[Title 40 CFR ]
[Code of Federal Regulations (annual edition) - July 1, 2000 Edition]
[From the U.S. Government Printing Office]



[[Page i]]

          

                    40


          Parts 72 to 80

                         Revised as of July 1, 2000

Protection of Environment





          Containing a Codification of documents of general 
          applicability and future effect
          As of July 1, 2000
          With Ancillaries
          Published by
          the Office of the Federal Register
          National Archives and Records
          Administration

As a Special Edition of the Federal Register



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                     U.S. GOVERNMENT PRINTING OFFICE
                            WASHINGTON : 2000



               For sale by U.S. Government Printing Office
 Superintendent of Documents, Mail Stop: SSOP, Washington, DC 20402-9328



[[Page iii]]




                            Table of Contents



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

  Title 40:
          Chapter I--Environmental Protection Agency                 3
  Finding Aids:
      Material Approved for Incorporation by Reference........     859
      Table of CFR Titles and Chapters........................     865
      Alphabetical List of Agencies Appearing in the CFR......     883
      List of CFR Sections Affected...........................     893



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

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

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

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                               EXPLANATION

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

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

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

LEGAL STATUS

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

HOW TO USE THE CODE OF FEDERAL REGULATIONS

    The Code of Federal Regulations is kept up to date by the individual 
issues of the Federal Register. These two publications must be used 
together to determine the latest version of any given rule.
    To determine whether a Code volume has been amended since its 
revision date (in this case, July 1, 2000), consult the ``List of CFR 
Sections Affected (LSA),'' which is issued monthly, and the ``Cumulative 
List of Parts Affected,'' which appears in the Reader Aids section of 
the daily Federal Register. These two lists will identify the Federal 
Register page number of the latest amendment of any given rule.

EFFECTIVE AND EXPIRATION DATES

    Each volume of the Code contains amendments published in the Federal 
Register since the last revision of that volume of the Code. Source 
citations for the regulations are referred to by volume number and page 
number of the Federal Register and date of publication. Publication 
dates and effective dates are usually not the same and care must be 
exercised by the user in determining the actual effective date. In 
instances where the effective date is beyond the cut-off date for the 
Code a note has been inserted to reflect the future effective date. In 
those instances where a regulation published in the Federal Register 
states a date certain for expiration, an appropriate note will be 
inserted following the text.

OMB CONTROL NUMBERS

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

[[Page vi]]

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

OBSOLETE PROVISIONS

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

INCORPORATION BY REFERENCE

    What is incorporation by reference? Incorporation by reference was 
established by statute and allows Federal agencies to meet the 
requirement to publish regulations in the Federal Register by referring 
to materials already published elsewhere. For an incorporation to be 
valid, the Director of the Federal Register must approve it. The legal 
effect of incorporation by reference is that the material is treated as 
if it were published in full in the Federal Register (5 U.S.C. 552(a)). 
This material, like any other properly issued regulation, has the force 
of law.
    What is a proper incorporation by reference? The Director of the 
Federal Register will approve an incorporation by reference only when 
the requirements of 1 CFR part 51 are met. Some of the elements on which 
approval is based are:
    (a) The incorporation will substantially reduce the volume of 
material published in the Federal Register.
    (b) The matter incorporated is in fact available to the extent 
necessary to afford fairness and uniformity in the administrative 
process.
    (c) The incorporating document is drafted and submitted for 
publication in accordance with 1 CFR part 51.
    Properly approved incorporations by reference in this volume are 
listed in the Finding Aids at the end of this volume.
    What if the material incorporated by reference cannot be found? If 
you have any problem locating or obtaining a copy of material listed in 
the Finding Aids of this volume as an approved incorporation by 
reference, please contact the agency that issued the regulation 
containing that incorporation. If, after contacting the agency, you find 
the material is not available, please notify the Director of the Federal 
Register, National Archives and Records Administration, Washington DC 
20408, or call (202) 523-4534.

CFR INDEXES AND TABULAR GUIDES

    A subject index to the Code of Federal Regulations is contained in a 
separate volume, revised annually as of January 1, entitled CFR Index 
and Finding Aids. This volume contains the Parallel Table of Statutory 
Authorities and Agency Rules (Table I). A list of CFR titles, chapters, 
and parts and an alphabetical list of agencies publishing in the CFR are 
also included in this volume.
    An index to the text of ``Title 3--The President'' is carried within 
that volume.
    The Federal Register Index is issued monthly in cumulative form. 
This index is based on a consolidation of the ``Contents'' entries in 
the daily Federal Register.
    A List of CFR Sections Affected (LSA) is published monthly, keyed to 
the revision dates of the 50 CFR titles.

[[Page vii]]


REPUBLICATION OF MATERIAL

    There are no restrictions on the republication of material appearing 
in the Code of Federal Regulations.

INQUIRIES

    For a legal interpretation or explanation of any regulation in this 
volume, contact the issuing agency. The issuing agency's name appears at 
the top of odd-numbered pages.
    For inquiries concerning CFR reference assistance, call 202-523-5227 
or write to the Director, Office of the Federal Register, National 
Archives and Records Administration, Washington, DC 20408 or e-mail 
info@fedreg.nara.gov.

SALES

    The Government Printing Office (GPO) processes all sales and 
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ELECTRONIC SERVICES

    The full text of the Code of Federal Regulations, The United States 
Government Manual, the Federal Register, Public Laws, Public Papers, 
Weekly Compilation of Presidential Documents and the Privacy Act 
Compilation are available in electronic format at www.access.gpo.gov/
nara (``GPO Access''). For more information, contact Electronic 
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Phone 202-512-1530, or 888-293-6498 (toll-free). E-mail, 
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    The Office of the Federal Register also offers a free service on the 
National Archives and Records Administration's (NARA) World Wide Web 
site for public law numbers, Federal Register finding aids, and related 
information. Connect to NARA's web site at www.nara.gov/fedreg. The NARA 
site also contains links to GPO Access.

                              Raymond A. Mosley,
                                    Director,
                          Office of the Federal Register.

July 1, 2000.



[[Page ix]]



                               THIS TITLE

    Title 40--Protection of Environment is composed of twenty-four 
volumes. The parts in these volumes are arranged in the following order: 
parts 1-49, parts 50-51, part 52 (52.01-52.1018), part 52 (52.1019-End), 
parts 53-59, part 60, parts 61-62, part 63 (63.1-63.1199), part 63 
(63.1200-End), parts 64-71, parts 72-80, parts 81-85, part 86, parts 87-
135, parts 136-149, parts 150-189, parts 190-259, parts 260-265, parts 
266-299, parts 300-399, parts 400-424, parts 425-699, parts 700-789, and 
part 790 to End. The contents of these volumes represent all current 
regulations codified under this title of the CFR as of July 1, 2000.

    Chapter I--Environmental Protection Agency appears in all twenty-
four volumes. A Pesticide Tolerance Commodity/Chemical Index and Crop 
Grouping Commodities Index appear in parts 150-189. A Toxic Substances 
Chemical--CAS Number Index appears in parts 700-789 and part 790 to End. 
Redesignation Tables appear in the volumes containing parts 50-51, parts 
150-189, and parts 700-789. Regulations issued by the Council on 
Environmental Quality appear in the volume containing part 790 to End. 
The OMB control numbers for title 40 appear in Sec. 9.1 of this chapter.

    For this volume, Bonnie J. Fritts was Chief Editor. The Code of 
Federal Regulations publication program is under the direction of 
Frances D. McDonald, assisted by Alomha S. Morris.

[[Page x]]





[[Page 1]]



                   TITLE 40--PROTECTION OF ENVIRONMENT




                    (This book contains parts 72-80)

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

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

[[Page 3]]



         CHAPTER I--ENVIRONMENTAL PROTECTION AGENCY (CONTINUED)




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

                 SUBCHAPTER C--AIR PROGRAMS (Continued)


  Editorial Note: Subchapter C--Air Programs is contained in volumes 40 
CFR parts 50-51, part 52(52.01-52.1018), part 52(52.1019-End), parts 53-
59, part 60, parts 61-62, part 63(63.1-63.1199), part 63(63.1200-End), 
parts 64-71, parts 72-80, parts 81-85, part 86, and parts 87-135.
Part                                                                Page
72              Permits regulation..........................           5
73              Sulphur dioxide allowance system............          92
74              Sulfur dioxide opt-ins......................         179
75              Continuous emission monitoring..............         206
76              Acid rain nitrogen oxides emission reduction 
                    program.................................         432
77              Excess emissions............................         457
78              Appeal procedures for Acid Rain Program.....         463
79              Registration of fuels and fuel additives....         473
80              Regulation of fuels and fuel additives......         567

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                 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.
72.14  Industrial utility-units exemption.

                  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.

                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.

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             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 an affected unit 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 subaccount for 
that unit 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 unit's 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.
    Allocate or allocation means the initial crediting of an allowance 
by the Administrator to an Allowance Tracking System unit 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 subaccount, or future year 
subaccount, to account for the number of tons of SO2 
emissions from an affected unit 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, records, deducts, and tracks 
allowances.
    Allowance Tracking System account means an account in the Allowance 
Tracking System established by the

[[Page 8]]

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 unit's 
compliance subaccount for the purposes of meeting the unit'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 unit account, the 
designated representative of the owners and operators of the affected 
unit.
    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, 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:


Baseline = BASE8587  x  {26280 / (26280 - OUTAGEHR)}  x  {36 / (36 - 
months not on line)}  x  106

    ``Months not on line'' is the number of months during January 1985 
through

[[Page 9]]

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.
    By-pass 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 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 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 design heat input (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 
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:

[[Page 10]]

    (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 
the 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 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 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

[[Page 11]]

which each affected unit at the source will meet the applicable Acid 
Rain emissions limitation and Acid Rain emissions reduction 
requirements.
    Compliance subaccount means the subaccount in an affected unit's 
Allowance Tracking System account, established pursuant to Sec. 73.31 
(a) or (b) of this chapter, in which are held, from the date that 
allowances for the current calendar year are recorded under 
Sec. 73.34(a) until December 31, allowances available for use in the 
current calendar year and, after December 31 until the date that 
deductions are made under Sec. 73.35(b), allowances available for use by 
the unit in the preceding calendar year, for the purpose of meeting the 
Acid Rain emissions limitation for sulfur dioxide.
    Compliance use date means the first calendar year for which an 
allowance may be used for purposes of meeting a unit'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 readings taken at least once every 15 minutes, a 
permanent record of emissions, expressed in pounds per hour (lb/hr) for 
sulfur dioxide and in pounds per million British thermal units (lb/
mmBtu) for nitrogen oxides. The following systems are component parts 
included in a continuous emission monitoring system:
    (1) Sulfur dioxide pollutant concentration monitor;
    (2) Flow monitor;
    (3) Nitrogen oxides pollutant concentration monitors;
    (4) Diluent gas monitor (oxygen or carbon dioxide);
    (5) A continuous moisture monitor when such monitoring is required 
by part 75 of this chapter; and
    (6) A data acquisition and handling system.
    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 systems are component 
parts included in a continuous opacity monitoring system:
    (1) Opacity monitor; and

[[Page 12]]

    (2) A 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.
    Current year subaccount means the subaccount in an Allowance 
Tracking System general account, established pursuant to Sec. 73.31(c) 
of this chapter, in which are held allowances that may be transferred to 
a unit's compliance subaccount for use for the purpose of meeting the 
Acid Rain sulfur dioxide emissions limitation.
    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 
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 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

[[Page 13]]

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.
    Direct Sale Subaccount means a subaccount in the Special Allowance 
Reserve, as specified in section 416(b) of the Act, which contains Phase 
II allowances to be sold in the amount of 25,000 per year, from calendar 
year 1993 to 1999, inclusive, and of 50,000 per year for each year 
beginning in calendar year 2000, subject to the adjustments noted in the 
regulations at part 73, subpart E of this chapter.
    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 75 of this chapter, 
the fuel identified in the State, local, or Federal permit for a plant 
and is 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, as established in a petition 
under Sec. 75.66 of this chapter.
    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.
    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 in 
paragraph 2.1 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.

[[Page 14]]

    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. 75.19 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 an affected unit during 
a calendar year that exceeds the Acid Rain emissions limitation for 
sulfur dioxide for the unit; 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.
    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 Secs. 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

[[Page 15]]

which the unit combusts the fuel measured by the fuel flowmeter for at 
least 168 unit operating hours (as defined in this section) or more.
    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.
    Future year subaccount means a subaccount in an Allowance Tracking 
System account, established by the Administrator pursuant to Sec. 73.31 
of this chapter, in which allowances are held for one of the 30 years 
following the later of 1995 or a current calendar year following 1995.
    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

[[Page 16]]

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 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 unit 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 means the product (expressed in mmBtu/time) of the gross 
calorific value of the fuel (expressed in Btu/lb) and the fuel feed rate 
into the combustion device (expressed in mass of fuel/time) and does not 
include the heat derived from preheated combustion air, recirculated 
flue gases, or exhaust from other sources.
    Hour before and 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, 
or hourly NOX emission rate recorded by a certified monitor 
during the unit operating hour immediately before and the unit 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

[[Page 17]]

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 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.
    Low mass emissions unit means an affected unit that is a gas-fired 
or oil-fired unit, burns only natural gas or fuel oil and qualifies 
under 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 means the emission 
rate of nitrogen oxides (in lb/mmBtu) calculated in accordance with 
section 3 of appendix F of part 75 of this chapter, using the maximum 
potential nitrogen oxides concentration as defined in section 2 of 
appendix A of part 75 of this chapter, and either the maximum oxygen 
concentration (in percent O2) or the minimum carbon dioxide 
concentration (in percent CO2) under all operating conditions 
of the unit except for unit start-up, shutdown, and upsets.
    Maximum rated hourly heat input means a unit-specific maximum hourly 
heat input (mmBtu) which is the higher of the manufacturer's maximum 
rated hourly heat input or the highest observed hourly heat input.
    Missing data period means the total number of consecutive hours 
during which any component part of a 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 or by one of its component parts to the

[[Page 18]]

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 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.
    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 1.0 grain or less of hydrogen sulfide per 100 
standard cubic feet and the hydrogen sulfide constitutes more than 50% 
(by weight) of the total sulfur in the gas fuel. Additionally, natural 
gas must meet either be composed of at least 70% 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

[[Page 19]]

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

[[Page 20]]

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

[[Page 21]]

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.
    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 natural gas, as defined in this section, 
that is provided by a supplier through a pipeline and that contains 0.3 
grains or less of hydrogen sulfide per 100 standard cubic feet and the 
hydrogen sulfide in content of the gas constitutes at least 50% (by 
weight) of the total sulfur in the fuel.
    Pollutant concentration monitor means that component of the 
continuous emission monitoring system that measures the concentration of 
a pollutant in a unit's flue gas.
    Potential electrical output capacity means the MWe capacity rating 
for the units which shall be equal to 33 percent of the maximum design 
heat input capacity of the steam generating unit, as calculated 
according to appendix D of part 72.
    Power distribution system means the portion of an electricity grid 
owned or operated by a utility that is dedicated to delivering electric 
energy to customers.
    Power purchase commitment means a commitment or obligation of a 
utility to purchase electric power from a facility pursuant to:
    (1) A power sales agreement;
    (2) A state regulatory authority order requiring a utility to:
    (i) Enter into a power sales agreement with the facility;
    (ii) Purchase from the facility; or
    (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

[[Page 22]]

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.
    Protocol 1 gas means a calibration gas mixture prepared and analyzed 
according to the ``Procedure for NBS-Traceable Certification of 
Compressed Gas Working Standards Used for Calibration and Audit of 
Continuous Emission Monitors (``Revised Traceability Protocol No. 
1''),'' Quality Assurance Handbook for Air Pollution Measurement 
Systems, Volume III, Stationary Source Specific Methods, Section 3.04, 
EPA-600/4-77-027b, June 1987 (set forth in appendix H of part 75 of this 
chapter) or such revised procedure as approved by the Administrator.
    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).
    Qualifying facility (QF) means a ``qualifying small power production 
facility'' within the meaning of section 3(17)(C) of the Federal Power 
Act or a ``qualifying cogeneration facility'' within the meaning of 
section 3(18)(B) of the Federal Power Act.
    Qualifying Phase I technology means a technological system of 
continuous emission reduction that is demonstrated to achieve a ninety 
(90) percent (or greater) reduction in emissions of sulfur dioxide from 
the emissions that would have resulted from the use of fossil fuels that 
were not subject to treatment prior to combustion, as provided in 
Sec. 72.42.
    Qualifying power purchase commitment means a power purchase 
commitment in effect as of November 15, 1990 without regard to changes 
to that commitment so long as:
    (1) The identity of the electric output purchaser; or
    (2) The identity of the steam purchaser and the location of the 
facility, remain unchanged as of the date the facility commences 
commercial operation; and
    (3) The terms and conditions of the power purchase commitment are 
not changed in such a way as to allow the costs of compliance with the 
Acid Rain Program to be shifted to the purchaser.
    Qualifying repowering technology means:
    (1) Replacement of an existing coal-fired boiler with one of the 
following clean coal technologies: Atmospheric or pressurized fluidized 
bed combustion, integrated gasification combined cycle, 
magnetohydrodynamics, direct and indirect coal-fired turbines, 
integrated gasification fuel cells, or as determined by the 
Administrator, in consultation with the Secretary of Energy, a 
derivative of one or more of these 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

[[Page 23]]

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 correspondence 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 or subaccount 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 concentration or volumetric flow 
measured by the pollutant concentration or flow 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 material (RGM) means a calibration gas mixture 
developed by agreement of a requestor and the National Institutes for 
Standards and Technologies (NIST) that NIST analyzes and certifies as 
``NIST traceable.'' RGMs may have concentrations different from those of 
standard reference materials.
    Research gas mixture (RGM) means a calibration gas mixture developed 
by agreement of a requestor and NIST that NIST analyzes and certifies as 
``NIST traceable.'' RGMs may have concentrations different from those of 
standard reference materials.
    Schedule of compliance means an enforceable sequence of actions, 
measures, or operations designed to achieve or maintain compliance, or 
correct non-compliance, with an applicable requirement of the Acid Rain 
Program, including any applicable Acid Rain permit requirement.
    Secretary of Energy means the Secretary of the United States 
Department of Energy or the Secretary's duly authorized representative.
    Serial number means, when referring to allowances, the unique 
identification number assigned to each allowance by the Administrator, 
pursuant to Sec. 73.34(d) of this chapter.
    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.

