-90 Standard Test Method for            Appendix G of Part 75
  Calculation of Carbon Distribution and 
  Structural Group Analysis of Petroleum Oils by 
  the n-d-aM Method.
ASTM D 3238-95 (Reapproved 2000), Standard Test                     75.6
  Method for Calculation of Carbon Distribution 
  and Structural Group Analysis of Petroleum Oils 
  by n-d-M Method, 2000.
ASTM D 3246-96 Standard Test Method for Sulfur in                  80.46
  Petroleum Gas by Oxidative Microcoulometry.
ASTM D 3246-96, Standard Test Method for Sulfur in                  75.6
  Petroleum Gas by Oxidative Microcoulometry, 
  1996.
ASTM D 3286-91a Standard Test Method for Gross     Appendix F of Part 75
  Calorific Value of Coal and Coke by the 
  Isoperibol Bomb Calorimeter.
ASTM D 3588-91 Standard Practice for Calculating   Appendix F of Part 75
  Heat Value, Compressibility Factor, and Relative 
  Density (Specific Gravity) of Gaseous Fuels.
ASTM D 3588-98, Standard Practice for Calculating                   75.6
  Heat Value, Compressibility Factor, and Relative 
  Density of Gaseous Fuels, 1998.
ASTM D 3606-92, Standard Test Method for                           80.46
  Determination of Benzene and Toluene in Finished 
  Motor and Aviation Gasoline by Gas 
  Chromatography.
ASTM D 3606-99, Standard Test Method for                           80.46
  Determination of Benzene and Toluene in Finished 
  Motor and Aviation Gasoline by Gas 
  Chromatography.
ASTM D 4052-91 Standard Test Method for Density    Appendix D of Part 75
  and Relative Density of Liquids by Digital 
  Density Meter.
ASTM D 4052-96 (Reapproved 2002), Standard Test                     75.6
  Method for Density and Relative Density of 
  Liquids by Digital Density Meter, 2002.
ASTM D 4057-88 Standard Practice for Manual        Appendix D of Part 75 
  Sampling of Petroleum and Petroleum Products.                 and 72.7
ASTM D 4057-95 Standard Practice for Manual                       80.330
  Sampling of Petroleum and Petroleum Products.
ASTM D 4057-95 (Reapproved 2000), Standard                    75.6, 80.8
  Practice for Manual Sampling of Petroleum and 
  Petroleum Products.
ASTM D 4177-82 (Reapproved 1990) Standard Practice Appendix D of Part 75
  for Automatic Sampling of Petroleum and 
  Petroleum Products.
ASTM D 4177-95 Standard Practice for Automatic                    80.330
  Sampling of Petroleum and Petroleum Products.
ASTM D 4177-95 (Reapproved 2000), Standard                    75.6, 80.8
  Practice for Automatic Sampling of Petroleum and 
  Petroleum Products.
ASTM D 4239-85 Standard Test Methods for Sulfur in   Appendix A of Part 
  the Analysis Sample of Coal and Coke Using High              75; 75.15
  Temperature Tube Furnace Combustion Methods.
ASTM D 4239-02, Standard Test Methods for Sulfur                    75.6
  in the Analysis Sample of Coal and Coke Using 
  High-Temperature Tube Furnace Combustion 
  Methods, 2002.
ASTM D 4294-83 Standard Test Method for Sulfur in        80.30(g)(2)(ii)
  Petroleum Products by Non-dispersive X-ray 
  Fluorescence Spectrometry.
ASTM D 4294-90 Standard Test Method for Sulfur in  72.7 and Appendices A 
  Petroleum Products by Energy-Dispersive X-Ray         and D of Part 75
  Fluorescence Spectroscopy.
ASTM D 4294-98, Standard Test Method for Sulfur in                  75.6
Petroleum and Petroleum Products by Energy-
[[Page 1105]]-ray Fluorescence Spectrometry, 
  1998.
ASTM D 4294-03 Standard Test Method for Sulfur in                 80.580
  Petroleum and Petroleum Products by Energy-
  Dispersive X-Ray Fluorescence Spectrometry.
ASTM D 4468-85 (Reapproved 1989) Standard Test     Appendix D of Part 75
  Method for Total Sulfur in Gaseous Fuels by 
  Hydrogenolysis and Rateometric Calorimetry.
ASTM D 4468-85 (Reapproved 2000) Standard Test                     80.46
  Method for Total Sulfur in Gaseous Fuels by 
  Hydrogenolysis and Rateometric Calorimetry.
ASTM D 4468-85 (Reapproved 2006), Standard Test                     75.6
  Method for Total Sulfur in Gaseous Fuels by 
  Hydrogenolysis and Rateometric, 2006.
ASTM D 4809-00, Standard Test Method for Heat of                    75.6
  Combustion of Liquid Hydrocarbon Fuels by Bomb 
  Calorimeter (Precision Method), 2000.
ASTM D 4814-93a, Standard Specification for             79.56(d)(5) and 
  Automotive Spark-Ignition Engine Fuel.                          (e)(3)
ASTM D 4814-95c, Standard Specification for                 80.164(a)(5)
  Automotive Spark-Ignition Engine Fuel.
ASTM D 4815-93, Standard Test Method for                           80.46
  Determination of MTBE, ETBE, TAME, DIPE, 
  tertiary-Amyl Alcohol and C1 to 
  C4 Alcohols in Gasoline by Gas 
  Chromatography.
ASTM D 4815-99, Standard Test Method for                           80.46
  Determination of MTBE, ETBE, TAME, DIPE, 
  tertiary-Amyl Alcohol and C1 to 
  C4 Alcohols in Gasoline by Gas 
  Chromatography.
ASTM D 4815-03, Standard Test Method for                           80.46
  Determination of MTBE, ETBE, TAME, DIPE, 
  tertiary-Amyl Alcohol and C1 to 
  C4 Alcohols in Gasoline by Gas 
  Chromatography.
ASTM D 4840-99 (Reapproved 2004), Standard Guide         75.6; Part 75, 
  for Sample Chain-of-Custody Procedures.           Appendix K, section 
                                                                   7.2.9
ASTM D 4891-89 Standard Test Method for Heating    Appendix F of Part 75
  Value of Gases in Natural Gas Range by 
  Stolchiometric Combustion.
ASTM D 5191-01, Standard Test Method for Vapor                     80.46
  Pressure of Petroleum Products (Mini Method).
ASTM D 4891-89 (Reapproved 2006, Standard Test                      75.6
  Method for Heating Value of Gases in Natural Gas 
  Range by Stoichiometric Combustion, 2006.
ASTM D 5291-92 Standard Test Methods for           Appendix G of Part 75
  Instrumental Determination of Carbon, Hydrogen, 
  and Nitrogen in Petroleum Products and 
  Lubricants.
ASTM D 5291-02, Standard Test Methods for                           75.6
  Instrumental Determination of Carbon and 
  Hydrogen, and Nitrogen in Petroleum Products and 
  Lubricants, 2002.
ASTM D 5373-02 (Reapproved 2007), Standard Test                     75.6
  Methods for Instrumental Determination of 
  Carbon, Hydrogen, and Nitrogen in Laboratory 
  Samples of Coal and Coke, 2007.
ASTM D 5453-03a, Standard Test Method for                  80.46; 80.580
  Determination of Total Sulfur in Light 
  Hydrocarbons, Motor Fuels and Oils by 
  Ultraviolet Fluorescence.
ASTM D 5453-06, Standard Test Method for                            75.6
Determination of Total Sulfur in Light 
[[Page 1106]], Spark Ignition Engine Fuel, Diesel 
  Engine Fuel, and Engine Oil by Ultraviolet 
ASTM D 5500-94, Standard Test Method for Vehicle               80.165(b)
  Evaluation of Unleaded Automotive Spark-Ignition 
  Fuel for Intake Valve Deposit Formation.
ASTM D 5504-94, Standard Test Method for           Appendix D of Part 75
  Determination of Sulfur Compounds in Natural Gas 
  and Gaseous Fuels by Gas Chromatography and 
  Chemiluminescence.
ASTM D 5598-94, Standard Specification for                     80.165(a)
  Evaluating Unleaded Automotive Spark-Ignition 
  Engine Fuel for Electronic Port Fuel Injector 
  Fouling.
ASTM D 5504-01, Standard Test Method for                            75.6
  Determination of Sulfur Compounds in Natural Gas 
  and Gaseous Fuels by Gas Chromatography and 
  Chemiluminescence, 2001.
ASTM D 5599-00, Standard Test Method for                           80.46
  Determination of Oxygenates in Gasoline by Gas 
  Chromatography and Oxygen Selective Flame 
  Ionization Detection.
ASTM D 5769-98, Standard Test Method for                           80.46
  Determination of Benzene, Toluene, and Total 
  Aromatics in Finished Gasolines by Gas 
  Chromatography (Mass Spectrometry).
ASTM D 5842-95, Standard Practice for Sampling and                80.330
  Handling of Fuels for Volatility Measurement.
ASTM D 5842-95 (Reapproved 2000), Standard                          80.8
  Practice for Sampling and Handling of Fuels for 
  Volatility Measurement.
ASTM D 5854-96 (Reapproved 2000), Standard                          80.8
  Practice for Mixing and Handling of Liquid 
  Samples of Petroleum and Petroleum Products.
ASTM D5865-01a, Standard Test Method for Gross                      75.6
  Calorific Value of Coal and Coke, 2001.
ASTM D 6299-02, Standard Practice for Applying            80.582, 80.585
  Statistical Quality Assurance Techniques to 
  Evaluate Analytical Measurement System 
  Performance.
ASTM D 6428-99, Standard Test Method for Total             80.46; 80.580
  Sulfur in Liquid Aromatic Hydrocarbons and their 
  Derivatives by Oxidative Combustion and 
  Electrochemical Detection.
ASTM D 6667-01, Standard Test Method for                           80.46
  Determination of Total Volatile Sulfur in 
  Gaseous Hydrocarbons and Liquefied Petroleum 
  Gases by Ultraviolet Fluorescence.
ASTM D 6667-04, Standard Test Method for                            75.6
  Determination of Total Volatile Sulfur in 
  Gaseous Hydrocarbons and Liquified Petroleum 
  Gases by Ultraviolet Fluorescence, 2004.
ASTM D 6751-07, Standard Specification for                       80.1101
  Biodiesel Fuel Blend Stock (B100) for Middle 
  Distillate Fuels, 2007.
ASTM D 6784-02, Standard Test Method for                     75.6; 75.22
  Elemental, Oxidized, Particle-bound and Total 
  Mercury in Flue Gas Generated from Coal-fired 
  Stationary Sources (Ontario-Hydro Method).
ASTM D 6911-03, Standard Guide for Packaging and         75.6; Part 75, 
  Shipping Environmental Samples for Laboratory     Appendix K, section 
  Analysis.                                                        7.2.8
ASTM D 6920-03, Standard Test Method for Total             80.46; 80.580
  Sulfur in Naphthas, Reformulated Gasolines, 
  Diesels, Biodiesels, and Motor Fuels by 
  Oxidative Combustion and Electrochemical 
  Detection.ce, 2006.
ASTM D 7036-04, Standard Practice for Competence                    75.6
of Air Emission Testing Bodies, 2004.
[[Page 1107]]

ASTM D 7039-04, Standard Test Method for Total                     80.46
  Sulfur in Gasoline and Diesel Fuel by 
  Monochromatic Wavelength Dispersive X-ray 
  Fluorescence Spectrometry.
ASTM E1-86, Standard Specification for ASTM        Appendix E of Part 80
  Thermometers.
ASTM E 29-02, Standard Practice for Using                           80.9
  Significant Digits in Test Data to Determine 
  Conformance with Specifications.


