[Title 40 CFR ]
[Code of Federal Regulations (annual edition) - July 1, 2009 Edition]
[From the U.S. Government Printing Office]



[[Page i]]


          40


          Parts 72 to 80

                         Revised as of July 1, 2009


          Protection of Environment




________________________

          Containing a codification of documents of general 
          applicability and future effect

          As of July 1, 2009
          With Ancillaries
                    Published by
                    Office of the Federal Register
                    National Archives and Records
                    Administration
                    A Special Edition of the Federal Register

[[Page ii]]

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                            Table of Contents



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

  Title 40:
          Chapter I--Environmental Protection Agency 
          (Continued)                                                3
  Finding Aids:
      Table of CFR Titles and Chapters........................    1101
      Alphabetical List of Agencies Appearing in the CFR......    1121
      List of CFR Sections Affected...........................    1131

[[Page iv]]





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

                     Cite this Code: CFR
                     To cite the regulations in 
                       this volume use title, 
                       part and section number. 
                       Thus, 40 CFR 72.1 refers 
                       to title 40, part 72, 
                       section 1.

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

[[Page v]]



                               EXPLANATION

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

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

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

LEGAL STATUS

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

HOW TO USE THE CODE OF FEDERAL REGULATIONS

    The Code of Federal Regulations is kept up to date by the individual 
issues of the Federal Register. These two publications must be used 
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    To determine whether a Code volume has been amended since its 
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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 
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inserted following the text.

OMB CONTROL NUMBERS

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

[[Page vi]]

Many agencies have begun publishing numerous OMB control numbers as 
amendments to existing regulations in the CFR. These OMB numbers are 
placed as close as possible to the applicable recordkeeping or reporting 
requirements.

OBSOLETE PROVISIONS

    Provisions that become obsolete before the revision date stated on 
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INCORPORATION BY REFERENCE

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This material, like any other properly issued regulation, has the force 
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    What is a proper incorporation by reference? The Director of the 
Federal Register will approve an incorporation by reference only when 
the requirements of 1 CFR part 51 are met. Some of the elements on which 
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    (a) The incorporation will substantially reduce the volume of 
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    (b) The matter incorporated is in fact available to the extent 
necessary to afford fairness and uniformity in the administrative 
process.
    (c) The incorporating document is drafted and submitted for 
publication in accordance with 1 CFR part 51.
    What if the material incorporated by reference cannot be found? If 
you have any problem locating or obtaining a copy of material listed as 
an approved incorporation by reference, please contact the agency that 
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Records Administration, Washington DC 20408, or call 202-741-6010.

CFR INDEXES AND TABULAR GUIDES

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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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    Raymond A. Mosley,
    Director,
    Office of the Federal Register.
    July 1, 2009.







[[Page ix]]



                               THIS TITLE

    Title 40--Protection of Environment is composed of thirty-two 
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 
of part 52), parts 53-59, part 60 (60.1-end of part 60, sections), part 
60 (Appendices), parts 61-62, part 63 (63.1-63.599), part 63 (63.600-
63.1199), part 63 (63.1200-63.1439), part 63 (63.1440-63.6175), part 63 
(63.6580-63.8830), part 63 (63.8980-end of part 63) parts 64-71, parts 
72-80, parts 81-84, part 85-Sec.  86.599-99, part 86 (86.600-1-end of 
part 86), 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, parts 790-999, and part 1000 to end. 
The contents of these volumes represent all current regulations codified 
under this title of the CFR as of July 1, 2009.

    Chapter I--Environmental Protection Agency appears in all thirty-two 
volumes. Regulations issued by the Council on Environmental Quality, 
including an Index to Parts 1500 through 1508, appear in the volume 
containing part 1000 to end. The OMB control numbers for title 40 appear 
in Sec.  9.1 of this chapter.

    For this volume, Susannah C. Hurley was Chief Editor. The Code of 
Federal Regulations publication program is under the direction of 
Michael L. White, assisted by Ann Worley.