[[Page 24]]

    Site lease, as used in part 73, subpart E of this chapter, means a 
legally-binding agreement signed between a new IPP or a firm associated 
with a new IPP and a site owner that establishes the terms and 
conditions under which the new IPP or the firm associated with the new 
IPP has the binding right to utilize a specific site for the purposes of 
operating or constructing the new IPP.
    Small diesel refinery means a domestic motor diesel fuel refinery or 
portion of a refinery that, as an annual average of calendar years 1988 
through 1990 and as reported to the Department of Energy on Form 810, 
had bona fide crude oil throughput less than 18,250,000 barrels per 
year, and the refinery or portion of a refinery is owned or controlled 
by a refiner with a total combined bona fide crude oil throughput of 
less than 50,187,500 barrels per year.
    Solid waste incinerator means a source as defined in section 
129(g)(1) of the Act.
    Source means any governmental, institutional, commercial, or 
industrial structure, installation, plant, building, or facility that 
emits or has the potential to emit any regulated air pollutant under the 
Act. 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.
    Spot allowance means an allowance that may be used for purposes of 
compliance with a unit'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 any hour (or fraction of an hour) during 
which flue gases flow through a common stack or bypass stack.
    Standard conditions means 68  deg.F at 1 atm (29.92 in. of mercury).
    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.

[[Page 25]]

    Substitute data means emissions or volumetric flow data provided to 
assure 100 percent recording and reporting of emissions when all or part 
of the continuous emission monitoring system is not functional or is 
operating outside applicable performance specifications.
    Substitution unit means an affected unit, other than a unit under 
section 410 of the Act, that is designated as a Phase I unit in a 
substitution plan under Sec. 72.41.
    Sulfur-free generation means the generation of electricity by a 
process that does not have any emissions of sulfur dioxide, including 
hydroelectric, nuclear, solar, or wind generation. A ``sulfur-free 
generator'' is a generator that is located in one of the 48 contiguous 
States or the District of Columbia and produces ``sulfur-free 
generation.''
    Supply-side measure means a measure to improve the efficiency of the 
generation, transmission, or distribution of electricity, implemented by 
a utility in connection with its operations or facilities to provide 
electricity to its customers, and includes the measures set forth in 
part 73, appendix A, section 2 of this chapter.
    Thermal energy means the thermal output produced by a combustion 
source used directly as part of a manufacturing process but not used to 
produce electricity.
    Ton or tonnage means any ``short ton'' (i.e., 2,000 pounds). For the 
purpose of determining compliance with the Acid Rain emissions 
limitations and reduction requirements, total tons for a year shall be 
calculated as the sum of all recorded hourly emissions (or the tonnage 
equivalent of the recorded hourly emissions rates) in accordance with 
part 75 of this chapter, with any remaining fraction of a ton equal to 
or greater than 0.50 ton deemed to equal one ton and any fraction of a 
ton less than 0.50 ton deemed not to equal any ton.
    Total planned net output capacity means the planned generator output 
capacity, excluding that portion of the electrical power which is 
designed to be used at the power production facility, as specified under 
one or more qualifying power purchase commitments or contemporaneous 
documents as of November 15, 1990; ``Total installed net output 
capacity'' shall be the generator output capacity, excluding that 
portion of the electrical power actually used at the power production 
facility, as installed.
    Transfer unit means a Phase I unit that transfers all or part of its 
Phase I emission reduction obligations to a control unit designated 
pursuant to a Phase I extension plan under Sec. 72.42.
    Underutilization means a reduction, during any calendar year in 
Phase I, of the heat input (expressed in mmBtu for the calendar year) at 
a Phase I unit below the unit's baseline.
    Unit means a fossil fuel-fired combustion device.
    Unit account means an Allowance Tracking System account, established 
by the Administrator for an affected unit pursuant to Sec. 73.31 (a) or 
(b) of this chapter.
    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 any hour (or fraction of an hour) during 
which a unit combusts any fuel.
    Unit operating quarter means a calendar quarter in which a unit 
combusts any fuel.
    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.

[[Page 26]]

    Utility regulatory authority means an authority, board, commission, 
or other entity (limited to the local-, State-, or federal-level, 
whenever so specified) responsible for overseeing the business 
operations of utilities located within its jurisdiction, including, but 
not limited to, utility rates and charges to customers.
    Utility system means all interconnected units and generators 
operated by the same utility operating company.
    Utility unit means a unit owned or operated by a utility:
    (1) That serves a generator in any State that produces electricity 
for sale, or
    (2) That during 1985, served a generator in any State that produced 
electricity for sale.
    (3) Notwithstanding paragraphs (1) and (2) of this definition, a 
unit that was in operation during 1985, but did not serve a generator 
that produced electricity for sale during 1985, and did not commence 
commercial operation on or after November 15, 1990 is not a utility unit 
for purposes of the Acid Rain Program.
    (4) Notwithstanding paragraphs (1) and (2) of this definition, a 
unit that cogenerates steam and electricity is not a utility unit for 
purposes of the Acid Rain Program, unless the unit is constructed for 
the purpose of supplying, or commences construction after November 15, 
1990 and supplies, more than one-third of its potential electrical 
output capacity and more than 25 MWe output to any power distribution 
system for sale.
    Utilization means the heat input (expressed in mmBtu/time) for a 
unit.
    Very low sulfur fuel means either:
    (1) A fuel with a total sulfur content no greater than 0.05 percent 
sulfur by weight;
    (2) Natural gas or pipeline natural gas, as defined in this section; 
or
    (3) Any gaseous fuel with a total sulfur content no greater than 20 
grains of sulfur per 100 standard cubic feet.
    Volumetric flow means the rate of movement of a specified volume of 
gas past a cross-sectional area (e.g., cubic feet per hour).
    Zero air material means either:
    (1) A calibration gas certified by the gas vendor not to contain 
concentrations of SO2, NOX, or total hydrocarbons 
above 0.1 parts per million (ppm), a concentration of CO above 1 ppm, or 
a concentration of CO2 above 400 ppm;
    (2) Ambient air conditioned and purified by a CEMS for which the 
CEMS manufacturer or vendor certifies that the particular CEMS model 
produces conditioned gas that does not contain concentrations of 
SO2, NOX, or total hydrocarbons above 0.1 ppm, a 
concentration of CO above 1 ppm, or a concentration of CO2 
above 400 ppm;
    (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, as amended at 58 FR 15647, Mar. 23, 1993; 58 
FR 33770, June 21, 1993; 58 FR 40747, July 30, 1993; 60 FR 17111, Apr. 
4, 1995; 60 FR 18468, Apr. 11, 1995; 60 FR 26514, May 17, 1995; 62 FR 
55475, Oct. 24, 1997; 63 FR 57498, Oct. 27, 1998; 63 FR 68404, Dec. 11, 
1998; 64 FR 25842, May 13, 1999; 64 FR 28586, May 26, 1999]



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.

[[Page 27]]

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.
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

[[Page 28]]

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

[[Page 29]]

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, Sec. 72.8, or 
Sec. 72.14 is in effect. Although such a unit is not an affected unit, 
the unit shall be subject to the requirements of Sec. 72.7, Sec. 72.8, 
or Sec. 72.14, 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), 
401 M Street, SW., 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]



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, Secs. 72.2 through 
72.6, and Secs. 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

[[Page 30]]

under this section, a statement signed by the designated representative 
(authorized in accordance with subpart B of this part) or, if no 
designated representative has been authorized, a certifying official of 
each owner of the unit shall be submitted to permitting authority 
otherwise responsible for administering a Phase II Acid Rain permit for 
the unit. If the Administrator is not the permitting authority, a copy 
of the statement shall be submitted to the Administrator. The statement, 
which shall be in a format prescribed by the Administrator, shall 
identify the unit, state the nameplate capacity of each generator served 
by the unit and the fuels currently burned or expected to be burned by 
the unit and their sulfur content by weight, and state that the owners 
and operators of the unit will comply with paragraph (f) of this 
section.
    (3) After receipt of the statement under paragraph (b)(2) of this 
section, the permitting authority shall amend under Sec. 72.83 the 
operating permit covering the source at which the unit is located, if 
the source has such a permit, to add the provisions and requirements of 
the exemption under paragraphs (a), (b)(1), (d), and (f) of this 
section.
    (c)(1) Any new utility unit that meets the requirements of paragraph 
(a) of this section and that is allocated one or more allowances under 
subpart B of part 73 of this chapter shall be exempt from the Acid Rain 
Program, except for the provisions of this section, Secs. 72.2 through 
72.6, and Secs. 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 unit's Allowance Tracking 
System account 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. Upon completion of such deductions and receipt 
of such proceeds, the Administrator will close the unit's Allowance 
Tracking System account and notify the designated representative (or 
certifying official) and, if the Administrator is not the permitting 
authority otherwise responsible for administering a Phase II Acid Rain 
permit for the unit, the permitting authority.
    (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.

[[Page 31]]

    (d) Compliance with the requirement that fuel burned during the year 
have an annual average sulfur content of 0.05 percent by weight or less 
shall be determined as follows using a method of determining sulfur 
content that provides information with reasonable precision, 
reliability, accessibility, and timeliness:
    (1) For gaseous fuel burned during the year, if natural gas is the 
only gaseous fuel burned, the requirement is assumed to be met;
    (2) For gaseous fuel burned during the year where other gas in 
addition to or besides natural gas is burned, the requirement is met if 
the annual average sulfur content is equal to or less than 0.05 percent 
by weight. The annual average sulfur content, as a percentage by weight, 
for the gaseous fuel burned shall be calculated as follows:
[GRAPHIC] [TIFF OMITTED] TR24OC97.001


where:

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

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

[[Page 32]]

    (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, 
the unit is not an affected unit under the Acid Rain Program and parts 
70 and 71 of this chapter and is not eligible to be an opt-in source 
under part 74 of this chapter. As an unaffected unit, the unit shall 
continue to be subject to any other applicable requirements under parts 
70 and 71 of this chapter.
    (3) For a period of 5 years from the date the records are created, 
the owners and operators of a unit exempt under this section shall 
retain at the source that includes the unit records demonstrating that 
the requirements of paragraph (a) of this section are met. The 5-year 
period for keeping records may be extended for cause, at any time prior 
to the end of the period, in writing by the Administrator or the 
permitting authority.
    (i) Such records shall include, for each delivery of fuel to the 
unit or for fuel delivered to the unit continuously by pipeline, the 
type of fuel, the sulfur content, and the sulfur content of each sample 
taken.
    (ii) The owners and operators bear the burden of proof that the 
requirements of paragraph (a) of this section are met.
    (4) Loss of exemption. (i) On the earliest of the following dates, a 
unit exempt under paragraphs (b), (c), or (e) of this section shall lose 
its exemption and become an affected unit under the Acid Rain Program 
and parts 70 and 71 of this chapter:
    (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]



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, Secs. 72.2 through 72.6, Secs. 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

[[Page 33]]

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, Secs. 72.2 through 
72.6, Secs. 72.10 through 72.13, and subpart B of part 73 of this 
chapter, and shall be subject to the requirements of paragraph (d) of 
this section in lieu of the requirements set forth in the written 
exemption. The permitting authority shall amend under Sec. 72.83 the 
operating permit covering the source at which the unit is located, if 
the source has such a permit, to add the provisions and requirements of 
the exemption under this paragraph (c) and paragraph (d) of this 
section.
    (d) Special Provisions. (1) A unit exempt under this section shall 
not emit any sulfur dioxide and nitrogen oxides starting on the date 
that the exemption takes effect. The owners and operators of the unit 
will be allocated allowances in accordance with subpart B of part 73 of 
this chapter. If the unit is a Phase I unit, for each calendar year in 
Phase I, the designated representative of the unit shall submit a Phase 
I permit application in accordance with subparts C and D of this part 72 
and an annual certification report in accordance with Secs. 72.90 
through 72.92 and is subject to Secs. 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, 
the unit is not an affected unit under the Acid Rain Program and parts 
70 and 71 of this chapter and is not eligible to be an opt-in source 
under part 74 of this chapter. As an unaffected unit, the unit shall 
continue to be subject to any other applicable requirements under parts 
70 and 71 of this 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 become an affected unit under the Acid Rain Program and 
parts 70 and 71 of this chapter:
    (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]



Sec. 72.9  Standard requirements.

    (a) Permit Requirements. (1) The designated representative of each 
affected source and each affected unit at the source shall:

[[Page 34]]

    (i) Submit a complete Acid Rain permit application (including a 
compliance plan) under this part in accordance with the deadlines 
specified in Sec. 72.30;
    (ii) Submit in a timely manner a complete reduced utilization plan 
if required under Sec. 72.43; and
    (iii) Submit in a timely manner any supplemental information that 
the permitting authority determines is necessary in order to review an 
Acid Rain permit application and issue or deny an Acid Rain permit.
    (2) The owners and operators of each affected source and each 
affected unit at the source shall:
    (i) Operate the unit in compliance with a complete Acid Rain permit 
application or a superseding Acid Rain permit issued by the permitting 
authority; and
    (ii) Have an Acid Rain Permit.
    (b) Monitoring Requirements. (1) The owners and operators and, to 
the extent applicable, designated representative of each affected source 
and each affected unit at the source shall comply with the monitoring 
requirements as provided in part 75 of this chapter.
    (2) The emissions measurements recorded and reported in accordance 
with part 75 of this chapter shall be used to determine compliance by 
the unit 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 
unit's compliance subaccount (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 unit; 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 
Secs. 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 Secs. 72.7, 72.8, or 72.14 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.

[[Page 35]]

    (e) Excess Emissions Requirements. (1) The designated representative 
of an affected unit 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 unit that has excess 
emissions in any calendar year shall:
    (i) Pay without demand the penalty required, and pay upon demand the 
interest on that penalty, as required by part 77 of this chapter; and
    (ii) Comply with the terms of an approved offset plan, as required 
by part 77 of this chapter.
    (f) Recordkeeping and Reporting Requirements. (1) Unless otherwise 
provided, the owners and operators of the source and each affected unit 
at the source shall keep on site at the source each of the following 
documents for a period of 5 years from the date the document is created. 
This period may be extended for cause, at any time prior to the end of 5 
years, in writing by the Administrator or permitting authority.
    (i) The certificate of representation for the designated 
representative for the source and each affected unit at the source and 
all documents that demonstrate the truth of the statements in the 
certificate of representation, in accordance with Sec. 72.24; provided 
that the certificate and documents shall be retained on site at the 
source beyond such 5-year period until such documents are superseded 
because of the submission of a new certificate of representation 
changing the designated representative.
    (ii) All emissions monitoring information, in accordance with part 
75 of this chapter; provided that to the extent that part 75 provides 
for a 3-year period for recordkeeping, the 3-year period shall apply.
    (iii) Copies of all reports, compliance certifications, and other 
submissions and all records made or required under the Acid Rain 
Program.
    (iv) Copies of all documents used to complete an Acid Rain permit 
application and any other submission under the Acid Rain Program or to 
demonstrate compliance with the requirements of the Acid Rain Program.
    (2) The designated representative of an affected source and each 
affected unit at the source shall submit the reports and compliance 
certifications required under the Acid Rain Program, including those 
under subpart I of this part and part 75 of this chapter.
    (g) Liability. (1) Any person who knowingly violates any requirement 
or prohibition of the Acid Rain Program, a complete Acid Rain permit 
application, an Acid Rain permit, or an exemption under Sec. 72.7, 
Sec. 72.8, or Sec. 72.14, 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. Except as provided under Sec. 72.41 
(substitution plans), Sec. 72.42 (Phase I extension plans), Sec. 72.43 
(reduced utilization plans), Sec. 72.44 (Phase II repowering extension 
plans), Sec. 74.47 of this chapter (thermal energy plans), and 
Sec. 76.11 of this chapter (NOX averaging plans), and except 
with regard to the requirements applicable to units with a common stack 
under part 75 of this chapter (including Secs. 75.16, 75.17 and 75.18 of 
this chapter), the owners and operators and the designated 
representative of one affected unit shall not be liable for any 
violation by any other affected unit of

[[Page 36]]

which they are not owners or operators or the designated representative 
and that is located at a source of which they are not owners or 
operators or the designated representative.
    (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, Sec. 72.8, or Sec. 72.14 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 unit can hold; provided, 
that the number of allowances held by the unit shall not affect the 
source's obligation to comply with any other provisions of the Act.
    (3) Requiring a change of any kind in any State law regulating 
electric utility rates and charges, affecting any State law regarding 
such State regulation, or limiting such State regulation, including any 
prudence review requirements under such State law.
    (4) Modifying the Federal Power Act or affecting the authority of 
the Federal Energy Regulatory Commission under the Federal Power Act.
    (5) Interfering with or impairing any program for competitive 
bidding for power supply in a State in which such program is 
established.