California Air Resources Board, Stationary Source Division

  2020 L St., P.O. Box 285, Sacramento, CA 95814
BMW-10,000 Miles Intake Valve Test Procedure,                  80.165(c)
  March 1, 1991.
Test Method for Evaluating Port Fuel Injector                  80.165(c)
  (PFI) Deposits in Vehicle Engines, March 1, 
  1991.


Gas Processors Association

  6526 East 60th Street, Tulsa, OK 74145
GPA Standard 2172-86, Calculation of Gross Heating Appendices D, E, and 
  Value, Relative Density and Compressibility               F of Part 75
  Factor for Natural Gas Mixtures from 
  Compositional Analysis.
GPA Standard 2172-96, Calculation of Gross Heating                  75.6
  Value, Relative Density and Compressibility 
  Factor for Natural Gas Mixtures from 
  Compositional Analysis, 1996.
GPA Standard 2261-90, Analysis for Natural Gas and Appendices D, F, and 
  Similar Gaseous Mixtures by Gas Chromatography.           G of Part 75
GPA Standard 2261-00, Analysis for Natural Gas and                  75.6
  Similar Gaseous Mixtures by Gas Chromatography, 
  2000.


Institute of Internal Auditors, Inc.

  249 Maitland Avenue, Altamonte Springs, FL 
  32701-4201
Codification of Standards for the Professional                    80.125
  Practice of Internal Auditing, 1989, 
  Identification Number ISBN 0-89413-207-5.


International Organization for Standardization

  Case Postale 56, CH-1211 Geneve 20, Switzerland
ISO 8316: 1987(E), Measurement of Liquid Flow in    75.20; Appendices D 
  Closed Conduits--Method of Collection of the          and E of Part 75
  Liquid in a Volumetric Tank.
ISO 9931 (December 1991), Coal--Sampling of                  76.4; 76.15
  Pulverized Coal Conveyed by Gases in Direct 
  Fired Coal Systems.


U.S. Government Printing Office

  Washington, DC 20402-9371; Telephone: (202) 512-
  1800; Telefacsimile: (202) 275-0019
U.S. Department of Health and Human Services,      79.61(c)(3), (d)(2), 
  Guide for the Care and Use of Laboratory                    and (d)(4)
  Animals, 1985.

[[Page 1109]]



                    Table of CFR Titles and Chapters




                      (Revised as of July 1, 2008)

                      Title 1--General Provisions

         I  Administrative Committee of the Federal Register 
                (Parts 1--49)
        II  Office of the Federal Register (Parts 50--299)
        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 100--
                199)
        II  Office of Management and Budget Circulars and Guidance 
                (200--299)
            Subtitle B--Federal Agency Regulations for Grants and 
                Agreements
       III  Department of Health and Human Services (Parts 300-- 
                399)
        VI  Department of State (Parts 600--699)
      VIII  Department of Veterans Affairs (Parts 800--899)
        IX  Department of Energy (Parts 900--999)
        XI  Department of Defense (Parts 1100--1199)
       XII  Department of Transportation (Parts 1200--1299)
       XIV  Department of the Interior (Parts 1400--1499)
        XV  Environmental Protection Agency (Parts 1500--1599)
     XVIII  National Aeronautics and Space Administration (Parts 
                1880--1899)
      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)
    XXVIII  Department of Justice (Parts 2800--2899)
     XXXII  National Endowment for the Arts (Parts 3200--3299)
    XXXIII  National Endowment for the Humanities (Parts 3300--
                3399)
      XXXV  Export-Import Bank of the United States (Parts 3500--
                3599)
    XXXVII  Peace Corps (Parts 3700--3799)

[[Page 1110]]

                        Title 3--The President

         I  Executive Office of the President (Parts 100--199)

                           Title 4--Accounts

         I  Government Accountability Office (Parts 1--99)

                   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)
         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)
        XV  Office of Administration, Executive Office of the 
                President (Parts 2500--2599)
       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)
      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)
      XXXV  Office of Personnel Management (Parts 4500--4599)
        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)
         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)

[[Page 1111]]

       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)
      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)
     LXXVI  Federal Retirement Thrift Investment Board (Parts 
                8600--8699)
    LXXVII  Office of Management and Budget (Parts 8700--8799)
     XCVII  Department of Homeland Security Human Resources 
                Management System (Department of Homeland 
                Security--Office of Personnel Management) (Parts 
                9700--9799)
      XCIX  Department of Defense Human Resources Management and 
                Labor Relations Systems (Department of Defense--
                Office of Personnel Management) (Parts 9900--9999)

                      Title 6--Domestic Security

         I  Department of Homeland Security, Office of the 
                Secretary (Parts 0--99)
         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)

[[Page 1112]]

       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)
        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)
      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  Cooperative State Research, Education, and Extension 
                Service, Department of Agriculture (Parts 3400--
                3499)

[[Page 1113]]

      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)
         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 1303--
                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)

                      Title 12--Banks and Banking

         I  Comptroller of the Currency, Department of the 
                Treasury (Parts 1--199)
        II  Federal Reserve System (Parts 200--299)

[[Page 1114]]

       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)
        XI  Federal Financial Institutions Examination Council 
                (Parts 1100--1199)
       XIV  Farm Credit System Insurance Corporation (Parts 1400--
                1499)
        XV  Department of the Treasury (Parts 1500--1599)
      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, Department of 
                Commerce (Parts 400--499)
         V  Emergency Oil and Gas Guaranteed Loan Board, 
                Department of Commerce (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--499)
         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)

[[Page 1115]]

       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)
       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  Bureau of Customs and Border Protection, Department of 
                Homeland Security; Department of the Treasury 
                (Parts 0--199)
        II  United States International Trade Commission (Parts 
                200--299)

[[Page 1116]]

       III  International Trade Administration, Department of 
                Commerce (Parts 300--399)
        IV  Bureau of 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)
         V  Employment and Training Administration, Department of 
                Labor (Parts 600--699)
        VI  Employment Standards Administration, 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  Millenium Challenge Corporation (Parts 1300--1399)

[[Page 1117]]

       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)
       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 
                HousingCommissioner, 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)

[[Page 1118]]

         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)
        XX  Office of Assistant Secretary for Housing--Federal 
                Housing Commissioner, Department of Housing and 
                Urban Development (Parts 3200--3899)
       XXV  Neighborhood Reinvestment Corporation (Parts 4100--
                4199)

                           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--899)

           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)

[[Page 1119]]

      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)
        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  Minerals Management Service, Department of the 
                Interior (Parts 200--299)
       III  Board of Surface Mining and Reclamation Appeals, 
                Department of the Interior (Parts 300--399)
        IV  Geological Survey, Department of the Interior (Parts 
                400--499)
       VII  Office of Surface Mining Reclamation and Enforcement, 
                Department of the Interior (Parts 700--999)

                 Title 31--Money and Finance: Treasury

            Subtitle A--Office of the Secretary of the Treasury 
                (Parts 0--50)

[[Page 1120]]

            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)
      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)

                      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)

[[Page 1121]]

            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)
        IV  Office of Vocational and Adult Education, Department 
                of Education (Parts 400--499)
         V  Office of Bilingual Education and Minority Languages 
                Affairs, Department of Education (Parts 500--599)
        VI  Office of Postsecondary Education, Department of 
                Education (Parts 600--699)
       VII  Office of Educational Research and Improvmeent, 
                Department of Education [Reserved]
        XI  National Institute for Literacy (Parts 1100--1199)
            Subtitle C--Regulations Relating to Education
       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  Copyright Office, Library of Congress (Parts 200--299)
       III  Copyright Royalty Board, Library of Congress (Parts 
                301--399)

[[Page 1122]]

        IV  Assistant Secretary for Technology Policy, Department 
                of Commerce (Parts 400--499)
         V  Under Secretary for Technology, Department of Commerce 
                (Parts 500--599)

           Title 38--Pensions, Bonuses, and Veterans' Relief

         I  Department of Veterans Affairs (Parts 0--99)

                       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)

          Title 41--Public Contracts and Property Management

            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)
            Chapters 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)
            Chapters 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)

[[Page 1123]]

            Chapters 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)
       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--499)
         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 200--499)
        II  Bureau of Land Management, Department of the Interior 
                (Parts 1000--9999)
       III  Utah Reclamation Mitigation and Conservation 
                Commission (Parts 10000--10010)

             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

[[Page 1124]]

        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)
        VI  National Science Foundation (Parts 600--699)
       VII  Commission on Civil Rights (Parts 700--799)
      VIII  Office of Personnel Management (Parts 800--899) 
                [Reserved]
         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)

[[Page 1125]]

       III  National Telecommunications and Information 
                Administration, Department of Commerce (Parts 
                300--399)

           Title 48--Federal Acquisition Regulations System

         1  Federal Acquisition Regulation (Parts 1--99)
         2  Defense Acquisition Regulations System, Department of 
                Defense (Parts 200--299)
         3  Department of 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 [Reserved]
        54  Defense Logistics Agency, Department of Defense (Parts 
                5400--5499)

[[Page 1126]]

        57  African Development Foundation (Parts 5700--5799)
        61  General Services Administration Board of Contract 
                Appeals (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)

                       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, Department of 
                Transportation (Parts 1000--1399)
        XI  Research and Innovative Technology Administration, 
                Department of Transportation [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)

[[Page 1127]]

        VI  Fishery Conservation and Management, National Oceanic 
                and Atmospheric Administration, Department of 
                Commerce (Parts 600--699)