[[Page 1]]



                   TITLE 40--PROTECTION OF ENVIRONMENT




                   (This book contains parts 72 to 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. 72.7 or Sec. 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, Sec. 72.42, Sec. 72.43, or Sec. 72.44 of 
this part, under Sec. 74.47 of this chapter, or a NOX 
averaging plan under Sec. 76.11 of this chapter, that includes units at 
more than one affected source shall be complete only if:
    (i) Such plan is signed and certified by the designated 
representative for each source with an affected unit governed by such 
plan; and
    (ii) A complete permit application is submitted covering each unit 
governed by such plan.
    (2) A permitting authority's approval of a plan under paragraph 
(b)(1) of this section that includes units in more than one State shall 
be final only after every permitting authority with jurisdiction over 
any such unit has approved the plan with the same modifications or 
conditions, if any.
    (c) Conditional Approval. In the compliance plan, the designated 
representative of an affected unit may propose, in accordance with this 
subpart, any Acid Rain compliance option for conditional approval, 
except a Phase I extension plan; provided that an Acid Rain compliance 
option under section 407 of

[[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. 76.5, Sec. 76.6, Sec. 76.7, 
Sec. 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. 76.5, Sec. 76.6, 
Sec. 76.7, Sec. 76.8, or Sec. 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:

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[GRAPHIC] [TIFF OMITTED] TC01SE92.082

where:

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

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


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



Sec. Sec. 73.22-73.24  [Reserved]



Sec. 73.25  Phase I extension reserve.

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

[58 FR 3687, Jan. 11, 1993]



Sec. 73.26  Conservation and renewable energy reserve.

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

[53 FR 15714, Mar. 23, 1993]



Sec. 73.27  Special allowance reserve.

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

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

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

[[Page 154]]

[GRAPHIC] [TIFF OMITTED] TR28SE98.052

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

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

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

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

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

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

[[Page 155]]

[GRAPHIC] [TIFF OMITTED] TR28SE98.056

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

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

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

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



                   Subpart C_Allowance Tracking System

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



Sec. 73.30  Allowance tracking system accounts.

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

[[Page 156]]

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

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



Sec. 73.31  Establishment of accounts.

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

[[Page 157]]

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

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



Sec. 73.32  [Reserved]



Sec. 73.33  Authorized account representative.

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

[[Page 158]]

the authorized account representative or alternate authorized account 
representative, as appropriate, must submit to the Administrator a 
notice of delegation, in a format prescribed by the Administrator, that 
includes the following elements:
    (i) The name, address, e-mail address, telephone number, and 
facsimile transmission number (if any) of such authorized account 
representative or alternate authorized account representative;
    (ii) The name, address, e-mail address, telephone number, and, 
facsimile transmission number (if any) of each such natural person 
(referred to as an ``agent'');
    (iii) For each such natural person, a list of the type or types of 
electronic submissions under paragraph (g)(1) or (2) of this section for 
which authority is delegated to him or her;
    (iv) The following certification statements by such authorized 
account representative or alternate authorized account representative:
    (A) ``I agree that any electronic submission to the Administrator 
that is by an agent identified in this notice of delegation and of a 
type listed for such agent in this notice of delegation and that is made 
when I am a authorized account representative or alternate authorized 
representative, as appropriate, and before this notice of delegation is 
superseded by another notice of delegation under 40 CFR 73.33(g)(4) 
shall be deemed to be an electronic submission by me.''
    (B) ``Until this notice of delegation is superseded by another 
notice of delegation under 40 CFR 73.33(g)(4), I agree to maintain an e-
mail account and to notify the Administrator immediately of any change 
in my e-mail address unless all delegation of authority by me under 40 
CFR 73.33(g) is eliminated.''
    (4) A notice of delegation submitted under paragraph (g)(3) of this 
section shall be effective, with regard to the authorized account 
representative or alternate authorized account representative identified 
in such notice, upon receipt of such notice by the Administrator and 
until receipt by the Administrator of a superseding notice of delegation 
submitted by such authorized account representative or alternate 
authorized account representative, as appropriate. The superseding 
notice of delegation may replace any previously identified agent, add a 
new agent, or eliminate entirely any delegation of authority.
    (5) Any electronic submission covered by the certification in 
paragraph (g)(3)(iv)(A) of this section and made in accordance with a 
notice of delegation effective under paragraph (g)(4) of this section 
shall be deemed to be an electronic submission by the designated 
representative or alternate designated representative submitting such 
notice of delegation.

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



Sec. 73.34  Recordation in accounts.

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

[[Page 159]]

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

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



Sec. 73.35  Compliance.

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

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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

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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 and system bias checks 
of the method. Dynamic spiking may be conducted

[[Page 263]]

(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;
    (3) Method 7E for determining total NOX concentration 
(both NO and NO2);

[[Page 264]]

    (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 by a certified monitor or 
monitoring

[[Page 265]]

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 commo