[58 FR 3650, Jan. 11, 1993, as amended at 60 FR 17113, Apr. 4, 1995; 62 
FR 55478, Oct. 24, 1997]



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 Office of the Federal Register, 800 
North Capitol Street, NW., Suite 700, Washington, DC, at the Public 
Information Reference Unit of the U.S. EPA, 401 M Street SW, Washington, 
DC and at the Library (MD-35), U.S. EPA, Research Triangle Park, North 
Carolina.

[[Page 37]]

    (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]



Sec. 72.14  Industrial utility-units exemption.

    (a) Applicability. This section applies to any non-cogeneration, 
utility unit that has not previously lost an exemption under paragraph 
(d)(4) of this section and that meets the following criteria:
    (1) Starting on the date of the signing of the interconnection 
agreement under paragraph (a)(2) of this section and thereafter, there 
has been no owner or operator of the unit, division or subsidiary or 
affiliate or parent company of an owner or operator of the unit, or 
combination thereof whose principal business is the sale, transmission, 
or distribution of electricity or that is a public utility under the 
jurisdiction of a State or local utility regulatory authority;
    (2) On or before March 23, 1993, the owners or operators of the unit 
entered into an interconnection agreement and any related power purchase 
agreement with a person whose principal business is the sale, 
transmission, or distribution of electricity or that is a public utility 
under the jurisdiction of a State or local utility regulatory authority, 
requiring the generator or generators served by the unit to produce 
electricity for sale only for incidental electricity sales to such 
person;
    (3) The unit served or serves one or more generators that, in 1985 
or any year thereafter, actually produced electricity for sale only for 
incidental electricity sales required under the interconnection 
agreement and any related power purchase agreement under paragraph 
(a)(2) of this section or a successor agreement under paragraph 
(d)(4)(ii) of this section; and
    (4) Incidental electricity sales, under this section, are total 
annual sales of electricity produced by a generator that do not exceed 
10 percent of the nameplate capacity of that generator times 8,760 hours 
per year and do not exceed 10 percent of the actual annual electric 
output of that generator.
    (b) Petition for exemption. The designated representative 
(authorized in accordance with subpart B of this part) of a unit under 
paragraph (a) of this section may submit to the permitting authority 
otherwise responsible for administering a Phase II Acid Rain permit for 
the unit a complete petition for an exemption for the unit from the 
requirements of the Acid Rain Program, except for the provisions of this 
section, Secs. 72.2 through 72.6, and Secs. 72.10 through 72.13. If the 
Administrator is not the permitting authority, a copy of the petition 
shall be submitted to the Administrator. A complete petition shall 
include the following elements in a format prescribed by the 
Administrator:
    (1) Identification of the unit;
    (2) A statement that the unit is not a cogeneration unit;
    (3) A list of the current owners and operators of the unit and any 
other owners and operators of the unit, starting on the date of the 
signing of the interconnection agreement under paragraph (a)(2) of this 
section, and a statement that, starting on that date, there has been no 
owner or operator of the unit, division or subsidiary or affiliate or 
parent company of an owner or operator of the unit, or combination 
thereof whose principal business is the sale, transmission, or 
distribution of electricity or that is a public utility under the 
jurisdiction of a State or local utility regulatory authority;
    (4) A summary of the terms of the interconnection agreement and any 
related power purchase agreement under

[[Page 38]]

paragraph (a)(2) of this section and any successor agreement under 
paragraph (d)(4)(ii) of this section, including the date on which the 
agreement was signed, the amount of electricity that may be required to 
be produced for sale by each generator served by the unit, and the 
provisions for expiration or termination of the agreement;
    (5) A copy of the interconnection agreement and any related power 
purchase agreement under paragraph (a)(2) of this section and any 
successor agreement under paragraph (d)(4)(ii) of this section;
    (6) The nameplate capacity of each generator served by the unit;
    (7) For each year starting in 1985, the actual annual electrical 
output of each generator served by the unit, the total amount of 
electricity produced for sales to any customer by each generator, and 
the total amount of electricity produced and sold as required by the 
interconnection agreement and any related power purchase agreement under 
paragraph (a)(2) of this section or any successor agreement under 
paragraph (d)(4)(ii) of this section;
    (8) A statement that each generator served by the unit actually 
produced electricity for sale only for incidental electricity sales (in 
accordance with paragraph (a)(4) of this section) required under the 
interconnection agreement and any related power purchase agreement under 
paragraph (a)(2) of this section or any successor agreement under 
paragraph (d)(4)(ii) of this section; and
    (9) The special provisions of paragraph (d) of this section.
    (c) Permitting Authority's Action. (1) (i) For any unit meeting the 
requirements of paragraphs (a) and (b) of this section, the permitting 
authority shall issue an exemption from the requirements of the Acid 
Rain Program, except for the provisions of this section, Secs. 72.2 
through 72.6 and Secs. 72.10 through 72.13.
    (ii) If a petition for exemption is submitted for a unit but the 
designated representative fails to demonstrate that the requirements of 
paragraph (a) of this section are met, the permitting authority shall 
deny an exemption under this section.
    (2) In issuing or denying an exemption under paragraph (c)(1) of 
this section, the permitting authority shall treat the petition for 
exemption as a permit application and apply the procedures used for 
issuing or denying draft, proposed (if the Administrator is not the 
permitting authority otherwise responsible for administering a Phase II 
Acid Rain permit for the unit), and final Acid Rain permits.
    (3) An exemption issued under paragraph (c)(1)(i) of this section 
shall become effective on January 1 of the first full year the unit 
meets the requirements of paragraph (a) of this section.
    (4) An exemption issued under paragraph (c)(1)(i) of this section 
shall be effective until the date on which the unit loses the exemption 
under paragraph (d)(4) of this section.
    (5) After issuance of the exemption under paragraphs (c)(1) and (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 (c)(1)(i) and (d) of this section.
    (d) Special Provisions. (1) 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.
    (2) For any period for which a unit is exempt under this section, 
the unit is not an affected unit under the Acid Rain Program and parts 
70 and 71 of this chapter and is not eligible to be an opt-in source 
under part 74 of this chapter. As an unaffected unit, the unit shall 
continue to be subject to any other applicable requirements under parts 
70 and 71 of this 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 owners 
and operators bear

[[Page 39]]

the burden of proof that the requirements 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. Such records shall include the following 
information:
    (i) A copy of the interconnection agreement and any related power 
purchase agreement under paragraph (a)(2) of this section and any 
successor agreement under paragraph (d)(4)(ii) of this section;
    (ii) The nameplate capacity of each generator served by the unit; 
and
    (iii) For each year starting in 1985, the actual annual electrical 
output of each generator served by the unit, the total amount of 
electricity produced for sales to any customer by each generator, and 
the total amount of electricity produced and sold as required by the 
interconnection agreement and any related power purchase agreement under 
paragraph (a)(2) of this section or any successor agreement under 
paragraph (d)(4)(ii) of this section.
    (4) Loss of exemption. (i) On the earliest of the following dates, a 
unit exempt under this section shall lose its exemption and become an 
affected unit under the Acid Rain Program and parts 70 and 71 of this 
chapter:
    (A) The first date on which there is an owner or operator of the 
unit, division or subsidiary or affiliate or parent company of an owner 
or operator of the unit, or combination thereof, whose principal 
business is the sale, transmission, or distribution of electricity or 
that is a public utility under the jurisdiction of a State or local 
utility regulatory authority.
    (B) If any generator served by the unit actually produces any 
electricity for sale other than for sale to the person specified as the 
purchaser in the interconnection agreement or any related power purchase 
agreement under paragraph (a)(2) of this section or a successor 
agreement under paragraph (d)(4)(ii) of this section, then the day after 
the date on which such electricity is sold.
    (C) If any generator served by the unit actually produces any 
electricity for sale to the person specified as the purchaser in the 
interconnection agreement or any related power purchase agreement under 
paragraph (a)(2) of this section or a successor agreement under 
paragraph (d)(4)(ii) of this section where such sale is not required 
under that interconnection agreement or related power purchase agreement 
or successor agreement or where such sale will result in total sales for 
a calendar year exceeding 10 percent of the nameplate capacity of that 
generator times 8,769 hours per year, then the day after the date on 
which such sale is made.
    (D) If any generator served by the unit actually produces any 
electricity for sale to the person specified as the purchaser in the 
interconnection agreement or related power purchase agreement under 
paragraph (a)(2) of this section or a successor agreement under 
paragraph (d)(4)(ii) of this section where such sale results in total 
sales for a calendar year exceeding 10 percent of the actual electric 
output of the generator for that year, then January 1 of the year after 
such year.
    (E) If the interconnection agreement or related power purchase 
agreement under paragraph (a)(2) of this section expires or is 
terminated, no successor agreement under paragraph (d)(4)(ii) of this 
section is in effect, and any generator served by the unit actually 
produces any electricity for sale, then the day after the date on which 
such electricity is sold.
    (ii) A ``successor agreement'' is an agreement that:
    (A) Modifies, replaces or supersedes the interconnection agreement 
or related power purchase agreement under paragraph (a)(2) of this 
section;
    (B) Is between the owners and operators of the unit and a person 
that is contractually obligated to sell electricity to the owners and 
operators of the unit and either whose principal business is the sale, 
transmission, or distribution of electricity or that is a public utility 
under the jurisdiction of a State or local utility regulatory authority; 
and
    (C) Requires the generator served by the unit to produce electricity 
for sale to the person under paragraph (d)(4)(ii)(B) of this section and 
only for incidental electricity sales, such that the total amount of 
electricity that

[[Page 40]]

such generator is required to produce for sale under the interconnection 
agreement or related power purchase agreement (to the extent they are 
still in effect) and the successor agreement shall not exceed the total 
amount of electricity that such generator was required to produce for 
sale under the interconnection agreement or related power purchase 
agreement under paragraph (a)(2) of this section.
    (iii) 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.
    (iv) 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 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 actions, inactions, or submissions, legally 
bind each owner and operator of the affected source represented and each 
affected unit at the source in all matters pertaining to the Acid Rain 
Program, not withstanding any agreement between the designated 
representative and such owners and operators. The owners and operators 
shall be bound by any order issued to the designated representative by 
the Administrator, the permitting authority, or a court.
    (c) The designated representative shall be selected and act in 
accordance with the certifications set forth in Sec. 72.24(a) (4), (5), 
(7), and (9).
    (d) No Acid Rain permit shall be issued to an affected source, nor 
shall any allowance transfer be recorded for an Allowance Tracking 
System account of an affected unit at a source, until the Administrator 
has received a complete certificate of representation for the designated 
representative of the source and the affected units at the source.



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 affected source or affected 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.

[[Page 41]]

    (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 unit account.

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



Sec. 72.22  Alternate designated representative.

    (a) The certificate of representation may designate one and only one 
alternate designated representative, who may act on behalf of the 
designated representative. The agreement by which the alternate 
designated representative is selected shall include a procedure for the 
owners and operators of the source and affected units at the source to 
authorize the alternate designated representative to act in lieu of the 
designated representative.
    (b) Upon receipt by the Administrator of a complete certificate of 
representation that meets the requirements of Sec. 72.24 (including 
those applicable to the alternate designated representative), any 
action, representation, or failure to act 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]



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

    (a) Changing the designated representative. The designated 
representative

[[Page 42]]

may be changed at any time upon receipt by the Administrator of a 
superseding complete certificate of representation. Notwithstanding any 
such change, all submissions, actions, and inactions 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 submissions, actions, and inactions 
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 a new 
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 new owner or operator shall be 
deemed to be subject to and bound by the certificate of representation, 
the submissions, actions, and inactions of the designated representative 
and any alternative designated representative of the source or unit, and 
the decisions, actions, and inactions of the Administrator and 
permitting authority, as if the new 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.



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.
    (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) The following statement: ``I certify that I have given notice of 
the agreement, selecting me as the `designated representative' for the 
affected source and each affected unit at the source identified in this 
certificate of representation, 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.''
    (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 actions, inactions, or 
submissions.''
    (7) The following statement: ``I certify that I shall abide by any 
fiduciary responsibilities imposed by the agreement by which I was 
selected as `designated representative' or `alternate designated 
representative', as applicable.''
    (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

[[Page 43]]

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 life-of-the-unit, firm power contractual 
arrangements, 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 
or, 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) If an alternate designated representative is authorized in the 
certificate of representation, the following statement: ``The agreement 
by which I was selected as the alternate designated representative 
includes a procedure for the owners and operators of the source and 
affected units at the source to authorize the alternate designated 
representative to act in lieu of the designated representative.''
    (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]



Sec. 72.25  Objections.

    (a) Once a complete certificate of representation has been submitted 
in accordance with Sec. 72.24, the Administrator will rely on the 
certificate of representation unless and until a superseding complete 
certificate is received by the Administrator.
    (b) Except as provided in Sec. 72.23, no objection or other 
communication submitted to the Administrator or the permitting authority 
concerning the authorization, or any submission, action or inaction, of 
the designated representative shall affect any submission, action, or 
inaction 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]



                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.

[[Page 44]]

    (b) Deadlines. (1) Phase 1. (i) The designated representative shall 
submit a complete Acid Rain permit application governing an affected 
unit during Phase I to the Administrator on or before February 15, 1993 
for:
    (A) Any source with such a unit under Sec. 72.6(a)(1); and
    (B) Any source with such a unit under Sec. 72.6(a) (2) or (3) that 
is designated a substitution or compensating unit in a substitution plan 
or reduced utilization plan submitted to the Administrator for approval 
or conditional approval.
    (ii) Notwithstanding paragraph (b)(1)(i) of this section, if a unit 
at a source not previously permitted is designated a substitution or 
compensating unit in a submission requesting revision of an existing 
Acid Rain permit, the designated representative of the unit shall submit 
a complete Acid Rain permit application on the date that the submission 
requesting the revision is made.
    (2) Phase II. (i) For any source with an existing unit under 
Sec. 72.6(a)(2), the designated representative shall submit a complete 
Acid Rain permit application governing such unit during Phase II to the 
permitting authority on or before January 1, 1996.
    (ii) For any source with a new unit under Sec. 72.6(a)(3)(i), the 
designated representative shall submit a complete Acid Rain permit 
application governing such unit to the permitting authority at least 24 
months before the later of January 1, 2000 or the date on which the unit 
commences operation.
    (iii) For any source with a unit under Sec. 72.6(a)(3)(ii), the 
designated representative shall submit a complete Acid Rain permit 
application governing such unit to the permitting authority at least 24 
months before the later of January 1, 2000 or the date on which the unit 
begins to serve a generator with a nameplate capacity greater than 25 
MWe.
    (iv) For any source with a unit under Sec. 72.6(a)(3)(iii), the 
designated representative shall submit a complete Acid Rain permit 
application governing such unit to the permitting authority at least 24 
months before the later of January 1, 2000 or the date on which the 
auxiliary firing commences operation.
    (v) For any source with a unit under Sec. 72.6(a)(3)(iv), the 
designated representative shall submit a complete Acid Rain permit 
application governing such unit to the permitting authority before the 
later of January 1, 1998 or March 1 of the year following the three 
calendar year period in which the unit sold to a utility power 
distribution system an annual average of more than one-third of its 
potential electrical output capacity and more than 219,000 MWe-hrs 
actual electric output (on a gross basis).
    (vi) For any source with a unit under Sec. 72.6(a)(3)(v), the 
designated representative shall submit a complete Acid Rain permit 
application governing such unit to the permitting authority before the 
later of January 1, 1998 or March 1 of the year following the calendar 
year in which the facility fails to meet the definition of qualifying 
facility.
    (vii) For any source with a unit under Sec. 72.6(a)(3)(vi), the 
designated representative shall submit a complete Acid Rain permit 
application governing such unit to the permitting authority before the 
later of January 1, 1998 or March 1 of the year following the calendar 
year in which the facility fails to meet the definition of an 
independent power production facility.
    (viii) For any source with a unit under Sec. 72.6(a)(3)(vii), the 
designated representative shall submit a complete Acid Rain permit 
application governing such unit to the permitting authority before the 
later of January 1, 1998 or March 1 of the year following the three 
calendar year period in which the incinerator consumed 20 percent or 
more fossil fuel (on a Btu basis).
    (c) Duty to reapply. The designated representative shall submit a 
complete Acid Rain permit application for each source with an affected 
unit at least 6 months prior to the expiration of an existing Acid Rain 
permit governing 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

[[Page 45]]

date of the permit for which the application is submitted.
    (d) The original and three copies of all permit applications for 
Phase I and where the Administrator is the permitting authority, for 
Phase II, shall be submitted to the EPA Regional Office for the Region 
where the affected source is located. The original and three copies of 
all permit applications for Phase II, where the Administrator is not the 
permitting authority, shall be submitted to the State permitting 
authority for the State where the affected source is located.
    (e) Where two or more affected units are located at a source, the 
permitting authority may, in its sole discretion, allow the designated 
representative of the source to submit, under paragraph (a) or (c) of 
this section, two or more Acid Rain permit applications covering the 
units at the source, provided that each affected unit is covered by one 
and only one such application.