                      CFR Index and Finding Aids

            Subject/Agency Index
            List of Agency Prepared Indexes
            Parallel Tables of Statutory Authorities and Rules
            List of CFR Titles, Chapters, Subchapters, and Parts
            Alphabetical List of Agencies Appearing in the CFR

[[Page 1129]]





           Alphabetical List of Agencies Appearing in the CFR




                      (Revised as of July 1, 2008)

                                                  CFR Title, Subtitle or 
                     Agency                               Chapter

Administrative Committee of the Federal Register  1, I
Advanced Research Projects Agency                 32, I
Advisory Council on Historic Preservation         36, VIII
African Development Foundation                    22, XV
  Federal Acquisition Regulation                  48, 57
Agency for International Development              22, II
  Federal Acquisition Regulation                  48, 7
Agricultural Marketing Service                    7, I, IX, X, XI
Agricultural Research Service                     7, V
Agriculture Department                            5, LXXIII
  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
  Cooperative State Research, Education, and      7, XXXIV
       Extension Service
  Economic Research Service                       7, XXXVII
  Energy, 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
  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
Animal and Plant Health Inspection Service        7, III; 9, I
Appalachian Regional Commission                   5, IX

[[Page 1130]]

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
Benefits Review Board                             20, VII
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
Census Bureau                                     15, I
Centers for Medicare & Medicaid Services          42, IV
Central Intelligence Agency                       32, XIX
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
Coast Guard                                       33, I; 46, I; 49, IV
Coast Guard (Great Lakes Pilotage)                46, III
Commerce Department                               44, IV
  Census Bureau                                   15, I
  Economic Affairs, Under Secretary               37, V
  Economic Analysis, Bureau of                    15, VIII
  Economic Development Administration             13, III
  Emergency Management and Assistance             44, IV
  Federal Acquisition Regulation                  48, 13
  Fishery Conservation and Management             50, VI
  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, VI
  National Oceanic and Atmospheric                15, IX; 50, II, III, IV, 
       Administration                             VI
  National Telecommunications and Information     15, XXIII; 47, III
       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, Under Secretary for                 37, V
  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 Product Safety Commission                5, LXXI; 16, II
Cooperative State Research, Education, and        7, XXXIV
     Extension Service
Copyright Office                                  37, 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    28, VIII
     for the District of Columbia
Customs and Border Protection Bureau              19, I
Defense Contract Audit Agency                     32, I
Defense Department                                5, XXVI; 32, Subtitle A; 
                                                  40, VII

[[Page 1131]]

  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          28, VIII
     Offender Supervision Agency for the
Drug Enforcement Administration                   21, II
East-West Foreign Trade Board                     15, XIII
Economic Affairs, Under Secretary                 37, V
Economic Analysis, Bureau of                      15, VIII
Economic Development Administration               13, III
Economic Research Service                         7, XXXVII
Education, Department of                          5, LIII
  Bilingual Education and Minority Languages      34, V
       Affairs, Office 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
  Vocational and Adult Education, Office of       34, IV
Educational Research and Improvement, Office of   34, VII
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                             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
  Administration, Office of                       5, XV
  Environmental Quality, Council on               40, V
  Management and Budget, Office of                5, III, LXXVII; 14, VI; 
                                                  48, 99
  National Drug Control Policy, Office of         21, III
  National Security Council                       32, XXI; 47, 2
  Presidential Documents                          3

[[Page 1132]]

  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                       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 Board                     12, IX
Federal Labor Relations Authority, and General    5, XIV; 22, XIV
     Counsel of the Federal Labor Relations 
     Authority
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
Fine Arts, Commission on                          45, XXI
Fiscal Service                                    31, II
Fish and Wildlife Service, United States          50, I, IV
Fishery Conservation and Management               50, VI
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
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

[[Page 1133]]

  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
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                  6, I
  Coast Guard                                     33, I; 46, I; 49, IV
  Coast Guard (Great Lakes Pilotage)              46, III
  Customs and Border Protection Bureau            19, I
  Federal Emergency Management Agency             44, I
  Immigration and Customs Enforcement Bureau      19, IV
  Immigration and Naturalization                  8, I
  Transportation Security Administration          49, XII
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 and Naturalization                    8, I
Immigration Review, Executive Office for          8, V
Independent Counsel, Office of                    28, VII
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
[[Page 1134]]

Inspector General
  Agriculture Department                          7, XXVI
  Health and Human Services Department            42, V
  Housing and Urban Development Department        24, XII
Institute of Peace, United States                 22, XVII
Inter-American Foundation                         5, LXIII; 22, X
Interior Department
  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
  Minerals Management Service                     30, II
  National Indian Gaming Commission               25, III
  National Park Service                           36, I
  Reclamation, Bureau of                          43, I
  Secretary of the Interior, Office of            2, XIV; 43, Subtitle A
  Surface Mining and Reclamation Appeals, Board   30, III
       of
  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 Fishing and Related Activities      50, III
International Investment, Office of               31, VIII
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
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, XXVII; 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
  Offices of Independent Counsel                  28, VI
  Prisons, Bureau of                              28, V
  Property Management Regulations                 41, 128
Labor Department                                  5, XLII
  Benefits Review Board                           20, VII
  Employee Benefits Security Administration       29, XXV
  Employees' Compensation Appeals Board           20, IV
  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

[[Page 1135]]

  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
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 Office                                37, II
  Copyright Royalty Board                         37, III
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
Millenium Challenge Corporation                   22, XIII
Mine Safety and Health Administration             30, I
Minerals Management Service                       30, II
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
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   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                    34, XII
National Counterintelligence Center               32, XVIII
National Credit Union Administration              12, VII
National Crime Prevention and Privacy Compact     28, IX
     Council
National Drug Control Policy, Office of           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 Highway Traffic Safety Administration    23, II, III; 49, V
National Imagery and Mapping Agency               32, I
National Indian Gaming Commission                 25, III
National Institute for Literacy                   34, XI
National Institute of Standards and Technology    15, II
National Intelligence, Office of Director of      32, XVII
National Labor Relations Board                    5, LXI; 29, I
National Marine Fisheries Service                 50, II, IV, VI
National Mediation Board                          29, X
National Oceanic and Atmospheric Administration   15, IX; 50, II, III, IV, 
                                                  VI
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
     Administration
National Transportation Safety Board              49, VIII
Natural Resources Conservation Service            7, VI

[[Page 1136]]

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                     5, XLVIII; 10, I
  Federal Acquisition Regulation                  48, 20
Occupational Safety and Health Administration     29, XVII
Occupational Safety and Health Review Commission  29, XX
Offices of Independent Counsel                    28, VI
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                                       22, III
Pennsylvania Avenue Development Corporation       36, IX
Pension Benefit Guaranty Corporation              29, XL
Personnel Management, Office of                   5, I, XXXV; 45, VIII
  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
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                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 and Reclamation Appeals, Board of  30, III

[[Page 1137]]

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
Technology, Under Secretary for                   37, V
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; 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
  Surface Transportation Board                    49, X
  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                               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 Bureau            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
  Fiscal Service                                  31, II
  Foreign Assets Control, Office of               31, V
  Internal Revenue Service                        26, I
  International Investment, 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
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
Vocational and Adult Education, Office of         34, IV
Wage and Hour Division                            29, V
Water Resources Council                           18, VI
Workers' Compensation Programs, Office of         20, I
World Agricultural Outlook Board                  7, XXXVIII

[[Page 1139]]



List of CFR Sections Affected



All changes in this volume of the Code of Federal Regulations that were 
made by documents published in the Federal Register since January 1, 
2001, 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 and parts as well as 
sections for revisions.
Title 40 was established at 36 FR 12213, June 29, 1971. For the period 
before January 1, 2001, see the ``List of CFR Sections Affected, 1964-
1972, 1973-1985, and 1986-2000'' published in ten separate volumes.

                                  2001

40 CFR
                                                                   66 FR
                                                                    Page
Chapter I
72.2 Corrected; CFR Correction.....................................42761
72.6 (b)(9) amended................................................12978
    Corrected; CFR correction......................................42761
72.9 (c)(6), (g)(1) and (h) amended................................12978
72.14 Removed......................................................12978
72.70 (b) amended..................................................12978
72.72 (b)(6) removed...............................................12978
72.83 (a)(13) amended..............................................12978
74.2 Amended.......................................................12978
75.10 (g) correctly added; CFR correction..........................31842
75.32 (a)(3) corrected; CFR correction.............................31842
78.1 (b)(1)(v) removed.............................................12978
78.12 (a)(2) amended...............................................12978
80 Exemption petition..............................................71067
    Authority citation revised...............................5135, 17262
    Regulation at 65 FR 71067 eff. date delayed.....................8089
80.2 (x) and (y) revised; (bb), (nn) and (xx) added.................5135
    (d) revised....................................................17262
80.24 (c) added....................................................54959
80.29 (a) and (b) revised...........................................5135
80.30 (g)(2)(ii) and (4)(i) revised; (h) added......................5135
80.40 (c) added....................................................37164
80.41 (e) and (f) revised..........................................37164
80.46 (f)(3), (g)(9) and (h) revised...............................53189
    (e) and (h) revised............................................17263
80.65 (d)(2)(ii) revised...........................................37165
    (i) revised....................................................67105
80.67 (g)(1) revised...............................................37165
80.68 (c)(8)(ii)(B) amended; (c)(8)(ii)(C) added...................37165
80.69 Introductory text revised....................................37165
80.74 (b)(5) and (6) amended; (b)(7) added.........................67106
80.75 (a)(2)(vi) and (vii) amended; (a)(2)(viii) added.............67106
80.78 (a)(5) and (10) revised; (a)(7)(i) and (ii) amended; 
        (a)(7)(iii) and (11) added.................................67106
80.81 (a) revised..................................................17263
    (a) correctly revised; CFR correction..........................66769
80.101 (a) revised; (k) added......................................54431
    (g)(9) added...................................................67107
80.104 (a)(2)(xii) added...........................................67107
80.105 (a)(5)(vi) added............................................67108
80.131 Added.......................................................67108
80.162 (a)(3)(i)(B), (ii) and (d) revised..........................55889
80.169 (c)(4)(i)C)(2) revised......................................55890
80.215 (b) revised..................................................5136
    (a)(2) and (3) revised; (a)(4) added...........................19306
80.216 (a)(1)(i) and (2) revised...................................19306
80.217 (b) revised.................................................19306
80.220 (c) added....................................................5136
80.225 (d) revised.................................................19306
80.230 (a)(1) revised..............................................19307
80.235 (c)(2), (f) and (g)(1) revised..............................19307
80.240 (e) added....................................................5136
80.245 (a)(3) revised; (c) added...................................19307
80.250 (a)(1) and (2) amended; (a)(3) and (4) added; (b) removed 
                                                                   19307

[[Page 1140]]

80.285 (a)(1)(i), (ii), (iii), (b)(1)(i), (ii) and (2) revised.....19307
80.290 (c)(6) added; (d) revised...................................19308
80.295 (a) amended; (b) revised; (c) added.........................19308
80.305 (a) amended; (d) revised....................................19308
80.310 (b) amended.................................................19308
80.330 (a)(3) and (4) revised......................................19308
80.335 (a)(2) revised; (d) and (e) added...........................19309
80.340 (c) added...................................................67108
80.410 (d)(1), (3)(ii), (f)(2)(ii) introductory text and (s) 
        introductory text revised..................................19309
80.500--80.620 (Subpart I) Added....................................5136
80.800--80.1045 (Subpart J) Added..................................17263

                                  2002

40 CFR
                                                                   67 FR
                                                                    Page
Chapter I
72 Technical correction.............................................1295
72.2 Amended.......................................................40420
    72.2 Corrected.................................................53504
75 Technical correction.............................................1295
    Nomenclature change............................................40476
75.1 (a) amended...................................................40421
75.4 (b)(2), (c)(2), (d), (e) introductory text and (i)(1) 
        amended; (d)(1), (f) introductory text, (1), (i)(2) and 
        (3) revised; (j) added.....................................40421
75.6 (a)(17), (18), (19), (26) and (35) amended....................40422
75.10 (a)(1), (2), (3)(i), (iii), (4), (c), (d)(1), (3) and (f) 
        (a)(5) added; (g) heading revised..........................40422
75.11 (b)(2), (e)(1), (2), (3) and (iii) amended...................40423
75.12 Section heading revised; (a), (d)(2) and (e) amended.........40423
75.13 (b) and (c) amended..........................................40423
75.15 Removed......................................................40423
75.16 Section heading, (e) heading, introductory text and (1) 
        through (4) amended; (a) removed; (b) heading, 
        introductory text and (c) revised..........................40423
    (e)(1) corrected...............................................53504
75.17 Section heading, introductory text, (b)(1) and (c) 
        introductory text amended; (c) heading, (1) and (2) 
        revised; (d) added.........................................40424
75.19 Section heading, (a), (b)(1), (2), (3), (4)(i), (5), 
        (c)(1)(i) through (iv)(C), (3)(ii)(C), (D) introductory 
        text, (1), (E) through (H) and (e)(2) revised; (b)(4) 
        introductory text, (ii), (iii), (c)(1)(iv) introductory 
        text, (A), (B)(4), (D), (E), (G), (H), (1), (2) 
        introductory text, (iii), (iv), (3)(i)(A), (B), (4)(i)(A), 
        (ii)(A), (iii)(A), (e) tables and (5) amended; 
        (c)(1)(iv)(B)(3) removed; (c)(1)(iv)(H)(2) redesignated as 
        (c)(1)(iv)(H)(3) and amended; (c)(1)(iv)(I), (J) and 
        (e)(6) added...............................................40424
    (c)(1)(iv)(h)(3), (3)(ii)(G) and (H) corrected.................53504
75.20 (b)(3)(i), (c)(2)(ii), (iii), (4) introductory text, (i), 
        (ii), (iii), (g)(2), (h)(1), (3), (4) introductory text, 
        (i) and (ii) revised; (a), (3), (4)(iii), (iv), (5)(i), 
        (b)(2), (5), (c) introductory text, (d)(2)(iii), (v), 
        (vii), (g)(1)(i), (5) and (h)(2) amended; second (c)(1)(v) 
        and (h)(4)(iii) removed; (c)(2)(iv) and (h)(5) added.......40431
75.21 (a)(7), (8), (9) and (e)(2) amended..........................40433
    (a)(7) corrected...............................................53505
75.22 (a) introductory text, (4) and (5) amended...................40433
    (a)(4) corrected...............................................53505
75.24 (a)(1) revised; (c)(2) amended...............................40433
75.30 (a)(6), (b), (d)(1) and (2) amended; (a)(7) and (8) added; 
        eff. 7-12-02...............................................40433
75.31 (a), (c)(2) and (3) amended; (c) introductory text heading 
        and (1) revised; (d) added.................................40433
75.32 (a) introductory text and (2) revised; (a)(1) and (3) 
        amended....................................................40434
75.33 (a) and (c) introductory text revised; (b)(5), (6), (7), 
        (c)(7), (8), (9), (d), (e) and Tables 3 and 4 added; 
        (c)(1) introductory text, (i), (ii)(A), (2) introductory 
        text, (i), (ii)(A), and (3) through (6) amended............40434
    (c)(7) corrected...............................................53505
    Corrected......................................................57274

[[Page 1141]]

75.34 (a) introductory text, (1) and (d) revised; (a)(2) and (3) 
        redesignated as (a)(3) and (4); new (a)(2) added; new 
        (a)(4) and (c) amended.....................................40438
75.35 Revised......................................................40439
75.36 Section heading and (b) revised; (a) and (d) amended; (c) 
        removed....................................................40439
75.37 (a) and (d) introductory text amended; (c) and (d)(2)(i) 
        revised....................................................40439
75.41 (b)(2)(v)(B) and (c)(2)(ii) amended..........................40440
75.53 (a)(1), (e)(1)(viii) and (f)(1)(i)(F) revised; (b), 
        (e)(1)(i) introductory text, (D), (E), (ix), (xii) 
        introductory text, (A) through (E), (f)(2)(i)(F), (H), (5) 
        introductory text, (i), (ii)(C) and (E) amended; (c) and 
        (d) removed; (f)(5)(i)(A) through (F) added................40440
    Corrected......................................................57274
75.54 Removed......................................................40440
75.55 Removed......................................................40440
75.56 Removed......................................................40440
75.57 Introductory text and (c)(4)(iv) Table 4a revised; (a)(3), 
        (4), (d)(6) and (7) amended................................40440
75.58 Introductory text and (b)(3) introductory text revised; 
        (b)(1)(i), (xi), (2)(vii), (3)(i) through (iv), (c) 
        introductory text, (7)(ii), (d) introductory text, (e)(1), 
        (f) introductory text and (1)(iii) amended.................40441
75.59 Introductory text, (a)(7)(ii)(P) and (iii)(F) revised; 
        (d)(2) redesignated as (d)(3); (a)(1)(vii), (5)(ii)(E), 
        (F), (L), (iii)(E), (7), (ii)(A), (P), (iii)(F), 
        (10)(i)(E), (12)(v) introductory text, (C), (E), (D), 
        (b)(2)(v), (4)(ii)(K), (L), (c)(1), (d)(1) introductory 
        text, (xi), (xii) and new (3)(x) amended; (d)(1)(xiii) 
        through (xvi) removed; (b)(4)(ii)(M) and new (d)(2) added 
                                                                   40442
75.60 (b)(6) amended; (b(7) added..................................40442
75.61 (a)(1) introductory text, (i) through (iv), (2) introductory 
        text, (i), (ii), (4), (5) and (ii) amended; (a)(6) revised
                                                                   40442
75.62 (a)(1) revised; (a)(2) amended...............................40443
75.63 (a)(1)(i) and (ii) revised; (a)(1)(iii) removed; Section 
        heading, (a)(2) heading, (i), (ii), (iii), (b)(1)(i), (ii) 
        and (2)(i) amended.........................................40443
75.64 (a) introductory text, (2) introductory text, (iii), (iv), 
        (vi), (vii), (viii), (xi), (4), (d) and (f) amended; 
        (a)(2)(v), (8) and (e) removed.............................40443
75.65 Amended......................................................40443
75.66 (e) and (f) introductory text amended; (i) removed...........40444
75.70 (a)(1), (d)(1), (f) introductory text, (1) introductory 
        text, (i) through (iv), (g)(1) and (2) amended; (e) and 
        (g)(6) revised; (f)(1)(v) added; (i) removed...............40444
75.71 (a)(1), (2), (b)(1), (3), (c)(2) and (d)(2) amended..........40444
    Corrected......................................................53505
75.72 (a)(1) introductory text, (i), (b)(1)(ii)(A), (c) and (d) 
        revised; (a)(1)(ii) redesignated as (a)(1)(iii); 
        (a)(1)(ii) added; introductory text, new (a)(1)(iii)(A), 
        (B), (2) introductory text, (ii)(A), (b)(1) introductory 
        text, (2)(ii), (iii), (e) introductory text, (1) 
        introductory text, (i), (2) and (g) amended................40445
75.73 (a), (6) introductory text, (c)(3) and (e)(2) amended; 
        (a)(6)(i) through (vi), (e)(1)(i) and (ii) removed; (e)(1) 
        revised; (a)(8), (d)(6), (f)(1)(vii) and (viii) added......40446
75.74 (c)(2)(i)(D)(1), (ii)(C), (H)(1), (6)(v), (7)(ii), (8)(ii) 
        and (10) revised; (c)(7)(iii) added; (c)(2)(ii) 
        introductory text, (A), (3)(iii), (iv), (v), (vi)(B), (x), 
        (xi), (xii)(A), (B), (4), (5) and (11) amended.............40446
    Corrected......................................................57274
75 Appendix A amended...........40448, 40449, 40452, 40453, 40455, 40457
    Appendix B amended.............................................40456
    Appendix C amended.............................................40459

[[Page 1142]]