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



Sec. 72.31  Information requirements for Acid Rain permit applications.

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

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



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

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

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



Sec. 72.33  Identification of dispatch system.

    (a) Every Phase I unit shall be treated as part of a dispatch system 
for purposes of Secs. 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

[[Page 46]]

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 
Secs. 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 Secs. 72.91 and 72.92 
(including the dispatch system data report) treating the utility system 
of each unit or generator as its respective dispatch system and treating 
the identification of dispatch system as no longer in effect.
    (f)(1) Notwithstanding paragraph (e)(1) of this section or any 
submission of an identification of dispatch system under paragraphs (b) 
or (d) of this section, the designated representative of a Phase I unit 
with two or more owners may petition the Administrator to treat, as the 
dispatch system for an owner's portion of the unit, the dispatch system 
of another unit.
    (i) The owner's portion of the unit shall be based on one of the 
following apportionment methods:
    (A) Owner's share of the unit's capacity in 1985-1987. Under this 
method, the baseline of the owner's portion of the unit shall equal the 
baseline of the unit multiplied by the average of the owner's percentage 
ownership of the capacity of the unit for each year during 1985-1987. 
The actual utilization of the owner's portion of the unit for a year in 
Phase I shall equal the actual utilization of the unit for the year that 
is attributed to the owner.
    (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

[[Page 47]]

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

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

[[Page 48]]

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 Secs. 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 Secs. 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 Secs. 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 Secs. 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 
Secs. 72.91 and 72.92 (including the dispatch system data report), 
treating the entire unit as a single Phase I unit, in accordance with 
paragraph (e)(1) of this paragraph and any identification of dispatch 
system submitted under paragraph (b) or (d) of this section; and
    (iii) The designated representative surrender for deduction the 
number of allowances calculated, consistent with the reports under 
paragraph (f)(5)(ii) of this section and Secs. 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

[[Page 49]]

in Phase I and the designated representatives shall make all submissions 
under Secs. 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 unit's compliance subaccount (after deductions under Sec. 73.34(c) 
of this chapter), or in the compliance subaccount of another affected 
unit at the same source to the extent provided in Sec. 73.35(b)(3), not 
less than the total annual emissions of sulfur dioxide from the unit. 
The compliance plan may also specify, in accordance with this subpart, 
one or more of the Acid Rain compliance options.
    (2) For nitrogen oxides emissions, certify that the unit will comply 
with the applicable emission limitation under Sec. 76.5, Sec. 76.6, or 
Sec. 76.7 of this chapter or shall specify one or more Acid Rain 
compliance options, in accordance with part 76 of this chapter.
    (b) Multi-unit compliance options. (1) A plan for a compliance 
option, under Sec. 72.41, 72.42, 72.43, or 72.44 of this part, under 
Sec. 74.47 of this chapter, or a NOX averaging plan under 
Sec. 76.11 of this chapter, that includes units at more than one 
affected source shall be complete only if:
    (i) Such plan is signed and certified by the designated 
representative for each source with an affected unit governed by such 
plan; and
    (ii) A complete permit application is submitted covering each unit 
governed by such plan.
    (2) A permitting authority's approval of a plan under paragraph 
(b)(1) of this section that includes units in more than one State shall 
be final only after every permitting authority with jurisdiction over 
any such unit has approved the plan with the same modifications or 
conditions, if any.
    (c) Conditional Approval. In the compliance plan, the designated 
representative of an affected unit may propose, in accordance with this 
subpart, any Acid Rain compliance option for conditional approval, 
except a Phase I extension plan; provided that an Acid Rain compliance 
option under section 407 of 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

[[Page 50]]

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]



Sec. 72.41  Phase I substitution plans.

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

[[Page 51]]

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

[[Page 52]]

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

[[Page 53]]

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

[[Page 54]]

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

[[Page 55]]

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

[[Page 56]]

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, 401 M Street, 
SW., Washington, DC 20460.
    (2) By February 15, 1993:
    (i) The designated representative for each source with a control 
unit shall submit a Phase I extension plan as a part of the Acid Rain 
permit application for the source, and
    (ii) The designated representative for each source with a unit 
designated as a transfer unit in any plan submitted under paragraph 
(b)(2)(i) of this section shall incorporate in the Acid Rain permit 
application each such plan.
    (c) Contents of early ranking application. A complete early ranking 
application shall include the following elements in a format prescribed 
by the Administrator:
    (1) Identification of each control unit. All control units in an 
application must be located at the same source. If the control unit is 
not a unit under paragraph (a)(1)(i) of this section, a substitution 
plan or a reduced utilization plan governing the unit shall be submitted 
by the deadline for submitting a Phase I permit application.
    (2) Identification of each transfer unit. A unit shall not be a 
transfer unit in more than one early ranking application.

[[Page 57]]

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

[[Page 58]]

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

[[Page 59]]

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

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[[Page 60]]

    (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 
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calculated as follows:

Allowances deducted = (1 - (percent reduction achieved90%))  x  Phase I 
    extension reserve allowances received

where:

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

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



Sec. 72.43  Phase I reduced utilization plans.

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

[[Page 61]]

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

[[Page 62]]

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

[[Page 63]]

    (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 
Secs. 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 Secs. 72.91 and 72.92.
    (3) Liability. The owners and operators of a unit governed by an 
approved reduced utilization plan shall be liable for any violation of 
the plan or this section at that or any other unit governed by the plan, 
including liability for fulfilling the obligations specified in part 77 
of this chapter and section 411 of the Act.
    (4) Termination. (i) A reduced utilization plan shall be in effect 
only in Phase I for the calendar years specified in the plan or until 
the calendar year for which a termination of the plan takes effect; 
provided that no reduced utilization plan that designates a compensating 
unit that serves as a control unit under a Phase I extension plan shall 
be terminated, and no such unit shall be de-designated as a compensating 
unit, before the end of Phase I.
    (ii) To terminate a reduced utilization plan for a given calendar 
year prior to its last year for which the plan was approved:

[[Page 64]]

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

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



Sec. 72.44  Phase II repowering extensions.

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

[[Page 65]]

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

[[Page 66]]

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

[[Page 67]]

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

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



                  Subpart E--Acid Rain Permit Contents



Sec. 72.50  General.

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



Sec. 72.51  Permit shield.

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

[[Page 68]]

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

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



         Subpart F--Federal Acid Rain Permit Issuance Procedures



Sec. 72.60  General.

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

[62 FR 55481, Oct. 24, 1997]



Sec. 72.61  Completeness.

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

[[Page 69]]

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

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



Sec. 72.62  Draft permit.

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



Sec. 72.63  Administrative record.

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



Sec. 72.64  Statement of basis.

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



Sec. 72.65  Public notice of opportunities for public comment.

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

[[Page 70]]

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

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



Sec. 72.66  Public comments.

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

[[Page 71]]

    (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.
    (b)(1) The term of every Acid Rain permit shall be 5 years 
commencing on its effective date.
    (2) Every Acid Rain permit for Phase I shall take effect on January 
1, 1995.

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



              Subpart G--Acid Rain Phase II Implementation



Sec. 72.70  Relationship to title V operating permit program.

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

[[Page 72]]

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 or for issuing exemptions under Sec. 72.14. 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]



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 
Secs. 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 Secs. 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 Secs. 72.72 and 72.73. On the later of 
the date of publication of such notice in the Federal Register or the 
date on which the State operating permit program is approved under part 
70 of this chapter, the State Acid Rain program accepted by the 
Administrator will become a portion of the approved State operating 
permit program. Before accepting or rejecting all or a portion of a 
State Acid Rain Program, the Administrator will provide notice and 
opportunity for public comment on such acceptance or rejection.
    (c)(1) Except as provided in paragraph (c)(2) of this section, the 
Administrator will issue all Acid Rain permits for Phase I. The 
Administrator reserves the right to delegate the remaining 
administration and enforcement of Acid Rain permits for Phase I to 
approved State operating permit programs.
    (2) The State permitting authority will issue an opt-in permit for a 
combustion or process source subject to its jurisdiction if, on the date 
on which the combustion or process source submits an opt-in permit 
application, the State permitting authority has opt-in regulations 
accepted under paragraph (b) of this section and an approved operating 
permits program under part 70 of this chapter.

[62 FR 55482, Oct. 24, 1997]



Sec. 72.72  Criteria for State operating permit program.

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

[[Page 73]]

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

[[Page 74]]

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

[[Page 75]]

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.
    (6) Industrial Utility-Units Exemption. The State permitting 
authority shall act in accordance with Sec. 72.14 on any petition for 
exemption from requirements of the Acid Rain Program.

[58 FR 3650, Jan. 11, 1993, as amended at 60 FR 17113, Apr. 4, 1995; 62 
FR 55482, Oct. 24, 1997]



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, the first Acid Rain 
permit for Phase II issued to a source may have a term of less than 5 
years where necessary to coordinate the term of such permit with the 
term of an operating permit to be issued to the source under a State 
operating permit program. Each Acid Rain permit issued in accordance 
with paragraph (b)(1) of this section shall take effect by the later of 
January 1, 2000, or, where the permit governs a unit under 
Sec. 72.6(a)(3) of this part, the deadline for monitor certification 
under part 75 of this chapter.

[62 FR 55483, Oct. 24, 1997]



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

[[Page 76]]

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 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

[[Page 77]]

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 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.

[[Page 78]]

    (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 Secs. 72.81 and 72.82 of 
this part, the permitting authority may, in its discretion, determine 
which of these sections is applicable.

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



Sec. 72.81  Permit modifications.

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

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



Sec. 72.82  Fast-track modifications.

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

[[Page 79]]

    (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 or which was approved by the 
permitting authority under Sec. 72.14; and
    (14) Incorporation of changes that the Administrator has determined 
to be similar to those in paragraphs (a)(1) through (13) of this 
section.
    (b)(1) The permitting authority will take final action on an 
administrative permit amendment within 60 days, or, for the addition of 
an alternative emissions limitation demonstration period, within 90 
days, of receipt of the requested amendment and may take such action 
without providing prior public notice. The source may implement any 
changes in the administrative permit amendment immediately upon 
submission of the requested amendment, provided that the requirements of 
paragraph (a) of this section are met.
    (2) The permitting authority may, on its own motion, make an 
administrative permit amendment under paragraph (a)(3), (a)(4), (a)(12), 
or (a)(13) of

[[Page 80]]

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]



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 Secs. 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 in which a 
unit is subject to the Acid Rain emissions limitations, the designated 
representative of the source at which the unit is located shall submit 
to the Administrator, within 60 days after the end of the calendar year, 
an annual compliance certification report for the unit.
    (b) Contents of report. The designated representative shall include 
in the annual compliance certification report under paragraph (a) of 
this section the following elements, in a format prescribed by the 
Administrator, concerning the unit and the calendar year covered by the 
report:
    (1) Identification of the unit;
    (2) For all Phase I units, the information in accordance with 
Secs. 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

[[Page 81]]

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]



Sec. 72.91  Phase I unit adjusted utilization.

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

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


where:

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


[[Page 82]]


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 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

[[Page 83]]

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 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.

[[Page 84]]

    (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  2000 lbs/ton


where:

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

[[Page 85]]

    (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 Secs. 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 Secs. 72.92(a) and 
(c) and 73.35(b) of this chapter:
    (A) The designated representative shall recalculate the unit's 
adjusted utilization in accordance with paragraph (a) of this section, 
replacing the amounts for reduction from energy conservation and 
reduction from improved unit efficiency by the amount for verified heat 
input reduction. ``Verified heat input reduction'' is the total of the 
amounts of verified reduction in the unit's heat input (in mmBtu) from 
energy conservation and improved unit efficiency measures included in 
the confirmation report.
    (B) After recalculating the adjusted utilization under paragraph 
(b)(5)(ii)(A) of this section for all Phase I units that are in the 
unit's dispatch system and to which paragraph (b)(5) of this section is 
applicable, the designated representative shall calculate the number of 
allowances to be surrendered in accordance with Sec. 72.92(c)(2) using 
the recalculated adjusted utilizations of such Phase I units.
    (C) The allowances to be deducted under paragraph (b)(5) of this 
section shall equal the amount under paragraph (b)(5)(ii)(B) of this 
section, provided that if the amount calculated under this paragraph 
(b)(5)(ii)(C) is equal to or less than zero, then the amount of 
allowances to be deducted is zero.
    (6) The Administrator will determine the amount of allowances that 
would have been included in the unit's compliance subaccount and the 
amount of excess emissions of sulfur dioxide that would have resulted if 
the deductions made under Sec. 73.35(b) of this chapter had been based 
on the verified, rather than the estimated, reduction in the unit's heat 
input from energy conservation and improved unit efficiency measures.
    (7) The Administrator will determine whether the amount of excess 
emissions of sulfur dioxide under paragraph (b)(6) of this section 
differs from the amount of excess emissions determined under 
Sec. 73.35(b) of this chapter based on the annual compliance 
certification report. If the amounts differ, the Administrator will 
determine: The number of allowances that should be deducted to offset 
any increase in excess emissions or returned to account for any decrease 
in excess emissions; and the amount of excess emissions penalty 
(excluding interest) that should be paid or returned to account for the 
change in excess emissions. The Administrator will deduct immediately 
from the unit's compliance subaccount the amount of allowances that he 
or she determines is necessary to offset any increase in excess 
emissions or will return immediately to the unit's compliance subaccount 
the amount of allowances that he or she determines is necessary to 
account for any decrease in excess emissions. The designated 
representative may identify the serial numbers of the allowances to be 
deducted or returned. In the absence of such identification, the 
deduction will be on a first-in, first-out basis under Sec. 73.35(b)(2) 
of this chapter and the return will be at the Administrator's 
discretion.
    (8) If the designated representative of a unit fails to submit on a 
timely basis a confirmation report (in accordance with paragraph (b) of 
this section) with regard to the estimate of expected kilowatt hour 
savings or improvement in

[[Page 86]]

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 `` 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;

[[Page 87]]

    (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  2000 
    lbs/ton.

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


where:

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

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


where:

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

[[Page 88]]

[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 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

[[Page 89]]

(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;
    (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

[[Page 90]]

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 unit's compliance subaccount 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 unit 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]



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 unit's Allowance Tracking System account in accordance 
with part 73 of this chapter based on the information in the compliance 
certifications and other submissions, as adjusted.

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/

[[Page 91]]

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

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

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

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


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

   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

[[Page 92]]

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.

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

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

For example:

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

[58 FR 15649, Mar. 23, 1993]



PART 73--SULFUR DIOXIDE ALLOWANCE SYSTEM--Table of Contents




                    Subpart A--Background and Summary

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

                    Subpart B--Allowance Allocations

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

                  Subpart C--Allowance Tracking System

73.30  Allowance tracking system accounts.
73.31  Establishment of accounts.
73.32  Allowance account contents.
73.33  Authorized account representative.
73.34  Recordation in accounts.
73.35  Compliance.
73.36  Banking.
73.37  Account error and dispute resolution.
73.38  Closing of accounts.

                     Subpart D--Allowance Transfers

73.50  Scope and submission of transfers.
73.51  Prohibition.
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

[[Page 93]]

                   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 Secs. 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, andIndependent Power Producers 
Written Guarantee'', are codified at Secs. 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 unit account for each unit listed in table 1 of this section in 
the amount listed in column A to be held in each future year subaccount 
for the years 1995 through 1999.

                                     Table 1--Phase I Allowance Allocations
----------------------------------------------------------------------------------------------------------------
                                                                                                       Column B
                                                                                     Column A final  auction and
            State name                         Plant name                Boiler          phase 1        sales
                                                                                       allocation      reserve
----------------------------------------------------------------------------------------------------------------
Alabama...........................  Colbert........................  1                        13213          357
                                                                     2                        14907          403
                                                                     3                        14995          405
                                                                     4                        15005          405

[[Page 94]]

 
                                                                     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
                                                                     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

[[Page 95]]

 
                                    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
                                                                     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

[[Page 96]]

 
                                                                     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
                                    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

[[Page 97]]

 
                                                                     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 unit account for each unit listed in table 2 of this 
section in the amount specified in table 2 column C to be held in the 
future year subaccounts representing calendar years 2000 through 2009.
    (2) The Administrator will allocate allowances to the unit account 
for each unit listed in table 2 of this section in the amount specified 
in table 2 column F to be held in the future year subaccounts 
representing calendar years 2010 and each year thereafter.

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[GRAPHIC] [TIFF OMITTED] TR28SE98.001


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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 148]]


[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]



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), 401 M Street, SW., 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 
Secs. 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]



Secs. 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 SO2 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;
    (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-

[[Page 149]]

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 other units at the same source that did 
operate during 1990.
    (5) Early reduction credits will be calculated at the unit level, 
subject to

[[Page 150]]

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 151]]


    (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.

[[Page 152]]

[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 153]]

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

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



Sec. 73.21  Phase II repowering allowances.

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


where:

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


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


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

[[Page 154]]

[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]



Secs. 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 155]]

[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 156]]

[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 unit's Allowance Tracking System 
account 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 unit's Allowance Tracking System account 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]



                  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 accounts for all affected units pursuant to Sec. 73.31 (a) and 
(b). All allocations of allowances pursuant to subparts B, E, and F of 
this part and part

[[Page 157]]

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 unit's Allowance Tracking System 
account.
    (b) Nature and function of general accounts. Transfers of allowances 
held for any person other than an affected unit, made pursuant to 
subparts C, D, E, F, and G of this part will be recorded in that 
person's Allowance Tracking System account established pursuant to 
Sec. 73.31(c).

[58 FR 3687, Jan. 11, 1993; 58 FR 40747, July 30, 1993]



Sec. 73.31  Establishment of accounts.

    (a) Existing affected units. The Administrator will establish an 
Allowance Tracking System account and allocate allowances for each 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 
an Allowance Tracking System account for the unit.
    (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 Allowance Tracking System 
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 actions, inactions, or 
submissions under 40 CFR part 73. I shall abide by any fiduciary 
responsibilities assigned pursuant to the binding agreement. 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 158]]

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]



Sec. 73.32  Allowance account contents.

    Each allowance account will include, at a minimum, the following:
    (a) The name, address, telephone number and facsimile transmission 
number, if any, of the authorized account representative; and
    (1) In the case of a unit account, a list of all persons identified 
as owners of record of the unit in Sec. 72.24(a)(3) of this chapter, or
    (2) In the case of a general account, a list of all persons subject 
to the binding agreement for the authorized account representative to 
represent their ownership interest with respect to allowances, as 
identified in accordance with Sec. 73.31(c);
    (b) A list of transfers of allowances to, and from, the account, 
including the identity of the transferror and transferee accounts;
    (c) In the case of a unit account for an existing affected unit, 
beginning in 1995, a compliance subaccount;
    (d) In the case of a unit account for a new unit, a compliance 
subaccount;
    (e) In the case of a general account, a current year subaccount;
    (f) Future year subaccounts for each of the 30 calendar years 
following the later of 1995 or the current calendar year;
    (g) In the case of a unit account, the current total of sulfur 
dioxide emissions in tons for the current calendar year as reported to 
date pursuant to part 75 of this chapter.

[58 FR 3687, Jan. 11, 1993; 58 FR 40747, July 30, 1993]



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) Authorized account representative identification. The 
Administrator will assign a unique identifying number to each authorized 
account representative or alternate authorized account representative 
identified pursuant to Sec. 73.31(c).
    (c) Notification of parties subject to the binding agreement. The 
authorized account representative for a general account shall notify, in 
writing, all persons who have an ownership interest with respect to the 
allowances held in the account of any Acid Rain Program submission 
required by this part or in a procedure under part 78 of this chapter, 
by the date of submission. Each person who has an ownership interest 
with respect to the allowances held in the account may expressly waive 
his or her right to receive such notification.
    (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 action, representation or failure to act by the alternate 
authorized account representative when acting in that capacity shall be 
deemed to be an

[[Page 159]]

action 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 actions 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 
submission to the Administrator by the authorized account representative 
shall affect the recordation of transfers submitted by 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.



Sec. 73.34  Recordation in accounts.

    (a) Recordation in compliance subaccounts. At the beginning of 1995 
and, in the case of each year thereafter, after the Administrator has 
made all deductions from an affected unit's compliance subaccount 
pursuant to Sec. 73.35(b), the Administrator will record in the 
compliance subaccount the allowances held in the future year subaccount 
for the year corresponding to the current calendar year. The future year 
subaccount for the new 30th year will be established at the same time 
and include the allowances allocated for the unit for that year pursuant 
to subpart B of this part.
    (b) Recordation in current year subaccounts. At the beginning of 
1995 and each year thereafter, the Administrator will record in the 
current year subaccount the allowances held in the future year 
subaccount for the year corresponding to the current calendar year.
    (c) Recordation in subaccounts. Allowances in each compliance, 
current year, and future year 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 Secs. 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 Secs. 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]



Sec. 73.35  Compliance.

    (a) Allowance transfer deadline. No allowance shall be deducted for 
purposes of compliance with an affected unit'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 unit's SO2 emissions occurred; and
    (2) Such allowance is:
    (i) Recorded in the unit's compliance subaccount; or
    (ii) Transferred to the unit's compliance subaccount, with the 
transfer submitted correctly pursuant to subpart D of this part for 
recordation in the compliance subaccount for the unit by not

[[Page 160]]

later than the allowance transfer deadline in the calendar year 
following the year for which compliance is being established; or
    (iii) Held in the compliance subaccount of another affected unit at 
the same source in accordance with paragraph (b)(3) of this section.
    (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 subaccount pursuant to 
paragraph (a) of this section and subpart D of this part, the 
Administrator will deduct allowances from each affected unit's 
compliance subaccount 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 remain in the compliance subaccount.
    (3)(i) If, after the Administrator completes the deductions under 
paragraph (b)(2) of this section for all affected units at the same 
source, a unit would otherwise have excess emissions and one or more 
other affected units at the source would otherwise have unused 
allowances in their compliance subaccounts and available for such other 
units under paragraph (a)(1) and (a)(2)(i) and (ii) of this section for 
the year for which compliance is being established, the Administrator 
will notify in writing the authorized account representative. The 
Administrator will state that the authorized account representative may 
specify in writing which of such allowances to deduct up to the amount 
calculated as follows, in order to reduce the tons of excess emissions 
otherwise at the unit:

Maximum deduction from other units = 0.95  x  Excess emissions if no 
    deduction from other units

    Where:
``Maximum deduction from other units'' is the maximum number of 
allowances that may be deducted for the year for which compliance is 
being established, for the unit otherwise having excess emissions, from 
the compliance subaccounts of other units at the same source, rounded to 
the nearest allowance.
``Excess emissions if no deduction from other units'' is the tons of 
excess emissions that the unit would otherwise have if no allowances 
were deducted for the unit from other units under this paragraph 
(b)(3)(i) or paragraph (b)(3)(ii) of this section.

    (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 (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. By no later 
than sixty days after the end of the calendar year, the authorized 
account representative for each unit account may identify by serial 
number the allowances to be deducted from the compliance subaccount for 
purposes of compliance with the unit's sulfur dioxide emissions 
limitation requirements. Such identification shall be made pursuant to 
part 72 of this chapter.
    (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 unit

[[Page 161]]

and recorded in its compliance subaccount. Following the deduction of 
all originally allocated allowances from the compliance subaccount, the 
Administrator will deduct those allowances that were transferred and 
recorded in the unit's compliance subaccount 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 unit with excess emissions for the preceding calendar year in an 
amount equal to the unit's excess emissions tonnage.
    (e) Deductions for units sharing a common emission stack. In the 
case of units sharing a common emission stack and have emissions that 
are not individually monitored pursuant to part 75 of this chapter, the 
authorized account representative may identify the percentage of 
allowances to be deducted from each unit's compliance subaccount. Such 
identification shall be made pursuant to part 72, subpart I of this 
chapter. In the absence of an identification, the Administrator will 
deduct an equal percentage of allowances from each unit's compliance 
subaccount.

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



Sec. 73.36  Banking.

    (a) Unit accounts. Any allowance in a compliance subaccount not 
deducted pursuant to Sec. 73.35 will remain in the compliance 
subaccount.
    (b) General accounts. In the case of a general account, any 
allowances in the current year subaccount at the end of the current 
calendar year will remain in the current year subaccount.



Sec. 73.37  Account error and dispute resolution.

    (a) Claim of error. The authorized account representative may notify 
the Administrator of any claim that the Administrator made an error in 
recording transfer information that was submitted correctly pursuant to 
subpart D of this part, provided that such claim of error notification 
is submitted to the Administrator by no later than 15 business days 
following the date mark of the notification by the Administrator 
pursuant to actions taken under Sec. 73.37(d) or Sec. 73.53. Such claim 
of error notification shall be in writing and shall include:
    (1) A description of the error alleged to have been made by the 
Administrator;
    (2) A proposed correction of the alleged error;
    (3) Any supporting documentation or other information concerning the 
alleged error and proposed correction; and
    (4) Certification by the signature of and the date of the signature 
of the authorized account representative.

The Administrator will not act on claim of error notifications received 
after the stated deadlines (except as provided under paragraph (f) of 
this section, or that do not contend that the Administrator made an 
error in recordation.
    (b) EPA action. The Administrator, at the Administrator's sole 
discretion based on documentation provided, will determine what changes, 
if any, will be made to the accounts subject to the alleged error. Not 
later than 20 business days after receipt of a claim of error 
notification pursuant to paragraph (a) of this section, the 
Administrator will submit to the authorized account representative a 
written response stating:
    (1) The determination made and any action taken by, the 
Administrator; and
    (2) The reasons for such action.
    (c) Administrative appeals procedure. Following the Administrator's 
action pursuant to paragraph (b) of this section, the authorized account 
representative may appeal the Administrator's action through the 
administrative appeals procedure pursuant to part 78 of this chapter.
    (d) EPA corrections. The Administrator may, without prior notice of 
a claim of error and in the Administrator's sole discretion, correct any 
errors in any account on his or her own motion. The Administrator will 
notify the authorized account representative by no later than 20 
business days following any such corrections.

[[Page 162]]

    (e) Excess emissions requirements. The filing of a claim of error 
notification pursuant to paragraph (a) of this section, or the pendency 
of the Administrator's action pursuant to paragraph (b) of this section, 
shall not affect a unit's obligations under part 77 of this chapter.
    (f) Waiver of deadline. The Administrator may, in his or her 
discretion, accept claim of error submissions made following the 
deadlines imposed in this section upon a demonstration by the authorized 
account representative of good cause for the delay. The finding of 
whether good cause exists shall be in the sole discretion of the 
Administrator. Appeals of a decision by the Administrator under this 
paragraph will be addressed pursuant to the administrative appeals 
process in part 78 of this chapter.



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 delete the general account from the 
Allowance Tracking System.
    (b) Inactive accounts. If a general account shows no activity for a 
period of a year or more and does not contain any allowances in its 
subaccounts, the Administrator will notify the account's authorized 
account representative that the account will be closed and eliminated 
from the Allowance Tracking System 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. The finding of whether good cause exists 
shall be in the sole discretion of the Administrator.



                     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, including, but not limited 
to, transfers of an allowance to and from contemporaneous future year 
subaccounts, and transfers of an allowance to and from compliance 
subaccounts and current year subaccounts, and transfers of all 
allowances allocated for a unit for each calendar year, in perpetuity.
    (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, or correct indication on the allowance transfer where a 
request involves the transfer of the unit's allowances in perpetuity;
    (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

[[Page 163]]

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 Allowance Tracking System account listed herein, 
except that I do not waive any remedies under 40 CFR part 73, or any 
other 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.''
    (3) Transfers of allowances to or from compliance subaccounts 
submitted for recordation following the allowance transfer deadline will 
not be recorded until after completion of the process of recordation set 
forth in Sec. 73.34(a).

[58 FR 3694, Jan. 11, 1993, as amended at 63 FR 68404, Dec. 11, 1998]



Sec. 73.51  Prohibition.

    Except as provided in Sec. 73.34(a), the Administrator will not 
record a transfer of allowances from a future year subaccount to a 
subaccount for an earlier year.



Sec. 73.52  EPA recordation.

    (a) General recordation. Except as provided in Sec. 73.50, 
Sec. 73.51, and this paragraph (a), the Administrator will record an 
allowance transfer by no later than five business days 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 information submitted pursuant to Sec. 73.50 is complete;
    (2) The transferror account includes each allowance identified by 
serial number in the allowance transfer request submitted pursuant to 
Sec. 73.50, except when a request for transfer of the unit's allowances 
in perpetuity is indicated correctly on the allowance transfer 
submission;
    (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; and
    (4) The transfer meets all applicable requirements of this subpart.
    (b) Where an allowance transfer submitted for recordation fails to 
meet the requirements of this subpart, the Administrator will not record 
such transfer.

[58 FR 3694, Jan. 11, 1993, as amended at 60 FR 17114, Apr. 4, 1995]



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

[[Page 164]]

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 a  100,000 b
1994.....................................  50,000 a  100,000 b  25,000 c
1995.....................................  50,000 a  100,000 b  25,000 c
1996.....................................   150,000  100,000 b  25,000 c
1997.....................................   150,000  125,000 b  25,000 c
1998.....................................   150,000  125,000 b
1999.....................................   150,000  125,000 b
2000 and after...........................   125,000  125,000 b
------------------------------------------------------------------------
a Not usable until 1995.
b Not usable until 7 years after purchase.
c Not usable until 6 years after purchase.
*These are unsold advance allowances from the direct sale program for
  1993, 1994, 1995, and 1996 respectively.


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

[[Page 165]]

    (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. The Administrator will announce the results of each auction 
through the Allowance Tracking System. The results will also be 
published in the Federal Register and in the Commerce Business Daily.
    (f) Transfer of allowances. Allowances will be transferred from the 
Auction Subaccount and from the subaccount for allowances offered by 
authorized account representatives to the Allowance Tracking System 
accounts of successful bidders as soon as payment is collected by the 
Administrator.
    (g) Return of unsuccessful bids. The Administrator will return 
payment to unsuccessful bidders and to bidders unwilling to purchase 
fewer allowances than requested following the conclusion of each 
auction.
    (h) Transfer of proceeds. The Administrator will return all proceeds 
from the auction as follows:
    (1) Allowances auctioned from the Auction Subaccount. Not later than 
90 days following each auction, the Administrator will pay a pro rata 
share of the proceeds of each auction to the authorized account 
representative of each unit from whose annual allowance allocation 
allowances were withheld for the purposes of establishing the Auction 
Subaccount. Each unit's pro rata share will be calculated pursuant to 
regulations to be promulgated under subpart B.
    (2) Allowances contributed from others. Not later than 90 days 
following each auction, the Administrator will transfer the full amount 
of the proceeds of each sale of allowances offered by authorized account 
representatives to such representatives. Proceeds from the sale of 
allowances that were offered with the same specified minimum price will 
be distributed according to each such offeror's pro rata share of the 
sale of such allowances.
    (3) The Administrator will pay no interest on any payment made 
pursuant to paragraphs (h) (1) and (2) of this section.
    (i) Return of unsold allowances. The Administrator will return all 
unsold allowances from the auction as follows:
    (1) Allowances in the Auction Subaccount. At the conclusion of each 
auction, the Administrator will transfer to the Allowance Tracking 
System account of each 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]

[[Page 166]]



Sec. 73.71  Bidding.

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



Sec. 73.72  Direct sales.

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

[61 FR 28763, June 6, 1996]



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

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

[[Page 167]]



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

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


(Allowances will be rounded to the nearest allowance)

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



Sec. 73.81  Qualified conservation measures and renewable energy generation.

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

[[Page 168]]

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

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



Sec. 73.82  Application for allowances from reserve program.

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

[[Page 169]]

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

[[Page 170]]

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

[[Page 171]]

for any calendar year shall be equal to the product of:
[GRAPHIC] [TIFF OMITTED] TC10NO91.006

                      (Rounded to the nearest ton)

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

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



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

[[Page 172]]

application as necessary for the Secretary to make a determination that 
the applicant meets the requirements of Sec. 73.28(a)(9) and (b). 
Additional information or revised applications will be processed 
according to the date of receipt of such information or revisions.
    (c) Notification of approval. The Secretary of Energy will review 
the net income neutrality application to determine whether it meets the 
requirements of Sec. 73.82 (a)(9) and (b) and will certify this finding 
in writing to the applicant and to the Administrator within 60 calendar 
days of receipt of the net income neutrality application or a revised 
application, except that the Secretary may specify a later date for 
certification.



Sec. 73.84  Administrator's action on applications.

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

[[Page 173]]

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



Sec. 73.85  Administrator review of the reserve program.