    Appendix D amended......................................40460, 40472
    Appendix E amended......................................40473, 40474
    Appendix F amended......................................40474, 40475
    Appendix G amended.............................................40475
    Appendices A, B, D and E corrected.............................53505
    Appendices B, D and G corrected................................57274
80.8 Added..........................................................8736
80.24 Regulation at 66 FR 54959 and 66867 correctly withdrawn......36676
    (c) added......................................................36771
80.27 (a)(2) table amended..........................................3440
    (b) and (d)(2) revised..........................................8736
    Regulation at 67 FR 3440 withdrawn.............................13092
80.28 (g)(2)(ii) and (4)(i) revised.................................8736
80.40 (c)(1) revised................................................8736
80.46 (b), (c), (d), (f), (g) and (h) revised.......................8737
    (a)(2) revised; (h) amended....................................40181
80.65 (d)(3) revised................................................8737
80.70 (j) introductory text, (k), (l) and (m) revised; (j)(5) and 
        (n) removed................................................38403
80.91 (a)(1)(ii) amended; (a)(1)(iii) removed.......................8737
80.92 (a)(1) amended................................................8737
80.101 (f)(4) correctly removed; CFR correction.....................4674
    (d)(2), (e)(2) and (h)(2)(iii) removed; (h)(2)(i) and (ii) 
revised.............................................................8738
80.102 Removed......................................................8738
80.104 (a)(1)(i) revised; (a)(2)(ix) removed........................8738
80.105 (a)(2) and (3) removed.......................................8738
80.106 (b) removed..................................................8738
80.128 (h) and (i) removed..........................................8738
80.162 Regulation at 66 FR 55889 withdrawn in part..................3440
80.195 (b)(4) and (c)(4) revised; (c)(5)(iii) and (6) added........40181
80.205 (a) amended; (f) removed....................................40182
80.210 (e)(5), (6) and (7) added...................................40182
80.216 (a) and (f) revised.........................................40182
80.225 (d) revised.................................................38340
    (a)(2) revised.................................................40182
80.271 Added.......................................................40182
80.275 (a)(1) revised; (a)(2)(i), (ii) and (v) amended; (b)(4), 
        (e)(3) and (h) added; (c)(2) redesignated as (c)(2)(i); 
        new (c)(2)(ii) added.......................................40183
80.285 (b)(1)(ii) revised..........................................40183
80.305 (f) added...................................................40183
80.310 (a) revised; (b) amended; (d) added.........................40184
    Regulation at 57 FR 40184 withdrawn in part....................54743
80.315 (a) introductory text and (b)(1) introductory text revised 
                                                                   40184
80.365 (d)(2) revised..............................................40184
80.370 (a)(4) revised; (a)(7)(v), (c)(4) and (5) added.............40184
80.385 (b) revised; (g) added eff. 9-10-02.........................40184
80.395 (a)(5), (6) and (12) revised; (a)(13) added.................40184
80.405 (e) added...................................................40185
80.410 (h)(7)(ii) revised..........................................40185
80.415 (a)(2)(iii), (iv) and (b)(6) added; (a)(3) and (g)(4) 
        revised; (a)(4) and (5) removed............................40185
Appendices D through G removed......................................8738

                                  2003

40 CFR
                                                                   68 FR
                                                                    Page
Chapter I
73 Actions on petitions............................................51194
80 Meetings........................................................39018
80.2 (z) revised...................................................56780
80.46 (b), (f)(3)(i) and (h) revised...............................56781
    (a) and (h) revised............................................57819
80.101 (a), (k)(3)(i), (ii), (iii), (vi)(b)(2), (3), (viii) and 
        (6)(iv) revised; (l) added; eff. 7-7-03....................24307
80.330 (c)(1) revised..............................................57820
80.340 (b)(2)(ii) revised..........................................57820
80.350 (b)(2) revised..............................................57820
80.855 (c) added; eff. 7-7-03......................................24309

                                  2004

40 CFR
                                                                   69 FR
                                                                    Page
Chapter I
78 Authority citation revised......................................21644
78.1 (a)(1) amended; (b)(6) added..................................21644
78.2 Amended.......................................................21645
78.3 (b)(3)(i) and (c)(7) amended; (d)(2) and (3) redesignated as 
        (d)(3) and (4); new (d)(3) amended; (a)(3) and new (d)(2) 
        added......................................................21645
78.4 (a) amended...................................................21645

[[Page 1143]]

78.12 (a)(2) amended...............................................21645
80.2 (f) added; (j), (o), (x), (y) and (xx) revised; (nn) removed; 
        eff. 8-30-04...............................................39166
80.27 (a)(2) table correctly amended; CFR correction...............17932
80.230 (b) revised; eff. 8-30-04...................................39167
80.240 (f) added; eff. 8-30-04.....................................39167
80.500 Heading revised; (f) removed; eff. 8-30-04..................39168
80.501 Revised; eff. 8-30-04.......................................39168
80.502 Added; eff. 8-30-04.........................................39168
80.510 Added; eff. 8-30-04.........................................39168
80.511 Added; eff. 8-30-04.........................................39169
80.512 Added; eff. 8-30-04.........................................39170
80.513 Added; eff. 8-30-04.........................................39171
80.520 (b) revised; (d) removed; eff. 8-30-04......................39171
80.521 Revised; eff. 8-30-04.......................................39171
80.522 Revised; eff. 8-30-04.......................................39171
80.523 Removed; eff. 8-30-04.......................................39172
80.527 Revised; eff. 8-30-04.......................................39172
80.530 Revised; eff. 8-30-04.......................................39172
80.531 (a)(1), (2), (d)(1), (5), (e)(1) and (2)(i) revised; eff. 
        8-30-04....................................................39173
80.532 Revised; eff. 8-30-04.......................................39173
80.533 Added; eff. 8-30-04.........................................39174
80.535 Added; eff. 8-30-04.........................................39175
80.536 Added; eff. 8-30-04.........................................39176
80.540 (b), (d), (e) and (f) revised; eff. 8-30-04.................39177
80.550 Heading and (a) through (f) revised; eff. 8-30-04...........39177
80.551 Revised; eff. 8-30-04.......................................39178
80.552 Heading, (a), (b), (c) and (e) revised; eff. 8-30-04........39179
80.553 (d), (e), (f) and (k) revised; eff. 8-30-04.................39179
80.554 Added; eff. 8-30-04.........................................39179
80.555 Added; eff. 8-30-04.........................................39180
80.560 (a), (b), (d), (e), (h), (i), (k) and (l) revised; eff. 8-
        30-04......................................................39181
80.561 Introductory text, (c), (d) and (f) revised; eff. 8-30-04 
                                                                   39181
80.570 Revised; eff. 8-30-04.......................................39182
80.571 Added; eff. 8-30-04.........................................39182
80.572 Added; eff. 8-30-04.........................................39183
80.573 Added; eff. 8-30-04.........................................39183
80.574 Added; eff. 8-30-04.........................................39183
80.580 Revised; eff. 8-30-04.......................................39184
80.581 Added; eff. 8-30-04.........................................39184
80.582 Added; eff. 8-30-04.........................................39185
80.583 Added; eff. 8-30-04.........................................39186
80.584 Added; eff. 8-30-04.........................................39187
80.585 Added; eff. 8-30-04.........................................39187
80.586 Added; eff. 8-30-04.........................................39188
80.590 Revised; eff. 8-30-04.......................................39188
80.591 Revised; eff. 8-30-04.......................................39189
80.592 Heading, (a), (b) introductory text, (4), (7) introductory 
        text, (c), (d) and (e) revised; eff. 8-30-04...............39189
80.593 Heading, (a)(3) and (c)(2) revised; eff. 8-30-04............39190
80.594 Heading, (a)(3), (5), (b) introductory text, (2) and (c) 
        revised; (a)(6), (7), (8) and (e) added; eff. 8-30-04......39190
80.597 Revised; eff. 8-30-04.......................................39190
80.598 Added; eff. 8-30-04.........................................39191
80.599 Added; eff. 8-30-04.........................................39194
80.600 Undesignated center heading removed; section revised; eff. 
        8-30-04....................................................39196
80.601 Revised; eff. 8-30-04.......................................39198
80.602 Revised; eff. 8-30-04.......................................39199
80.603 Added; eff. 8-30-04.........................................39200
80.604 Added; eff. 8-30-04.........................................39200
80.606 Undesignated center heading and section added; eff. 8-30-04
                                                                   39201
80.607 Added; eff. 8-30-04.........................................39202
80.608 Added; eff. 8-30-04.........................................39203
80.610 Revised; eff. 8-30-04.......................................39203
80.611 Revised; eff. 8-30-04.......................................39204
80.612 (a) revised; eff. 8-30-04...................................39204
80.613 Heading, (a) and (d) revised; eff. 8-30-04..................39204
80.614 Revised; eff. 8-30-04.......................................39205
80.615 Added; eff. 8-30-04.........................................39208
80.620 Heading, (a), (b), (c), (d)(2), (3)(i)(D), (e)(1), 
        (f)(2)(ii) introductory text, (3)(ii), (g), (h) 
        introductory text, (2), (i)(1)(v), (vi), (5), (j), (k)(1), 
        (3) and (n) through (s) revised; eff. 8-30-04..............39208

                                  2005

40 CFR
                                                                   70 FR
                                                                    Page
Chapter I
72.2 Amended; eff. 7-1-06..........................................25333
    Amended; eff. 7-18-05..........................................28677
72.7 (c)(1)(ii) amended; eff. 7-1-06...............................25334
72.9 (b)(2), (c)(1)(i), (e)(1), (2) introductory text, (g)(6) and 
        (h)(2) amended; eff. 7-1-06................................25334
72.21 (b)(1) and (e)(2) amended; eff. 7-1-06.......................25334

[[Page 1144]]

72.24 (a)(5), (7) and (10) removed; eff. 7-1-06....................25334
72.40 (a)(1) amended; eff. 7-1-06..................................25334
72.72 (a)(1), (2) and (3) amended; eff. 7-1-06.....................25334
72.73 (b)(2) amended; eff. 7-1-06..................................25334
72.90 (a) amended; eff. 7-1-06.....................................25334
72.95 Introductory text and (a) amended; eff. 7-1-06...............25334
72.96 (b) amended; eff. 7-1-06.....................................25334
73.10 (a), (b)(1) and (2) amended; eff. 7-1-06.....................25335
73.27 (c)(3) and (5) amended; eff. 7-1-06..........................25335
73.30 (a) and (b) amended; eff. 7-1-06.............................25335
73.31 (a), (b) and (c)(1)(v) amended; eff. 7-1-06..................25335
73.32 Removed; eff. 7-1-06.........................................25335
73.33 (b) and (c) removed; eff. 7-1-06.............................25335
73.34 (a) and (b) revised; (c) introductory text amended; eff. 7-
        1-06.......................................................25335
73.35 (a) introductory text, (1), (2), (i), (ii), (b)(1), (2), 
        (c)(2) and (d) amended; (a)(2)(iii), (b)(3) and (e) 
        removed; (a)(3) added; (c)(1) revised; eff. 7-1-06.........25335
73.36 (a) and (b) amended; eff. 7-1-06.............................25336
73.37 Revised; eff. 7-1-06.........................................25336
73.38 (a) and (b) amended; eff. 7-1-06.............................25336
73.50 (a), (b)(1)(ii) and (2)(ii) amended; (b)(3) removed; eff. 7-
        1-06.......................................................25336
73.51 Removed; eff. 7-1-06.........................................25336
73.52 (a) introductory text amended; (a)(1), (2), (3) and (b) 
        revised; (a)(4) removed; (c) added; eff. 7-1-06............25336
73.70 (e), (f) and (i)(1) amended; eff. 7-1-06.....................25336
74.4 (c)(1) and (2) amended; eff. 7-1-06...........................25336
74.18 (d) amended; eff. 7-1-06.....................................25336
74.40 (a) and (b) amended; eff. 7-1-06.............................25336
74.42 Revised; eff. 7-1-06.........................................25336
74.43 (a), (b)(7) and (8) amended; eff. 7-1-06.....................25337
74.44 (c)(1)(ii), (2)(iii)(C), (D), (E) introductory text, (3) and 
        (F) amended; eff. 7-1-06...................................25337
74.46 (b)(2) removed; eff. 7-1-06..................................25337
74.47 (a)(3)(iv), (v), (6), (c), (d)(1)(ii)(C), (D), (2)(i), (B) 
        and (ii) amended; eff. 7-1-06..............................25337
74.49 (a) introductory text amended; eff. 7-1-06...................25337
74.50 (a)(2) introductory text, (i), (b) and (d) amended; eff. 7-
        1-06.......................................................25337
75.2 (d) added; eff. 7-18-05.......................................28678
75.6 Introductory text amended; (a)(38) through (41) redesignated 
        as (a)(39) through (42); new (a)(38), (43) and (44) added; 
        (b) through (e) revised; eff. 7-18-05......................28678
    (b) introductory text, (c), (d) introductory text and (e) 
introductory text revised..........................................51268
75.10 (d)(1) and (3) amended; eff. 7-18-05.........................28678
75.15 Added; eff. 7-18-05..........................................28678
75.20 (a)(5)(i), (c)(1) and (d)(2)(v) revised; (b) introductory 
        text amended; (c)(9) and (10) redesignated as (c)(10) and 
        (11); new (c)(9) added; eff. 7-18-05.......................28679
75.21 (a)(3) revised; eff. 7-18-05.................................28679
75.22 (a)(7) and (b)(5) added; eff. 7-18-05........................28679
75.24 (d) revised; eff. 7-18-05....................................28680
75.31 (a) amended; (b) introductory text, (1) and (2) revised; 
        eff. 7-18-05...............................................28680
75.32 (a) introductory text amended; eff. 7-18-05..................28680
75.33 Table 1 revised; eff. 7-18-05................................28680
75.38 Added; eff. 7-18-05..........................................28681
75.39 Added; eff. 7-18-05..........................................28681
75.53 (e)(1)(i)(E), (iv) introductory text and (x) revised; eff. 
        7-18-05....................................................28682
75.57 (i) and (j) added; eff. 7-18-05..............................28682
75.58 (b)(3) introductory text, (i) and (ii) revised; eff. 7-18-05
                                                                   28683
75.59 (a)(1) introductory text, (3) introductory text, (5) 
        introductory text, (ii) introductory text, (6) 
        introductory text, (9) introductory text, (vi) and (c) 
        introductory text revised; (a)(7)(vii), (viii) and (14) 
        added; eff. 7-18-05........................................28683
75.80--75.84 (Subpart I) Added; eff. 7-18-05.......................28684

[[Page 1145]]

75 Appendix A amended; eff. 7-18-05..................28690, 28691, 28692
    Appendix B amended; eff. 7-18-05...............................28693
    Appendix F amended; eff. 7-18-05...............................28695
    Appendix K added; eff. 7-18-05.................................28695
77.3 (a), (b), (c), (d) introductory text and (1) through (5) 
        amended; eff. 7-1-06.......................................25337
77.4 (b)(1), (c)(1)(ii)(A), (d)(1), (2), (3), (e)(iv), (g)(2)(ii), 
        (3)(ii), (iii) and (k)(2) amended; eff. 7-1-06.............25337
77.5 (b) and (c) amended; (d) removed; eff. 7-1-06.................25337
77.6 (a)(1), (b)(1)(i)(A), (3), (c) and (f) amended; eff. 7-1-06 
                                                                   25337
78 Heading revised; eff. 7-11-05...................................25338
78.1 (a)(1) amended; (b)(2)(i) revised; (b)(7), (8) and (9) added; 
        eff. 7-11-05...............................................25338
78.3 (b)(3)(i), (c)(7) and (d)(3) amended; (a)(4), (5), (6), 
        (d)(5), (6) and (7) added; eff. 7-11-05....................25338
78.4 (a) amended; eff. 7-11-05.....................................25339
78.5 (a) amended; eff. 7-11-05.....................................25339
78.12 (a) introductory text and (2) amended; eff. 7-11-05..........25339
78.13 (b) amended; eff. 7-11-05....................................25339
80.2 (c) Footnote 1 and (ee) revised; (ww) added...................74566
80.41 (p) revised..................................................74566
80.45 (c)(1)(iv)(C)(6), (D)(6) and (d)(1)(iv)(B) revised...........74566
80.49 (a) introductory text, (3) introductory text and (b) 
        introductory text revised; (a)(1) table amended............74567
80.50 (a)(2) revised...............................................74567
80.65 (d)(2)(iii), (vi)(C), (D), (E) and (g) removed; (e) heading 
        and (e)(1) revised; (e)(2)(ii)(B) amended..................74567
80.67 (h)(1)(iv) revised...........................................74568
80.68 (b)(2)(ii) amended; (c)(9)(i)(B), (ii)(B), (10)(ii), (11), 
        (12) and (13)(iii) revised; (c)(10)(iii), (iv), (v) and 
        Footnote 2 added...........................................74568
80.69 (a)(4) removed; (e)(2)(i)(A) and (v) introductory text 
        revised....................................................74569
80.70 (m) introductory text amended; (m)(1) and (2) revised........71705
80.74 (b)(2) and (f) removed; (b)(7)(ii) revised; (b)(8) and (9) 
        added......................................................74569
80.75 (a) introductory text, (2)(vii) and (viii)(D) revised; 
        (a)(2)(ix), (x) and (o) added..............................74569
80.76 (b) revised..................................................74570
80.77 (c), (f), (g)(3) and (i) revised; (j) removed................74570
80.78 (a)(1)(iii) and (3) removed; (a)(11) introductory text 
        revised; (a)(12) added.....................................74570
80.81 (c)(2), (5), (6), (10) and (g)(1)(vi) revised; (c)(4) and 
        (g)(1)(vii) removed........................................74570
    (a), (c) introductory text, (e)(2) introductory text, (3)(i), 
(g)(1) introductory text, (h)(1) introductory text, (ii)(A), (C) 
and (2)(i) revised.................................................75920
80.82 Revised......................................................74570
80.83 Revised......................................................74571
80.101 (g)(9) heading and (i) through (iv) revised; (i)(3) added 
                                                                   74572
80.104 (a)(2)(xiii), (xiv) and (xv) added..........................74573
80.105 (a)(5)(iv), (v), (vi)(D) and (c) revised; (a)(5)(vii), 
        (viii) and (7) added.......................................74573
80.106 (a)(1)(v) and (vi) revised; (a)(1)(vii) removed.............74573
80.125 (a)(1), (2) and (3) added...................................74573
80.126 (e) and (f) revised; (h) through (l) added..................74574
80.128 Heading, introductory text, (e)(2), (4) and (5) revised; 
        (e)(6) removed.............................................74574
80.129 Heading, introductory text, (a), (d)(3)(iii) and (iv) 
        revised; (d)(3)(v) removed.................................74574
80.131 Revised.....................................................74574
80.133 Added.......................................................74576
80.134 Added.......................................................74577
80.162 (a)(3)(i)(B) and (ii) revised...............................69245
80.211 Added.......................................................74578
80.215 (a)(2)(i) amended...........................................70509
80.410 (f)(4)(ii) and (r)(1)(iv) revised...........................74578
80.500 (b) and (c) revised.........................................70509
80.502 (b)(2) and (4) revised......................................70509
80.510 (h) introductory text revised...............................40895
80.525 (a) and (c) revised.........................................40895

[[Page 1146]]

80.531 (a)(2) amended; (c)(1), (2)(i) and (d)(1) revised; (d)(4) 
        removed....................................................40895
    (c)(2)(ii) removed.............................................70510
80.533 (e)(2) revised..............................................70510
80.550 (b)(3) revised..............................................40896
80.551 (f) revised.................................................40896
80.580 (c)(1) and (2)(i) revised...................................40896
    (d) revised....................................................70510
80.586 Heading revised.............................................40896
80.590 (a)(6)(i) revised...........................................40896
    (a)(6)(i) and (d) revised......................................70510
80.591 (b)(3) revised..............................................40896
80.592 (a)(2)(iii) revised.........................................70510
80.593 (a)(7)(i) revised...........................................70510
80.594 (b)(2) revised..............................................40896
80.595 (a) amended; (b) revised....................................40896
80.596 (a) amended.................................................40896
80.597 (c) revised; (d)(3) added...................................70510
80.598 (b)(9)(vi) revised..........................................70511
80.599 (a) introductory text and (1) revised; (b)(1), (2), (4), 
        (c)(1), (3), (d)(1), (2)(ii) and (e)(2) through (5) 
        amended....................................................40896
    (a) introductory text table, (1) table, (b)(4), (e)(2) and (3) 
revised............................................................70511
80.600 (a)(6), (b)(1) introductory text, (i) introductory text, 
        (ii) introductory text, (iii) introductory text, (iv) 
        introductory text, (v) introductory text and (2) revised; 
        (a)(13) added; (b)(3) amended..............................40898
    (b)(1)(i) introductory text, (C), (D), (3) and (i) through (l) 
revised; (m) added.................................................70511
80.601 (a)(2), (b) introductory text and (1) revised; (a)(4)(iii), 
        (iv), (v) and (b)(3)(ii) through (ix) redesignated as 
        (a)(4)(iv), (v), (vi) and (b)(3)(iii) through (x); new 
        (a)(4)(iii) and (b)(3)(ii) added...........................40898
    (a) introductory text, (1), (2), (4)(v), (b) introductory 
text, (d) introductory text, (1)(i) through (iv) and (3) revised; 
(d)(1)(v), (vi) and (vii) added....................................70512
80.602 (a)(2)(iii), (b) introductory text, (d) and (e) revised; 
        (f) added..................................................70513
80.604 (d)(5) removed..............................................40899
80.613 (a)(1) introductory text revised............................40899
80.855 (b)(1)(i) and (ii) revised; (b)(2) removed..................58335
80.1100 (Subpart K) Added..........................................77335