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

[[Page 174]]

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

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

    The following listed measures are approved as ``qualified energy 
conservation measures'' for purposes of the Conservation and Renewable 
Energy Reserve Program or reduced utilization qualified energy 
conservation plans under Sec. 72.43 of this chapter. Measures not 
appearing on the list may also be qualified conservation measures if 
they meet the requirements specified in Sec. 73.81(a) of this part.
1.1  Residential
1.1.1  Space Conditioning
     Electric furnace improvements (intermittent ignition, 
automatic vent dampers, and heating element change-outs)
     Air conditioner (central and room) upgrades/replacements
     Heat pump (ground source, solar assisted, and conventional) 
upgrades/replacements
     Cycling of air conditioners and heat pumps
     Natural ventilation
     Heat recovery ventilation
     Clock thermostats
     Setback thermostats
     Geothermal steam direct use
     Improved equipment controls
     Solar assisted space conditioning (ventilation, air-
conditioning, and desiccant cooling)
     Passive solar designs
     Air conditioner and heat pump clean and tune-up
     Heat pipes
     Whole house fans
     High efficiency fans and motors
     Hydronic pump insulation
     Register relocation
     Register size and blade configuration
     Return air location
     Duct sizing
     Duct insulation
     Duct sealing
     Duct cleaning
     Shade tree planting
1.1.2  Water Heating
     Electric water heater upgrades/replacements
     Electric water heater tank wraps/blankets
     Low-flow showerheads and fittings
     Solar heating and pre-heat units
     Geothermal heating and pre-heat units
     Heat traps
     Water heater heat pumps
     Recirculation pumps
     Setback thermostats
     Water heater cycling control
     Solar heating for swimming pools
     Pipe wrap insulation
1.1.3  Lighting
     Lamp replacement
     Dimmers
     Motion detectors and occupancy sensors
     Photovoltaic lighting
     Fixture replacement
     Outdoor lighting controls
1.1.4  Building Envelope
     Attic, basement, ceiling, and wall insulation
     Passive solar building systems
     Exterior roof insulation
     Exterior wall insulation
     Exterior wall insulation bordering unheated space (e.g., a 
garage)
     Knee wall insulation in attic
     Floor insulation
     Perimeter insulation
     Storm windows/doors
     Caulking/weatherstripping
     Multi-glazed inserts for sliding glass doors
     Sliding door replacements
     Installation of French doors
     Hollow core door replacement
     Radiant barriers
     Window vent conversions
     Window replacement
     Window shade screens
     Low-e windows
     Window reduction
     Attic ventilation
     Whole house fan
     Passive solar design
1.1.5  Other Appliances
     Refrigerator replacements
     Freezer replacements
     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

[[Page 175]]

     Automatic economizer cooling
     Outside air control
     Hot and cold deck automatic reset
     Reheat system primary air optimization
     Process heat recovery
     Deadband thermostat
     Timeclocks on circulating pumps
     Chiller system
     Increase condensing unit efficiency
     Separate make-up air for exhaust hoods
     Variable air volume system
     Direct tower cooling (chiller strainer cycle)
     Multiple chiller control
     Radiant heating
     Evaporative roof surface cooling
     Cooling tower flow control
     Ceiling fans
     Evaporative cooling
     Direct expansion cooling system
     Heat recovery ventilation (water and air-source)
     Set-back controls for heating/cooling
     Make-up air control
     Manual fan switches
     Energy saving exhaust hood
     Night flushing
     Spot radiant heating
     Terminal regulated air volume control scheme
     Variable speed motors for HVAC system
     Waterside economizers
     Airside economizer
     Gray water systems
     Well water for cooling
1.2.2  Building envelope
     Insulation
     Wall insulation
     Floor/slab insulation
     Roof insulation
     Window and door upgrades, replacements, and films (to 
reduce solar heat gains)
     Passive solar design
     Earth berming
     Shading devices and tree planting
     High reflectivity roof coating
     Evaporative cooling
     Infiltration reduction
     Weatherstripping
     Caulking
     Low-e windows
     Multi-glazed windows
     Replace glazing with insulated walls
     Thermal break window frames
     Tinted glazing
     Vapor barrier
     Vestibule entry
1.2.3  Lighting
     Electronic ballast replacements
     Delamping
     Reflectors
     Occupancy sensors
     Daylighting with controls
     Photovoltaic lighting
     Efficient exterior lighting
     Manual selective switching
     Efficient exit signs
     Daylighting construction
     Cathode cutout ballasts
     High intensity discharge luminaries
     Outdoor light timeclock and photocell
1.2.4  Refrigeration
     Refrigerator replacement
     Freezer replacement
     Optimize heat gains to refrigerated space
     Optimize defrost control
     Refrigeration pressure optimization control
     High efficiency compressors
     Anti-condensate heater control
     Floating head pressure
     Hot gas defrost
     Parallel unequal compressors
     Variable speed compressors
     Water cooler controls
     Waste heat utilization
     Air doors on refrigeration equipment
1.2.5  Water Heating
     Electric water heating upgrades/replacements
     Electric water heater wraps/blankets
     Pipe insulation
     Solar heating and/or pre-heat units
     Geothermal heating and/or pre-heat units
     Circulating pump control
     Point-of-use water heater
     Heat recovery domestic water heater (DWH) system
     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

[[Page 176]]

     Delamping
     Photovoltaic lighting
     Two step and dimmable high intensity discharge ballast
1.3.3  Heating/Ventilation/Air Conditioning (HVAC)
     Heat pump replacement/upgrade
     Furnace upgrade/replacement
     Fan motor efficiency
     Resizing of chillers
     Heat pipe retrofits on air conditioners
     Variable speed drive on fan motor
     Solar assisted HVAC including ventilation, chillers, heat 
pumps and desiccants
1.3.4  Industrial Processes
     Upgrades in heat transfer equipment
     Insulation and burner upgrades for industrial furnaces/
ovens/boilers to reduce electricity loads on motors and fans
     Insulation and redesign of piping
     Upgrades/retrofits in condenser/evaporation equipment
     Process air and water filtration for improved efficiency
     Upgrades of catalytic combustors
     Solar process heat
     Customer located power based on photovoltaic, solar 
thermal, biomass, wind, and geothermal resources
     Power factor controllers
     Utilization of waste gas fuels
     Steam line and steam trap repairs/upgrades
     Compressed air system improvements/repairs
     Industrial process heat pump
     Optimization of equipment lubrication or maintenance
     Resizing of process equipment for optimal energy efficiency
     Use of unique thermodynamic power cycles
1.3.5  Building Envelope
     Insulation of ceiling, walls, and ducts
     Window and door replacement/upgrade, including thermal 
energy barriers
     Caulking/weatherstripping
1.3.6  Water Heating
     Electric water heater upgrades/replacements
     Electric water heater wraps/blankets
     Pipe insulation
     Low-flow showerheads and fittings
     Solar heating and pre-heat units
     Geothermal heating and pre-heat units
1.3.7  Other End-uses and miscellaneous
     Refrigeration system retrofit/replacement
     Energy management control systems and end use metering
     Customer-owned transformer retrofits/replacements and 
proper sizing
1.4  Agricultural
1.4.1  Space Conditioning
     Building envelope measures
     Efficient HVAC equipment
     Heat pipe retrofit on air conditioners
     System and control measures
     Solar assisted HVAC including ventilation, chillers, heat 
pumps, and desiccants
     Air-source and geothermal heat pumps replacement/upgrades
1.4.2  Water heating
     Upgrades/replacements
     Water heater wraps/blankets
     Pipe insulation
     Low-flow showerheads and fittings
     Solart heating and/or pre-hear units
     Geothermal heating and/or pre-heat units
1.4.3  Lighting
     Electronic ballast replacements
     Delamping
     Reflectors
     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
11.4.6  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

[[Page 177]]

     District heating and cooling measures derived for 
cogeneration that result in electricity savings

       2. Supply-side Measures Applicable for Reduced Utilization

    Supply-side measures that may be approved for purposes of reduced 
utilization plans under Sec. 72.43 include the following:
2.1  Generation efficiency
     Heat rate improvement programs
     Availability improvement programs
     Coal cleaning measures that improve boiler efficiency
     Turbine improvements
     Boiler improvements
     Control improvements, including artificial intelligence and 
expert systems
     Distributed control--local (real-time) versus central 
(delayed)
     Equipment monitoring
     Performance monitoring
     Preventive maintenance
     Additional or improved heat recovery
     Sliding/variable pressure operations
     Adjustable speed drives
     Improved personnel training to improve man/machine 
interface
2.2  Transmission and distribution efficiency
     High efficiency transformer switchouts using amorphous core 
and silicon steel technologies
     Low-loss windings
     Innovative cable insulation
     Reactive power dispatch optimization
     Power factor control
     Primary feeder reconfiguration
     Primary distribution voltage upgrades
     High efficiency substation transformers
     Controllable series capacitors
     Real-time distribution data acquisition analysis and 
control systems
     Conservation voltage regulation

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

    The following listed measures are approved as ``qualified renewable 
energy generation'' for purposes of the Conservation and Renewable 
Energy Reserve Program. Measures not appearing on the list may also be 
qualified renewable energy generation measures if they meet the 
requirements specified in Sec. 73.81.
3.1  Biomass resources
     Combustible energy-producing materials from biological 
sources which include: wood, plant residues, biological wastes, landfill 
gas, energy crops, and eligible components of municipal solid waste.
3.2  Solar resources
     Solar thermal systems and the non-fossil fuel portion of 
solar thermal hybrid systems
     Grid and non-grid connected photovoltaic systems, including 
systems added for voltage or capacity augmentation of a distribution 
grid.
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

[[Page 178]]

Form 810 for October, November and December 1993;
    (iii) For calendar years 1994 through 1999, inclusive, photocopies 
of Form 810 for each month in the respective calendar year.
    (3) For joint ventures, each eligible refinery shall submit a 
separate application under paragraph (b)(2) of this section. Each 
application must include the diesel fuel throughput applicable to the 
joint agreement and the requested distribution of allowances that would 
be allocated to the joint agreement. If the applications for refineries 
involved in the joint agreement are inconsistent as to the throughput of 
diesel fuel applicable to the joint agreement or as to the distribution 
of the allowances, all involved applications will be considered void for 
purposes of the joint agreement.
    (4) The certifying official shall submit all requests for allowances 
by April 1 of the calendar year following the year in which the diesel 
fuel was desulfurized to the Director, Acid Rain Division, under the 
procedures set forth in Sec. 73.13 of this part.
    (c) Allowance allocation. The Administrator will allocate allowances 
to the eligible refinery upon satisfactory submittal of information 
under paragraphs (a) and (b) of this section in the amount calculated 
according to the following equations. Such allowances will be allocated 
to the refinery's non-unit subaccount for the calendar year in which the 
application is made.
    (1) Allowances allocated under this section to any eligible refinery 
will be limited to the tons of SO2 attributable to the 
desulfurization of diesel fuel at the refinery. (2) The refinery will be 
allocated allowances for a calendar year and, in the case of 1993, for 
the period October 1 through December 31, calculated according to the 
following equation, but not to exceed 1500 for any calendar year:
[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


[[Page 179]]



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



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




                    Subpart A--Background and Summary

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

                    Subpart B--Permitting Procedures

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

        Subpart C--Allowance Calculations for Combustion Sources

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

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

  Subpart E--Allowance Tracking and Transfer and End of Year Compliance

74.40  Establishment of opt-in source allowance accounts.
74.41  Identifying allowances.
74.42  Prohibition on future year 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, Sec. 72.8 or 
Sec. 72.14 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]

[[Page 180]]



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

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



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.
    (c)(1) Notwithstanding paragraph (b) of this section, a certifying 
official of a combustion or process source that is located at the same 
source as one or more affected utility units and that, on the date on 
which an initial opt-in permit application is submitted for such 
combustion or process source and thereafter, does not serve a generator 
that produces electricity for sale may elect to designate, for such 
combustion or process source, a different designated representative than 
the designated representative for the affected utility units.
    (2) In order to make such an election, the certifying official shall 
submit to the Administrator, in a format prescribed by the 
Administrator: a certification that the combustion or process source for 
which the election is made meets each of the requirements for election 
in paragraph (c)(1) of this section; and a certificate of representation 
for the designated representative of the combustion or process source in 
accordance with Sec. 72.24 of this chapter. The Administrator will rely 
on such certificate of representation in accordance with Sec. 72.25 of 
this chapter, unless the Administrator determines that the requirements 
for election in paragraph (c)(1) of this section are not met. If, after 
the election is made, the requirements for election in paragraph (c)(1) 
of this section are no longer met, the election shall automatically 
terminate on the first date on which the requirements are no longer met 
and, within 30

[[Page 181]]

days of that date, a certificate of representation for the designated 
representative of the combustion or process source shall be submitted 
consistent with paragraph (b) of this section.

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



                    Subpart B--Permitting Procedures



Sec. 74.10  Roles--EPA and permitting authority.

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

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



Sec. 74.12  Opt-in permit contents.

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

[[Page 182]]

years and may be renewed in accordance with Sec. 74.19; provided
    (1) If an opt-in permit is issued prior to January 1, 2000, then the 
opt-in permit may, at the option of the permitting authority, expire on 
December 31, 1999; and
    (2) If an affected unit with an Acid Rain permit is located at the 
same source as the combustion source, the combustion source's opt-in 
permit may, at the option of the permitting authority, expire on the 
same date as the affected unit's Acid Rain permit expires.



Sec. 74.14  Opt-in permit process.

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

[[Page 183]]

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

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



Sec. 74.16  Application requirements for combustion sources.

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

[[Page 184]]

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. The Administrator will close the opt-in source's unit account and 
transfer any remaining allowances to a new general account as specified 
under Sec. 74.46(b)(2).
    (e) Opt-in source's prior violations. An opt-in source that 
withdraws from the Acid Rain Program shall comply with all requirements 
under the Acid Rain Program concerning all years for which the opt-in 
source was an affected unit, even if such requirements arise, or must be 
complied with after the withdrawal takes effect.
    (f) Notification. (1) After the requirements for withdrawal under 
paragraphs (b) and (c) of this section are met and after the 
Administrator's action on withdrawal under paragraph (d) of this section 
is complete, the Administrator will issue a notification to the 
permitting authority and the designated representative of the opt-in 
source of the acceptance of the opt-in source's request to withdraw.
    (2) If the requirements for withdrawal under paragraphs (b) and (c) 
of this section are not met or the Administrator's action under 
paragraph (d) of this section cannot be completed, the Administrator 
will issue a notification to the permitting authority and the designated 
representative of the opt-in source that the opt-in source's request to 
withdraw is denied. If the opt-in source's request to withdraw is 
denied, the opt-in source shall remain in the Opt-in Program and shall 
remain subject to the requirements for opt-in sources contained in this 
part.
    (g) Permit amendment. (1) After the Administrator issues a 
notification under paragraph (f)(1) of this section that the 
requirements for withdrawal have been met (including the deduction of 
the full amount of allowances as required under paragraph (d) of this 
section), the permitting authority shall amend, in accordance with 
Secs. 72.80 and 72.83 (administrative amendment) of

[[Page 185]]

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]



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

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



        Subpart C--Allowance Calculations for Combustion Sources



Sec. 74.20  Data for baseline and alternative baseline.

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

[[Page 186]]

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


where,

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

and unit conversion


= 2 for coal

= 0.001 for oil

= 1 for gas


For other fuels, the combustion source must specify unit conversion; or
    (ii) for a combustion source submitting annual data,
    [GRAPHIC] [TIFF OMITTED] TR04AP95.002
    
and unit conversion
    = 2 for coal
    = 0.001 for oil
    = 1 for gas

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

[[Page 187]]

[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 SO2 emissions rate.

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

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

where,

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

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

[[Page 188]]

[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 SO2 emissions rate.

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

                       Table 1--Factors to Convert Emission Limits to Pounds of SO2/mmBtu
----------------------------------------------------------------------------------------------------------------
                                                             Bituminous   Subbituminous   Lignite
                     Unit measurement                           coal           coal         coal         Oil
----------------------------------------------------------------------------------------------------------------
lbs Sulfur/mmBtu..........................................       2.0            2.0           2.0        2.0
% Sulfur in fuel..........................................       1.66           2.22          2.86       1.07
ppm SO2...................................................       0.00287        0.00384  .........       0.00167
ppm Sulfur in fuel........................................  ............  .............  .........       0.00334
tons SO2/hour.............................................     2 x 8760/(annual fuel consumption for specified
                                                                               year 1 x 10 3)

[[Page 189]]

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

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

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

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

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



Sec. 74.24  Current allowable SO2 emissions rate.

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

[[Page 190]]



Sec. 74.25  Current promulgated SO2 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 191]]

[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 192]]

[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 an opt-in account under paragraph (b) 
of this section, the Administrator will establish an account and 
allocate allowances in accordance with subpart C of this part for 
combustion sources or subpart D of this part for process sources. A 
separate unit account will be established for each opt-in source.
    (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 allowance account in the Allowance Tracking System to the 
Administrator.



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  Prohibition on future year transfers.

    The Administrator will not record a transfer of opt-in allowances 
allocated to opt-in sources from a future year subaccount into any other 
future year subaccount in the Allowance Tracking System.

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



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 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 in lieu 
of any annual compliance certification report required under subpart I 
of part 72 of this chapter.
    (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;

[[Page 193]]

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



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

[[Page 194]]

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:
    (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:

[[Page 195]]

[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,
[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

[[Page 196]]

[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.
    (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 opt-in source's account identification number in the 
Allowance Tracking System;
    (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;

[[Page 197]]

    (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 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.

[[Page 198]]

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


where:

``Allowances held after deduction'' shall be the amount of allowances 
held in the opt-in source's compliance subaccount 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

[[Page 199]]

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 opt-in 
source's compliance subaccount the amount of allowances that he or she 
determines is necessary to offset any increase in excess emissions or 
will return immediately to the opt-in source's compliance subaccount 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 opt-in 
source's compliance subaccount shall be calculated as follows:

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


where,

``Allowances allocated or acquired'' shall be the number of allowances 
held in the source's compliance subaccount 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).

[[Page 200]]

``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]



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 
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) After the allowance deductions under paragraph (b)(1) of this 
section are made, the Administrator will close the opt-in source's unit 
account in the Allowance Tracking System. If any allowances remain in 
the opt-in source's unit account after allowance deductions are made 
under paragraph (b)(1) of this section, and any deductions made under 
part 77 of this chapter, the Administrator will establish a general 
account for the opt-in source, and transfer any remaining allowances 
into this general account. The designated representative for the opt-in 
source shall become the authorized account representative for the 
general account.



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

[[Page 201]]

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 opt-in source's account identification number in the 
Allowance Tracking System;
    (v) Each replacement unit's account identification number in the 
Allowance Tracking System (ATS);
    (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;
    (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;

[[Page 202]]

    (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 Allowance Tracking System account of each 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 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

[[Page 203]]

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


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 unit 
account of the replacement unit to any other account in the Allowance 
Tracking System.
    (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

[[Page 204]]

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 opt-in source's account identification number in the 
Allowance Tracking System (ATS);
    (D) The account identification number in the Allowance Tracking 
System (ATS) for each 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 Allowance Tracking System 
accounts for the opt-in source and for each 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 Allowance Tracking 
System account of 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 Allowance 
Tracking System accounts for the opt-in source and for each replacement 
unit to reflect any differences between the estimated values submitted 
in the opt-in utilization report and the actual values submitted in the 
confirmation report pursuant to Sec. 74.44(c)(2).
    (3) Liability. The owners and operators of an opt-in source or a 
replacement unit governed by an approved thermal energy plan shall be 
liable for any violation of the plan or this section at that opt-in 
source or replacement unit that is governed by the thermal energy plan, 
including liability for fulfilling the obligations specified in part 77 
of this chapter and section 411 of the Act.

[60 FR 17115, Apr. 4, 1995, as amended at 63 FR 18841, 18842, Apr. 16, 
1998]



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

[[Page 205]]

from the allowances held in an opt-in source's compliance subaccount 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]



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 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 opt-in source's compliance subaccount 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 opt-in source's unit account.
    (c) Notification of deduction. When allowances are deducted, the 
Administrator will send a written notification to the authorized account 
representative of each Allowance Tracking System account from which 
allowances were deducted. The notification will state:
    (1) The serial numbers of all allowances deducted from the account,
    (2) The reason for deducting the allowances, and
    (3) The date of deduction of the allowances.
    (d) Amount of deduction. The Administrator may deduct allowances in 
accordance with paragraph (a) of this section in an amount required to 
offset any excess emissions in accordance with part 77 of this chapter 
and when an 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]

[[Page 206]]



           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 
          (SO2 and flow monitors).
75.12  Specific provisions for monitoring NOX emission rate 
          (NOX and diluent gas monitors).
75.13  Specific provisions for monitoring CO2 emissions.
75.14  Specific provisions for monitoring opacity.
75.15  Specific provisions for monitoring SO2 emissions 
          removal by qualifying Phase I technology.
75.16  Special provisions for monitoring emissions from common, by-pass, 
          and multiple stacks for SO2 emissions and heat 
          input determinations.
75.17  Specific provisions for monitoring emissions from common, by-
          pass, 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 units.

            Subpart C--Operation and Maintenance Requirements

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

             Subpart D--Missing Data Substitution Procedures

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

                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.

[[Page 207]]

75.48  Petition for an alternative monitoring system.

                  Subpart F--Recordkeeping Requirements

75.50-75.52  [Reserved]
75.53  Monitoring plan.
75.54  General recordkeeping provisions.
75.55  General recordkeeping provisions for specific situations.
75.56  Certification, quality assurance and quality control record 
          provisions.
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 submittals.
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 emission rate 
          and heat input for the purpose of calculating NOX 
          mass emissions.
75.72  Determination of NOX mass emissions.
75.73  Recordkeeping and reporting.
75.74  Annual and ozone season monitoring and reporting requirements.
75.75  Additional ozone season calculation procedures for special 
          circumstances.

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

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

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



                           Subpart A--General



Sec. 75.1  Purpose and scope.

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

[[Page 208]]

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]



Sec. 75.2  Applicability.

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

[58 FR 3701, Jan. 11, 1993, as amended at 58 FR 15716, Mar. 23, 1993; 60 
FR 26516, May 17, 1995; 63 FR 57499, Oct. 27, 1998]



Sec. 75.3  General Acid Rain Program provisions.

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

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



Sec. 75.4  Compliance dates.

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

[[Page 209]]

under an approved NO 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 
NO 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 NO and 
CO2 or excepted monitoring systems for NO 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, NO, 
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 NO 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 
NO and CO2 monitoring systems shall be January 1, 
1996; or
    (2) Not later than 90 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, NO, 
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 NO 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 
NO and CO2 monitoring systems shall be January 1, 
1996; or
    (2) Not later than 90 days after the date the unit becomes subject 
to the requirements of the Acid Rain Program, notice of which date shall 
be provided under subpart G of this part.
    (d) In accordance with Sec. 75.20, the owner or operator of an 
existing unit that is shutdown and is not yet operating by the 
applicable dates listed in paragraph (a) of this section, or an existing 
unit which has been placed in long-term cold storage after having 
previously reported emissions data in accordance with this part, 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 no later than the earlier of 45 unit operating days or 180 
calendar days after the date that the unit recommences commercial 
operation of the affected unit, notice of which date shall be provided 
under subpart G of

[[Page 210]]

this part. The owner or operator shall determine and report 
SO2 concentration, NO emission rate, CO2 
concentration, and flow data for all unit operating hours after the 
applicable compliance date in paragraph (a) of this section until all 
required certification tests are successfully completed using either:
    (1) The maximum potential concentration of SO2, the 
maximum potential NOX emission rate, as defined in section 
2.1.2.1 of appendix A to this part, 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.
    (e) In accordance with Sec. 75.20, if the owner or operator of an 
existing unit completes construction of a new stack, flue, or flue gas 
desulfurization system 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, NO, CO2, opacity, and 
volumetric flow are installed on the new stack or duct and all 
certification tests are completed not later than 90 calendar days after 
the date that emissions first exit to the atmosphere through the new 
stack, flue, or flue gas desulfurization system, notice of which date 
shall be provided under subpart G of this part. Until emissions first 
pass through the new stack, flue or flue gas desulfurization system, the 
unit is subject to the appropriate deadline in paragraph (a) of this 
section. The owner or operator shall determine and report SO2 
concentration, NO emission rate, CO2 concentration, 
and flow data for all unit operating hours after emissions first pass 
through the new stack, flue, or flue gas desulfurization system 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 a 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 by no later than the later of: 30 
unit operating days after the date that the unit first combusted that 
backup fuel after the certification testing of the primary fuel; or The 
deadline in paragraph (a) of this section. The owner or operator shall 
determine and report NO emission rate data for all unit 
operating hours that the backup fuel is combusted after the applicable 
compliance date in paragraph (a) of this section until all required 
certification tests are successfully completed using either:
    (1) The maximum potential NO emission rate; 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

[[Page 211]]

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) In accordance with Sec. 75.20, the owner or operator of a unit 
with a qualifying Phase I technology shall ensure that all certification 
tests for the inlet and outlet SO2-diluent continuous 
emission monitoring systems are completed no later than January 1, 1997 
if the unit with a qualifying Phase I technology requires the use of an 
inlet SO2-diluent continuous emission monitoring system for 
the purpose of monitoring SO2 emissions removal from January 
1, 1997 through December 31, 1999.
    (i) In accordance with Sec. 75.20, the owner or operator of each 
affected unit at which SO2 concentration is measured on a dry 
basis or at which moisture corrections are required to account for 
CO2 emissions, NOX emission rate in lb/mmBtu, heat 
input, or NOX mass emissions for units in a NOX 
mass reduction program, shall ensure that the continuous moisture 
monitoring system required by this part is installed and that all 
applicable initial certification tests required under Sec. 75.20(c)(5), 
(c)(6), or (c)(7) for the continuous moisture monitoring system are 
completed no later than the following dates:
    (1) April 1, 2000, for a unit that is existing and has commenced 
commercial operation by January 2, 2000; or
    (2) For a new affected unit which has not commenced commercial 
operation by January 2, 2000, no later than 90 days 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, no later than the earlier of 45 unit operating days or 
180 calendar days after the date that the unit recommences commercial 
operation.

[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]



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 Secs. 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 Secs. 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 Secs. 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

[[Page 212]]

    (2) The owner or operator is monitoring emissions from the unit with 
another certified monitoring system or an excepted methodology approved 
by the Administrator for use at that unit that provides emissions data 
for the same pollutant or parameter as the retired or discontinued 
monitoring system; or
    (3) The designated representative submits notification of the date 
of recertification testing of a replacement monitoring system in 
accordance with Secs. 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 Office of the Federal Register, 800 
North Capitol Street, NW, Suite 700, Washington, DC, at the Public 
Information Reference Unit of the U.S. EPA, 401 M Street, SW, 
Washington, DC and at the Library (MD-35), U.S. EPA, Research Triangle 
Park, North Carolina.
    (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 D129-91, Standard Test Method for Sulfur in Petroleum 
Products (General Bomb Method), for appendices A and D of this part.
    (2) ASTM D240-87 (Reapproved 1991), 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 D287-82 (Reapproved 1987), Standard Test Method for API 
Gravity of Crude Petroleum and Petroleum Products (Hydrometer Method), 
for appendix D of this part.
    (4) ASTM D388-92, Standard Classification of Coals by Rank, 
incorporation by reference for appendix F of this part.
    (5) ASTM D941-88, Standard Test Method for Density and Relative 
Density (Specific Gravity) of Liquids by Lipkin Bicapillary Pycnometer, 
for appendix D of this part.
    (6) ASTM D1072-90, Standard Test Method for Total Sulfur in Fuel 
Gases, for appendix D of this part.
    (7) ASTM D1217-91, Standard Test Method for Density and Relative 
Density (Specific Gravity) of Liquids by Bingham Pycnometer, for 
appendix D of this part.
    (8) ASTM D1250-80 (Reapproved 1990), Standard Guide for Petroleum 
Measurement Tables, for appendix D of this part.
    (9) ASTM D1298-85 (Reapproved 1990), Standard Practice 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 D1480-91, Standard Test Method for Density and Relative 
Density (Specific Gravity) of Viscous Materials by Bingham Pycnometer, 
for appendix D of this part.
    (11) ASTM D1481-91, 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 D1552-90, Standard Test Method for Sulfur in Petroleum 
Products (High Temperature Method), for appendices A and D of the part.
    (13) ASTM D1826-88, 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 D1945-91, Standard Test Method for Analysis of Natural Gas 
by Gas Chromatography, for appendices F and G of this part.
    (15) ASTM D1946-90, Standard Practice for Analysis of Reformed Gas 
by

[[Page 213]]

Gas Chromatography, for appendices F and G of this part.
    (16) ASTM D1989-92, Standard Test Method for Gross Calorific Value 
of Coal and Coke by Microprocessor Controlled Isoperibol Calorimeters, 
for appendix F of this part.
    (17) ASTM D2013-86, Standard Method of Preparing Coal Samples for 
Analysis, for Sec. 75.15 and appendix F of this part.
    (18) ASTM D2015-91, Standard Test Method for Gross Calorific Value 
of Coal and Coke by the Adiabatic Bomb Calorimeter, for Sec. 75.15 and 
appendices A, D and F of this part.
    (19) ASTM D2234-89, Standard Test Methods for Collection of a Gross 
Sample of Coal, for Sec. 75.15 and appendix F of this part.
    (20) ASTM D2382-88, Standard Test Method for Heat of Combustion of 
Hydrocarbon Fuels by Bomb Calorimeter (High-Precision Method), for 
appendices D and F of this part.
    (21) ASTM D2502-87, 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 D2503-82 (Reapproved 1987), Standard Test Method for 
Molecular Weight (Relative Molecular Mass) of Hydrocarbons by 
Thermoelectric Measurement of Vapor Pressure, for appendix G of this 
part.
    (23) ASTM D2622-92, Standard Test Method for Sulfur in Petroleum 
Products by X-Ray Spectrometry, for appendices A and D of this part.
    (24) ASTM D3174-89, 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, Standard Practice for Ultimate Analysis of Coal 
and Coke, for appendices A and F of this part.
    (26) ASTM D3177-89, Standard Test Methods for Total Sulfur in the 
Analysis Sample of Coal and Coke, for Sec. 75.15 and appendix A of this 
part.
    (27) ASTM D3178-89, Standard Test Methods for Carbon and Hydrogen in 
the Analysis Sample of Coal and Coke, for appendix G of this part.
    (28) ASTM D3238-90, 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 D3246-81 (Reapproved 1987), Standard Test Method for 
Sulfur in Petroleum Gas By Oxidative Microcoulometry, for appendix D of 
this part.
    (30) ASTM D3286-91a, Standard Test Method for Gross Calorific Value 
of Coal and Coke by the Isoperibol Bomb Calorimeter, for appendix F of 
this part.
    (31) ASTM D3588-91, Standard Practice for Calculating Heat Value, 
Compressibility Factor, and Relative Density (Specific Gravity) of 
Gaseous Fuels, for appendices D and F to this part.
    (32) ASTM D4052-91, Standard Test Method for Density and Relative 
Density of Liquids by Digital Density Meter, for appendix D of this 
part.
    (33) ASTM D4057-88, Standard Practice for Manual Sampling of 
Petroleum and Petroleum Products, for appendix D of this part.
    (34) ASTM D4177-82 (Reapproved 1990), Standard Practice for 
Automatic Sampling of Petroleum and Petroleum Products, for appendix D 
of this part.
    (35) ASTM D4239-85, Standard Test Methods for Sulfur in the Analysis 
Sample of Coal and Coke Using High Temperature Tube Furnace Combustion 
Methods, for Sec. 75.15 and appendix A of this part.
    (36) ASTM D4294-90, Standard Test Method for Sulfur in Petroleum 
Products by Energy-Dispersive X-Ray Fluorescence Spectroscopy, for 
appendices A and D of this part.
    (37) ASTM D4468-85 (Reapproved 1989), Standard Test Method for Total 
Sulfur in Gaseous Fuels by Hydrogenolysis and Rateometric Colorimetry, 
for appendix D of this part.
    (38) ASTM D4891-89, Standard Test Method for Heating Value of Gases 
in Natural Gas Range by Stoichiometric Combustion, for appendices D and 
F to this part.
    (39) ASTM D5291-92, Standard Test Methods for Instrumental 
Determination of Carbon, Hydrogen, and Nitrogen in Petroleum Products 
and Lubricants, for appendices F and G to this part.
    (40) ASTM D5373-93, ``Standard Methods for Instrumental 
Determination of Carbon, Hydrogen, and Nitrogen in

[[Page 214]]

Laboratory Samples of Coal and Coke,'' for appendix G to this part.
    (41) ASTM D5504-94, 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.
    (b) The following materials are available for purchase from the 
American Society of Mechanical Engineers (ASME), 22 Law Drive, Box 2350, 
Fairfield, NJ 07007-2350.
    (1) ASME MFC-3M-1989 with September 1990 Errata, Measurement of 
Fluid Flow in Pipes Using Orifice, Nozzle, and Venturi, for appendix D 
of this part.
    (2) ASME MFC-4M-1986 (Reaffirmed 1990), Measurement of Gas Flow by 
Turbine Meters, for appendix D of this part.
    (3) ASME-MFC-5M-1985, Measurement of Liquid Flow in Closed Conduits 
Using Transit-Time Ultrasonic Flowmeters, for appendix D of this part.
    (4) ASME MFC-6M-1987 with June 1987 Errata, Measurement of Fluid 
Flow in Pipes Using Vortex Flow Meters, 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 with December 1989 Errata, 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), 11 W. 42nd Street, New 
York NY 10036: 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.
    (d) The following materials are available for purchase from the 
following address: Gas Processors Association (GPA), 6526 East 60th 
Street, Tulsa, Oklahoma 74145:
    (1) GPA Standard 2172-86, 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 2261-90, Analysis for Natural Gas and Similar 
Gaseous Mixtures by Gas Chromatography, for appendices D, F, and G of 
this part.
    (e) The following materials are available for purchase from the 
following address: American Gas Association, 1515 Wilson Boulevard, 
Arlington VA 22209:
    (1) American Gas Association Report No. 3: Orifice Metering of 
Natural Gas and Other Related Hydrocarbon Fluids, Part 1: General 
Equations and Uncertainty Guidelines (October 1990 Edition), Part 2: 
Specification and Installation Requirements (February 1991 Edition) and 
Part 3: Natural Gas Applications (August 1992 Edition), for appendices D 
and E of this part.
    (2) American Gas Association Transmission Measurement Committee 
Report No. 7: Measurement of Gas by Turbine Meters (Second Revision, 
April, 1996), for appendix D to this part.
    (f) The following materials are available for purchase from the 
following address: American Petroleum Institute, Publications 
Department, 1220 L Street NW, Washington, DC 20005-4070.
    (1) American Petroleum Institute (API) Petroleum Measurement 
Standards, Chapter 3, Tank Gauging: Section 1A, Standard Practice for 
the Manual Gauging of Petroleum and Petroleum Products, December 1994; 
Section 1B, Standard Practice for Level Measurement of Liquid 
Hydrocarbons in Stationary Tanks by Automatic Tank Gauging, April 1992 
(reaffirmed January 1997); Section 2, Standard Practice for Gauging 
Petroleum and Petroleum Products in Tank Cars, September 1995; Section 
3, Standard Practice for Level Measurement of Liquid Hydrocarbons in 
Stationary Pressurized Storage Tanks by Automatic Tank Gauging, June 
1996; Section 4, Standard Practice for Level Measurement of Liquid 
Hydrocarbons on Marine Vessels by Automatic Tank Gauging, April 1995; 
and Section 5, Standard Practice for Level Measurement of Light 
Hydrocarbon Liquids Onboard Marine Vessels by Automatic Tank Gauging, 
March 1997; 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.