                                  2006

40 CFR
                                                                   71 FR
                                                                    Page
Chapter I
72.2 Amended.......................................................25377
72.7 (f)(2) revised; (f)(4)(i) amended.............................25377
72.8 (d)(4) revised; (d)(6)(i) introductory text amended...........25377
72.20 (b) amended..................................................25378
72.22 (b) amended..................................................25378
72.23 (a), (b) and (c)(1) amended..................................25378
72.24 (a)(1), (6) and (9)(ii) amended..............................25378
72.25 (b) amended..................................................25378
72.26 Added........................................................25378
73.31 (c)(1)(v) amended............................................25378
73.33 (d)(4), (e) and (f) amended; (g) added.......................25378
74.4 (c) removed...................................................25379
78.1 (b)(8)(ii) amended; (b)(10), (11) and (12) added..............25379
78.3 (b)(3)(i) and (d)(3) amended; (a)(7), (8), (9), (d)(8), (9) 
        and (10) added.............................................25379
80 Authority citation revised......................................31959
    Technical correction...........................................58498
80.2 (ii) revised............................................8982, 26698
    (z) revised....................................................16499
    (ccc) revised; (sss) added.....................................25716
    Regulation at 71 FR 8982 withdrawn.............................26420
80.9 Added.........................................................16499
80.41 (e) table and (f) table amended; (o)(4) added.................8972
    (e) table and (f) table amended; (o) removed; (q) heading, 
introductory text and (1) revised............................8982, 26698
    Regulation at 71 FR 8982 withdrawn.............................26420
80.46 (a)(1), (2), (3)(i), (ii), (iii), (4), (b), (f)(3)(i), 
        (g)(2)(i) and (h) revised; (a)(3)(iv) added................16499
80.65 Heading, (c)(1)(ii), (3), (d)(2)(vi) and (h) revised; 
        (c)(1)(iii), (2) and (d)(2)(v)(D) removed...................8982
    Regulation at 71 FR 8982 withdrawn.............................26420

[[Page 1147]]

    (d)(2)(vi) stay lifted; heading, (c)(1)(ii), (3), (d)(2)(vi), 
(3) and (h) revised; (c)(1)(iii), (2) and (d)(2)(v)(D) removed.....26698
80.67 (a)(1), (2)(i)(A), (g) introductory text, (3) introductory 
        text, (5) introductory text, (6) introductory text, (h)(1) 
        introductory text, (iv), (v) and (3)(ii) revised; (b)(3), 
        (f), (g)(5)(i), (6)(i), (h)(1)(vi), (vii) and (viii) 
        removed.....................................................8982
    Regulation at 71 FR 8982 withdrawn.............................26420
    (a)(1), (2)(i)(A), (g) introductory text, (3), (5) 
introductory text, (6) introductory text, (h)(1) introductory 
text, (iv), (v) and (3)(ii) revised; (b)(3), (f), (g)(5)(i), 
(6)(i), (h)(1)(vi), (vii) and(viii) removed; (g)(7) added..........26699
80.68 (a) introductory text, (3), (b) introductory text, (4)(i), 
        (ii), (c)(3), (4)(i) and (13)(v)(L) revised; (c)(12) 
        removed..............................................8983, 26699
    Regulation at 71 FR 8983 withdrawn.............................26420
80.69 (a)(6)(ii), (iii), (10) introductory text, (b), (d) and (e) 
        revised; (a)(6)(iv), (8), (9) and (c) removed........8983, 26700
    Regulation at 71 FR 8983 withdrawn.............................26420
    (a)(11) added; eff. 8-1-06.....................................31959
80.70 (k)(2) added.................................................77620
80.73 Introductory text revised..............................8984, 26700
    Regulation at 71 FR 8984 withdrawn.............................26420
80.74 (c) heading, introductory text, (2) and (d) introductory 
        text revised................................................8984
    Regulation at 71 FR 8984 withdrawn.............................26420
    (c) introductory text, (2) and (d) introductory text revised 
                                                                   26700
    (b)(10) added; eff. 8-1-06.....................................31961
80.75 Introductory text, (a) introductory text, (h), (i), (l), (m) 
        and (n)(2) revised; (a)(2)(vii) and (f) removed......8984, 26700
    Regulation at 71 FR 8984 withdrawn.............................26420
    (a)(2) correctly reinstated; CFR correction....................67065
    (a)(2)(ix) and (x) reinstated; CFR correction..................77266
80.76 (a) revised............................................8984, 26701
    Regulation at 71 FR 8984 withdrawn.............................26420
80.77 (g)(2)(ii) removed; (i)(1) revised............................8984
    Regulation at 71 FR 8984 withdrawn.............................26420
    (g)(2)(ii) removed; (i)(2) revised.............................26701
    (g)(2)(iv)(B) and (3) revised; (g)(4) added; eff. 8-1-06.......31961
80.78 (a)(1)(ii)(C), (8)(1) through (iv) and (11)(iv)(D) added......8972
    (a)(1)(ii) removed; (a)(8) and (11)(iv) revised;................8985
    Regulation at 71 FR 8985 withdrawn in part.....................26420
    (a)(1)(ii) removed; (a)(11)(iv) revised........................26701
80.79 (a)(5) added; (c)(1) amended..................................8973
    (a)(5) amended; (c)(1) revised..................................8985
    (a)(5) and (c)(1) correctly revised; regulation at 71 FR 8985 
withdrawn in part..................................................26420
    (c)(1) revised.................................................26701
    (a)(5) correctly revised.......................................27533
80.81 (d), (e)(3) and (h)(1) introductory text revised; (e)(2) 
        removed.....................................................8973
    (b)(1) and (2) revised...................................8985, 26701
    Regulation at 71 FR 8985 withdrawn.............................26420
80.84 Added; eff. 8-1-06...........................................31961
80.104 Introductory text, (a) introductory text and (b) revised; 
        (c) added; eff. 8-1-06.....................................31963
80.125 (a), (c) and (d) introductory text revised............8985, 26701
    Regulation at 71 FR 8985 withdrawn.............................26420
80.126 (b) revised...........................................8985, 26701
    Regulation at 71 FR 8985 withdrawn.............................26420
80.128 (e)(2) revised........................................8986, 26702
    Regulation at 71 FR 8986 withdrawn.............................26420
80.129 Removed...............................................8986, 26702
    Regulation at 71 FR 8986 withdrawn.............................26420
    (a), (d)(3)(iii), (iv) and (v) stay lifted.....................26698
80.130 (a) revised...........................................8986, 26702

[[Page 1148]]

    Regulation at 71 FR 8986 withdrawn.............................26420
80.133 (h)(1) and (4) revised................................8986, 26702
    Regulation at 71 FR 8986 withdrawn.............................26420
80.134 Removed...............................................8986, 26702
    Regulation at 71 FR 8986 withdrawn.............................26420
80.213 Added; eff. 8-1-06..........................................31963
80.285 (b)(1)(ii) revised..........................................54912
80.310 (a) and (b) revised.........................................54912
80.365 (b)(8) added; eff. 8-1-06...................................31964
80.382 Added.......................................................78093
80.415 (a)(2)(iii) revised.........................................54912
80.500--80.620 (Subpart I) Heading revised.........................25716
80.502 (b)(1)(iii), (d)(1), (2) and (f) added......................25716
80.520 (b)(2) introductory text revised............................25717
80.527 (c) introductory text, (3), (4) and (e)(2) revised..........25717
80.531 (a)(5)(i), (ii) and (d)(2) revised; (a)(5)(v) and (c)(5) 
        added......................................................25717
80.532 (d)(1)(i) revised...........................................25717
80.533 Heading, (d)(2), (e)(1), (f), (g) and (h) revised; 
        (c)(2)(iii), (e) introductory text and (i) added...........25717
80.535 (a)(1)(i) and (c)(1)(i) revised.............................25718
80.551 (f) added...................................................25718
80.553 (b) and (d) revised.........................................25718
80.554 (d)(1)(i), (ii) and (3)(i) revised..........................25718
80.570 (e) revised.................................................25718
80.571 (f) revised.................................................25718
80.572 (f) revised.................................................25718
80.573 (c) revised.................................................25718
80.574 (d) revised.................................................25719
80.580 (b)(1) and (c)(1) removed; (c)(2)(i) and (e)(1)(v) revised 
                                                                   16500
    (d) revised....................................................25719
80.581 (c)(1) revised..............................................25719
80.590 (a)(7) introductory text and (i) revised; (i) added.........25719
80.591 (b)(3), (4)(i), (ii) and (iii) revised......................25719
80.592 (f) added...................................................25719
80.595 Heading revised.............................................25720
80.597 (c)(1) introductory text and (2) introductory text revised; 
        (c)(1)(iv) and (5) added...................................25720
80.598 (a)(3)(iv) and (vi) revised; (a)(2)(v)(C), (b)(2)(iii), 
        (iv), (3)(iv), (v), (4)(iv) and (9)(xvi) added.............25720
80.599 (b)(2), (e)(2), (4) and (5) revised; (h) added..............25720
80.600 (a)(1)(v), (vi), (3)(ii), (iii), (4)(i), (ii), 
        (b)(1)(i)(D), (ii)(G), (H), (iii)(B), (C), (iv)(A), (B), 
        (v)(A), (B), (vi)(A), (B), (vii)(B), (C), (viii)(A) and 
        (B) revised; (a)(1)(vii), (viii), (ix), (3)(iv), (4)(iii), 
        (b)(1)(i)(E) through (H), (ii)(I) through (L), (iii)(D), 
        (iv)(C), (v)(C), (vi)(C), (vii)(D), (viii)(C), (n) and (o) 
        added......................................................25721
80.601 (a) introductory text, (1)(i), (2)(i), (4)(v), (vi) and (b) 
        introductory text revised; (b)(4) and (f) added............25722
80.602 (g) added...................................................25723
80.614 Heading, introductory text, (a), (b), (c), (e), (f)(1) 
        introductory text, (i) through (vi), (vii) introductory 
        text, (D), (viii), (2) introductory text, (i), (iii), 
        (iv), (vi), (vii), (5), (6)(i) through (iv), (7) 
        introductory text, (i), (ii) and (iii) revised.............25723
80.616 Added.......................................................25725
80.617 Added.......................................................25726
80.840 Added; eff. 8-1-06..........................................31964

                                  2007

40 CFR
                                                                   72 FR
                                                                    Page
Chapter I
72 Actions on petitions............................................35354
72 Authority citation revised......................................59205
72.2 Amended.......................................................51527
72.24 (a)(9) introductory text amended.............................59205
73 Actions on petitions............................................35354
74 Actions on petitions............................................35354
75.15 (f) and (j) revised; (k) added...............................51527
75.20 (d)(2)(ix) added.............................................51527
75.57 (j)(7) revised...............................................51528
75.81 (a)(1) revised...............................................51528
75.84 (f)(1)(ii)(J) revised........................................51528
75 Appendices A, B and K amended...................................51528
75 Appendix K corrected............................................55279
78 Actions on petitions............................................35354
78 Authority citation revised......................................59205

[[Page 1149]]

78.1 (a)(1) revised................................................59205
80 Authority citation revised.......................................8542
80.41 (e) and (f) redesignated as (e)(1) and (f)(1); (e)(2), (3), 
        (f)(2) and (3) added........................................8543
80.65 (f)(2)(iv) and (v) amended....................................2427
80.68 (a), (b) and (c) redesignated as (b), (c) and (d); new (a) 
        added; new (b)(2), (c) introductory text, (2)(i), (ii), 
        (3), (4)(i), (d)(1)(ii)(A), (B), (2)(i), (8)(i)(C), 
        (9)(ii)(B), (10)(v), (11)(ii) and (13)(v)(G) amended........8543
80.70 Regulation at 71 FR 77620 withdrawn..........................14681
    (k)(2) added...................................................20242
80.91 (e)(2)(ii)(A) revised........................................60579
80.93 (d) revised..................................................60579
80.101 (c)(3) and (4) added.........................................8543
80.101 (f)(2), (4)(iii), (g)(1)(ii)(B), (2) introductory text, (i) 
        and (6) revised; (f)(3) and (g)(1)(ii)(C) added............60580
80.104 (a)(2)(xiii) added..........................................60581
80.125 (e) amended..................................................2427
80.128 (a) revised..................................................8543
80.815 (d)(1) redesignated as (d)(1)(i); (d)(1)(ii) added...........8544
80.825 (c)(2) revised..............................................60581
80.850 (c) revised; (d) added......................................60581
80.855 (b)(2) added................................................60582
80.910 (a) revised.................................................60582
80.915 (e) through (h) redesignated as (f) through (i); new (e) 
        added......................................................60582
80.1035 (h) added...................................................8544
80.1100 Revised; eff. 9-1-07.......................................23991
80.1101 Added; eff. 9-1-07.........................................23992
80.1104 Added; eff. 9-1-07.........................................23993
80.1105 Added; eff. 9-1-07.........................................23993
80.1106 Added; eff. 9-1-07.........................................23993
80.1107 Added; eff. 9-1-07.........................................23993
80.1115 Added; eff. 9-1-07.........................................23995
80.1125 Added; eff. 9-1-07.........................................23995
80.1126 Added; eff. 9-1-07.........................................23995
80.1127 Added; eff. 9-1-07.........................................23995
80.1128 Added; eff. 9-1-07.........................................23995
80.1129 Added; eff. 9-1-07.........................................23995
80.1130 Added; eff. 9-1-07.........................................23995
80.1131 Added; eff. 9-1-07.........................................23995
80.1132 Added; eff. 9-1-07.........................................23995
80.1141 Added; eff. 9-1-07.........................................23999
80.1142 Added; eff. 9-1-07.........................................23999
80.1143 Added; eff. 9-1-07.........................................23999
80.1150 Added; eff. 9-1-07.........................................24000
80.1151 Added; eff. 9-1-07.........................................24000
80.1152 Added; eff. 9-1-07.........................................24000
80.1153 Added; eff. 9-1-07.........................................24000
80.1154 Added; eff. 9-1-07.........................................24000
80.1155 Added; eff. 9-1-07.........................................24000
80.1160 Added; eff. 9-1-07.........................................24003
80.1161 Added; eff. 9-1-07.........................................24003
80.1163 Added; eff. 9-1-07.........................................24004
80.1164 Added; eff. 9-1-07.........................................24004
80.1165 Added; eff. 9-1-07.........................................24004
80.1166 Added; eff. 9-1-07.........................................24004
80.1167 Added; eff. 9-1-07.........................................24004
80.1200--80.1363 (Subpart L) Added..................................8544

                                  2008

   (Regulations published from January 1, 2008, through July 1, 2008)

40 CFR
                                                                   73 FR
                                                                    Page
Chapter I
72.2 Amended........................................................4340
75.4 (d) revised....................................................4340
75.6 (a)(1) through (4), (6) through (15), (17), (19), (21) 
        through (29), (31) through (42), (b)(1) through (4), (6), 
        (d)(1) and (2) amended; (a)(5), (16), (18), (20) and (30) 
        removed; (a)(45) through (49) and (f)(4) added; (f)(1) and 
        (3) revised.................................................4341
75.11 Heading, (d)(3), (e) introductory text, (1), (3) 
        introductory text and (f) revised; (b)(1) amended; (e)(2) 
        removed; (e)(4) added.......................................4342
75.12 Heading and (e)(3) revised; (b) amended.......................4342
75.13 (d)(3) revised................................................4343
75.14 (e) added.....................................................4343
75.15 Introductory text amended; (h) revised; (l) added.............4343
75.16 (b)(1)(ii) revised; (e)(1) and (3) amended....................4343
75.17 (d)(2) revised................................................4343
75.19 (a)(1), (c)(1)(i), (iv)(A)(3), (3)(ii)(B)(2), (H) and 
        (4)(ii) heading revised; (c)(1)(iv)(A), (G) and (4)(i)(A) 
        amended; (c)(1)(iv)(I)(3) through (6) and (4)(ii)(D) added
                                                                    4344
75.20 (b) introductory text amended; (c)(1)(v) revised; (f)(1) and 
        (2) removed.................................................4345
75.21 (a)(4) amended................................................4345

[[Page 1150]]

75.22 (a) introductory text, (5), (6), (7), (b) introductory text, 
        (5) and (c)(1) introductory text revised; (b)(3) amended; 
        (b)(6), (7) and (8) added...................................4345
75.31 (c)(3) amended................................................4346
75.32 (b) revised...................................................4346
75.33 Heading, (c)(8)(iii), (iv) Tables 1 and 2 and (e)(3) Table 
        (3) revised; (b)(1) introductory text, (2) introductory 
        text, (3), (4), (c)(1) introductory text, (2) introductory 
        text, (3), (4), (d)(1) introductory text, (2) introductory 
        text, (3) introductory text and (4) introductory text 
        amended.....................................................4346
75.34 (a) introductory text and (3) revised; (a)(2)(ii) and (d) 
        amended; (a)(5) added.......................................4348
75.38 (a) and (c) revised...........................................4349
75.39 (a) through (d) revised; (f) added............................4349
75.53 (a)(1) revised; (a)(2) amended; (e)(1)(xiv), (g) and (h) 
        added.......................................................4350
75.57 (b)(3), (i)(1)(iv), (2) and (j)(2) amended; (c)(4)(iv) Table 
        4a revised..................................................4353
75.58 (b)(3) introductory text and (f)(1)(iii) revised; 
        (b)(3)(iii) and (iv) amended; (c)(1)(xii), (xiii), (4)(x), 
        (5)(ii), (d)(1)(ix), (x), (2)(ix), (x), (f)(1)(xi), (xii) 
        and (2)(x) amended; (c)(1)(xiv), (4)(xi), (d)(1)(xi), 
        (2)(xi), (f)(1)(xiii) and (xiv) added.......................4354
75.59 (a)(1)(i), (xi), (2)(i), (3)(i), (ii), (4)(i), (vi)(L), (M), 
        (vii)(K), (L), (6)(i), (ix), (13), (b)(1)(ii), (2)(i), 
        (4)(i)(A), (H), (I), (ii)(L), (M), (5)(i)(B), (H), 
        (ii)(B), (iii)(B), (iv)(A), (G), (H), (d)(1)(xi), (xii), 
        (2)(iii), (iv) and (v) amended; (a)(1)(viii), (6) 
        introductory text, (7)(viii) heading, (8), (b)(4)(ii)(A), 
        (B) and (F) revised; (a)(4)(vi)(N), (vii)(M), (7)(ix), 
        (x), (b)(4)(i)(J), (ii)(N), (5)(iv)(I), (d)(i)(xiii), 
        (2)(vi), (vii), (e) and (f) added; (a)(12)(iii) removed.....4354
75.60 (b)(8) added..................................................4356
75.61 (a)(1) introductory text and (5) introductory text amended; 
        (a)(3) revised; (a)(7) and (8) added........................4356
75.62 (a)(1) revised; (a)(2) amended................................4357
75.63 (a)(1)(i)(A), (ii)(B) and (2)(i) amended; (a)(1)(ii)(A), 
        (2)(iii) and (b)(2)(iv) revised; (b)(2)(iii) removed........4357
75.64 (a)(8) removed; (a)(2)(xiv) and (3) through (7), (9), (10) 
        and (11) redesignated as (a)(2)(xiii) and new (8) through 
        (15); (a) introductory text and new (2)(xiii) revised; new 
        (a)(3) through (7) added; new (a)(14) amended...............4357
75.66 (f) removed...................................................4358
75.71 Heading and (e) revised; (a)(1) and (2) amended...............4358
75.72 Heading, introductory text and (c)(3) revised; (f) removed 
                                                                    4358
75.73 (c)(3), (f)(1) introductory text and (ii)(K) revised; 
        (e)(1), (2) and (f)(1)(ii) introductory text amended........4359
75.74 (c)(2) introductory text, (i) introductory text, (C), (ii) 
        introductory text, (E), (3)(xi), (xii)(A), (B) and (6)(v) 
        amended; (c)(2)(i)(D), (ii)(F), (3)(ii), (6)(iii), 
        (7)(iii)(L), (8)(ii) and (11) revised; (c)(2)(ii)(G), (H), 
        (3)(vi), (vii) and (viii) removed...........................4360
75.80 (f)(1)(iii) amended...........................................4361
75.81 (a)(3) and (d)(1) amended; (a)(4), (c)(1), (2), (d)(2), (5) 
        and (e)(1) revised; (d)(4)(iv) added........................4361
75.82 (b)(3), (c)(4) and (d)(3) added; (c)(2), (3), (d)(1) and (2) 
        amended.....................................................4362
75.84 (c)(3), (e)(1), (2), (f)(1)(i) and (ii) introductory text 
        amended; (f)(1) introductory text and (ii)(I) revised.......4363
75 Appendix A amended...............................................4363
    Appendix B amended..............................................4367
    Appendix D amended..............................................4369
    Appendices E and F amended......................................4372
    Appendices G and K amended......................................4376
    Appendix F corrected............................................8408
79 Policy statement................................................22277

[[Page 1151]]

79.68 (f)(5)(vii) correctly reinstated.............................34875
80.27 (a)(2)(ii) table amended......................................8209
80.1275 (d)(2) redesignated as (d)(3); (d)(1)(v) and new (2) added
                                                                   13136
    Regulation at 73 FR 13136 withdrawn............................26325


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