[[Page 215]]

    (3) American Petroleum Institute (API) Section 2, ``Conventional 
Pipe Provers,'' Section 3, ``Small Volume Provers,'' and Section 5, 
``Master-Meter Provers,'' from Chapter 4 of the Manual of Petroleum 
Measurement Standards, October 1988 (Reaffirmed 1993), 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]



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) 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 the 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 
Secs. 75.11 and 75.16 and subpart E of this part;
    (2) The owner or operator shall install, certify, operate, and 
maintain, in accordance with all the requirements of this part, a 
NOX continuous emission monitoring system (consisting of a 
NOX pollutant concentration monitor and an O2 or 
CO2 diluent gas monitor) with the 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 
Secs. 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 the automated data acquisition and handling 
system for measuring and recording CO2 concentration (in ppm 
or percent), volumetric gas flow (in scfh), and CO2 mass 
emissions (in tons/hr) discharged to the atmosphere;
    (ii) The owner or operator shall determine CO2 emissions 
based on the measured carbon content of the fuel and the procedures in 
appendix G of this part to estimate CO2 emissions (in ton/
day) discharged to the atmosphere; or
    (iii) The owner or operator shall install, certify, operate, and 
maintain, in accordance with all the requirements of this part, a flow 
monitoring system and a CO2 continuous emission monitoring 
system using an O2 concentration monitor in order to 
determine CO2 emissions using the procedures in appendix F of 
this part with the 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; and
    (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 
Secs. 75.14 and 75.18.
    (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

[[Page 216]]

appropriate units of measurement (i.e., lb/hr for SO2 and lb/
mmBtu for NOx).
    (c) Heat Input Measurement Requirement. The owner or operator shall 
determine and record the heat input 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 and component thereof 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, SO2 emission rate in lb/mmBtu 
(if applicable), CO2 concentration, O2 
concentration, CO2 mass emissions (if applicable), 
NOX concentration, and NOX emission rate data 
collected by the monitors to hourly averages. Hourly averages shall be 
computed using at least one data point in each fifteen minute quadrant 
of an hour, where the unit combusted fuel during that quadrant of an 
hour. Notwithstanding this requirement, an hourly average may be 
computed from at least two data points separated by a minimum of 15 
minutes (where the unit operates for more than one quadrant of an hour) 
if data are unavailable as a result of the performance of calibration, 
quality assurance, or preventive maintenance activities pursuant to 
Sec. 75.21 and appendix B of this part, 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 
pollutant concentration monitor, flow monitor, or NOX 
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. An hourly 
average NOX or SO2 emission rate in lb/mmBtu is 
valid only if the minimum number of data points is acquired by both the 
pollutant concentration monitor (NOX or SO2) 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. 
Except for SO2 emission rate

[[Page 217]]

data in lb/mmBtu, 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 monitoring system 
and component thereof 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.

[58 FR 3701, Jan. 11, 1993, as amended at 60 FR 26519, May 17, 1995; 64 
FR 28590, May 26, 1999]



Sec. 75.11  Specific provisions for monitoring SO2 emissions (SO2 and flow monitors).

    (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; 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 
psychometric 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

[[Page 218]]

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
    (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).
    (e) Units with SO2 continuous emission monitoring systems 
during the combustion of gaseous fuel. The owner or operator of an 
affected unit with an SO2 continuous emission monitoring 
system shall, during any hour in which the unit combusts only gaseous 
fuel, determine SO2 emissions in accordance with paragraph 
(e)(1), (e)(2) or (e)(3) of this section, as applicable.
    (1) If the gaseous fuel meets the definition of ``pipeline natural 
gas'' or ``natural gas'' in Sec. 72.2 of this chapter, the owner or 
operator may, in lieu of operating and recording data from the 
SO2 monitoring system, 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 a certified flow monitoring 
system and a certified diluent monitor, in conjunction with the 
appropriate default SO2 emission rate from section 2.3.1.1 or 
2.3.2.1.1 of appendix D to this part, and Equation D-5 in 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.
    (2) The owner or operator may, in lieu of operating and recording 
data from the SO2 monitoring system, determine SO2 
emissions by certifying an

[[Page 219]]

excepted monitoring system in accordance with Sec. 75.20 and appendix D 
to this part, following the applicable fuel sampling and analysis 
procedures in section 2.3 of appendix D to this part, meeting the 
recordkeeping requirements of Sec. 75.55 or Sec. 75.58, as applicable, 
and meeting all quality control and quality assurance requirements for 
fuel flowmeters in appendix D to this part. If this compliance option is 
selected, the hourly unit heat input reported under Sec. 75.54(b)(5) or 
Sec. 75.57(b)(5), as applicable, shall be determined using a certified 
flow monitoring system and a certified diluent monitor, in accordance 
with the procedures in section 5.2 of appendix F to this part. The flow 
monitor and diluent monitor shall meet all of the applicable quality 
control and quality assurance requirements of appendix B to this part.
    (3) The owner or operator may determine SO2 mass 
emissions by using a certified SO2 continuous monitoring 
system, in conjunction with a certified flow rate monitoring system. 
However, if the unit burns any gaseous fuel that is very low sulfur fuel 
(as defined in Sec. 72.2 of this chapter), then on and after April 1, 
2000, the SO2 monitoring system shall be subject to the 
following quality assurance provisions when the very low sulfur fuel is 
combusted. Prior to April 1, 2000, the owner or operator may comply with 
these provisions.
    (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  ppm, whichever 
is less restrictive).
    (iii) Any hourly average SO2 concentration of less than 
2.0 ppm recorded by the SO2 monitoring system shall be 
adjusted to a default value of 2.0 ppm, for reporting purposes. Such 
adjusted hourly averages shall be considered to be quality-assured data, 
provided that the monitoring system is operating and is not out-of-
control with respect to any of the quality assurance tests required by 
appendix B of this part (i.e., daily calibration error, linearity and 
relative accuracy test audit).
    (iv) In accordance with the requirements of section 2.1.1.2 of 
appendix A to this part, for units that sometimes burn gaseous fuel that 
is very low sulfur fuel (as defined in Sec. 72.2 of this chapter) and at 
other times burn higher sulfur fuel(s) such as coal or oil, a second 
low-scale SO2 measurement range is not required when the very 
low sulfur gaseous fuel is combusted. For units that burn only gaseous 
fuel that is very low sulfur fuel and burn no other type(s) of fuel(s), 
the owner or operator shall set the span of the SO2 
monitoring system to a value no greater than 200 ppm.
    (f) Other units. The owner or operator of an affected unit that 
combusts wood, refuse, or other material in addition to oil or gas shall 
comply with the monitoring provisions for coal-fired units specified in 
paragraph (a) of this section.

[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]



Sec. 75.12  Specific provisions for monitoring NOX emission rate (NOX and diluent gas monitors).

    (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 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 continuous emission 
monitoring system may measure either O2 or CO2 
concentration in the flue gases.

[[Page 220]]

    (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; 
and 15.0% for wood.
    (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 continuous emission monitoring system no later than 
December 31 of the following calendar year.
    (e) Low mass emissions units. Notwithstanding the requirements of 
paragraphs (a) and (c) 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).
    (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]



Sec. 75.13  Specific provisions for monitoring CO2 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 Secs. 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.''

[[Page 221]]

    (b) Determination of CO2 emissions using appendix G of 
this part. If the owner or operator chooses to use the appendix G 
method, then the owner or operator may provide information satisfactory 
to the Administrator 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 may 
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, a continuous moisture 
monitoring system, as specified in Sec. 75.11(b)(2), or a fuel-specific 
default moisture percentage (if applicable), as defined in 
Sec. 75.11(b)(1), and by using the methods and procedures specified in 
appendix F to this part. For units using a common stack, multiple stack, 
or bypass stack, the owner or operator may use the provisions of 
Sec. 75.16, except that the phrase ``CO2 continuous emission 
monitoring system'' shall apply rather than ``SO2 continuous 
emission monitoring system,'' the term ``maximum potential concentration 
of CO2'' shall apply rather than ``maximum potential 
concentration of SO2,'' and the phrase ``CO2 mass 
emissions'' shall apply rather than ``SO2 mass emissions.''
    (d) Determination of CO2 mass emissions from low mass 
emissions units. The owner or operator of a unit that qualifies as a low 
mass emissions unit under Sec. 75.19(a) and (b) shall comply with one of 
the following:
    (1) Meet the general operating requirements in Sec. 75.10 for a 
CO2 continuous emission monitoring system and flow monitoring 
system;
    (2) Meet the requirements specified in paragraph (b) or (c) of this 
section for use of the methods in appendix G or F to this part, 
respectively; or
    (3) Use the low mass emissions excepted methodology in Sec. 75.19(c) 
for estimating hourly CO2 mass emissions, if applicable under 
Sec. 75.19(a) and (b).

[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]



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

[[Page 222]]

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.

[58 FR 3701, Jan. 11, 1993, as amended at 61 FR 25581, May 22, 1996]



Sec. 75.15  Specific provisions for monitoring SO2 emissions removal by qualifying Phase I technology.

    (a) Additional monitoring provisions. In addition to the 
SO2 monitoring requirements in Sec. 75.11 or Sec. 75.16, for 
the purposes of adequately monitoring SO2 emissions removal 
by qualifying Phase I technology operated pursuant to Sec. 72.42 of this 
chapter, the owner or operator shall, except where specified below, use 
both an inlet SO2-diluent continuous emission monitoring 
system and an outlet SO2-diluent continuous emission 
monitoring system, consisting of an SO2 pollutant 
concentration monitor and a diluent CO2 or O2 
monitor. (The outlet SO2-diluent continuous emission 
monitoring system may consist of the same SO2 pollutant 
concentration monitor that is required under Sec. 75.11 or Sec. 75.16 
for the measurement of SO2 emissions discharged to the 
atmosphere and the diluent monitor used as part of the NO 
continuous emission monitoring system that is required under Sec. 75.12 
or Sec. 75.17 for the measurement of NO emissions discharged 
into the atmosphere.) During the period when required to measure 
emissions removal efficiency, from January 1, 1997 through December 31, 
1999, the owner or operator shall meet the general operating 
requirements in Sec. 75.10 for both the inlet and the outlet 
SO2-diluent continuous emission monitoring systems, and in 
addition, the owner or operator shall comply with the monitoring 
provisions in this section. On January 1, 2000, the owner or operator 
may cease operating and/or reporting on the inlet SO2-diluent 
continuous emission monitoring system results for the purposes of the 
Acid Rain Program.
    (1) Pre-combustion technology. The owner or operator of an affected 
unit for which a precombustion technology has been employed for the 
purpose of meeting qualifying Phase I technology requirements shall use 
sections 4 and 5 of method 19 in appendix A of part 60 of this chapter 
to estimate, daily, for the purposes of this part, the percentage 
SO2 removal efficiency from such technology, and shall 
substitute the following ASTM methods for sampling, preparation, and 
analysis of coal for those cited in method 19: ASTM D2234-89, Standard 
Test Method for Collection of a Gross Sample of Coal (Type I, Conditions 
A, B, or C and systematic spacing), ASTM D2013-86, Standard Method of 
Preparing Coal Samples for Analysis, ASTM D2015-91, Standard Test Method 
for Gross Calorific Value of Coal and Coke by the Adiabatic Calorimeter, 
and ASTM D3177-89, Standard Test Methods for Total Sulfur in the 
Analysis Sample of Coal and Coke, or ASTM D4239-85, Standard Test Method 
for Sulfur in the Analysis Sample of Coal and Coke Using High 
Temperature Tube Furnace Combustion Methods. Each of the preceding ASTM 
methods is incorporated by reference in Sec. 75.6.
    (2) Combustion technology. The owner or operator of an affected unit 
for which a combustion technology has been installed and operated for 
the purpose of meeting qualifying Phase I technology requirements shall 
use the coal sampling and analysis procedures in paragraph (a)(1) of 
this section and equation 5 in paragraph (b) of this section to estimate 
the percentage SO2 removal efficiency from such technology.
    (3) Post-combustion technology. The owner or operator of an affected 
unit for which a post-combustion technology has been installed and 
operated for the purpose of meeting qualifying Phase I technology 
requirements shall install, certify, operate, and maintain both an inlet 
and an outlet SO2-diluent continuous emission monitoring 
system.
    (i) Both inlet and outlet SO2-diluent continuous emission 
monitoring systems shall consist of an SO2 pollutant 
concentration monitor and a diluent

[[Page 223]]

gas monitor for measuring the O2 or CO2 
concentrations in the flue gas and shall measure and record average 
hourly SO2 emission rates (in lb/mmBtu).
    (ii) The SO2-diluent continuous emission monitoring 
systems for measuring and recording the SO2 emissions removal 
by a qualifying Phase I technology shall meet all the requirements of 
this part during the period when required to measure emissions removal, 
from January 1, 1997 through December 31, 1999, and shall meet the 
certification deadline specified in Sec. 75.4.
    (iii) The SO2 pollutant concentration monitors and the 
diluent gas monitors at the inlet and outlet of the SO2 
emission controls shall meet all requirements specified in appendices A 
and B to this part.
    (b) Demonstration of SO2 emissions removal efficiency. 
The owner or operator shall demonstrate the average annual percentage 
SO2 emissions removal efficiency of the installed technology 
or combination of technologies during the period when required to 
measure emissions removal, from January 1, 1997 through December 31, 
1999, according to the following procedures:
    (1) Calculate the average annual SO2 emissions removal 
efficiency using equations 1-7 as follows:

%R=[100[1.0-(1.0-%Rf/100) (1.0-%Rg/100) 
    (1.0-%Rc/100)]


(Eq. 1)

where,

%R = Overall percentage SO2 emissions removal efficiency.
%Rf = Percentage SO2 emissions removal efficiency 
from fuel pretreatment, calculated from equation 19-22 in Reference 
Method 19 in appendix A to part 60 of this chapter.
%Rc = Percentage SO2 emissions removal of 
combustion emission controls, calculated from equation 5.
%Rg = Percentage SO2 removal efficiency of post-
combustion emission controls, calculated from equation 2.

[GRAPHIC] [TIFF OMITTED] TC01SE92.094


(Eq. 2)

where,

Eo = Average hourly SO2 emission rate in lb/mmBtu, 
measured at the outlet of the post-combustion emission controls during 
the calendar year, calculated from equation 3.
Ei = Average hourly SO2 emission rate in lb/mmBtu, 
measured at the inlet to the post-combustion emission controls during 
the calendar year, calculated from equation 4.

[GRAPHIC] [TIFF OMITTED] TC01SE92.095


(Eq. 3)

where,

Ehoj = Each hourly SO2 emission rate in lb/mmBtu, 
measured by the continuous emission monitoring system at the outlet to 
the post-combustion emission controls.
n = Total unit operating hours during which the SO2 
continuous emission monitoring system at the outlet of the emission 
controls collected quality-assured data.

[GRAPHIC] [TIFF OMITTED] TC01SE92.096


(Eq. 4)

where,

Ehij = Each hourly SO2 emission rate in lb/mmBtu, 
measured by the continuous emission monitoring system at the inlet to 
the post-combustion emission controls.
m=Total unit operating hours during which the SO2 continuous 
emission monitoring system at the inlet to the emission controls 
collected quality-assured data.

[GRAPHIC] [TIFF OMITTED] TR17MY95.000


where,

Eco = Average hourly SO2 emission rate in lb/
mmBtu, measured at the outlet of the combustion emission controls during 
the calendar year, calculated from equation 6.
Eci = Average hourly SO2 emission rate in lb/
mmBtu, determined by coal sampling and analysis according to the methods 
and procedures in paragraph (a)(1) of this section, calculated from 
equation 7.

[GRAPHIC] [TIFF OMITTED] TC01SE92.097


[[Page 224]]



(Eq. 6)

where,

Eocj = Each hourly SO2 emission rate in lb/mmBtu, 
measured by the continuous emission monitoring system at the outlet to 
the combustion controls.
q = Total unit operating hours for which the outlet SO2 
continuous emission monitoring system collected quality-assured data 
during the calendar year.

[GRAPHIC] [TIFF OMITTED] TR22MY96.002


where,

Eicj = Each average hourly SO2 emission rate in 
lb/mmBtu, determined by the coal sampling and analysis methods and 
procedures in paragraph (a)(1) of this section and calculated using 
appendix A, method 19 of part 60 of this chapter, performed once a day.
p = Total unit operation hours during which coal sampling and analysis 
is performed to determine SO2 emissions at the inlet to the 
combustion controls.

    (2) The owner or operator shall include all periods when fuel is 
being combusted in determining total unit operating hours for the 
purpose of calculating the average SO2 emissions removal 
efficiency during the calendar year.
    (3) The owner or operator shall use only quality-assured 
SO2 emissions data in the calculation of SO2 
emissions removal efficiency.
    (4) Compliance with the 90-percent SO2 emissions removal 
efficiency requirement under this part is determined annually beginning 
January 1, 1997 through December 31, 1999.

[58 FR 3701, Jan. 11, 1993, as amended at 60 FR 26521, May 17, 1995; 61 
FR 25582, May 22, 1996]



Sec. 75.16  Special provisions for monitoring emissions from common, by-pass, and multiple stacks for SO2 emissions and heat input determinations.

    (a) Phase I common stack procedures. Prior to January 1, 2000, the 
following procedures shall be used when more than one unit utilize a 
common stack:
    (1) Only Phase I units or only Phase II units using common stack. 
When a Phase I unit uses a common stack with one or more other Phase I 
units, but no other units, or when a Phase II unit uses a common stack 
with one or more Phase II units, but no other 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
    (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 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) Phase I unit using common stack with non-Phase I unit(s). When 
one or more Phase I units uses a common stack with one or more Phase II 
or 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
    (A) Designate any Phase II unit(s) as a substitution or compensating 
unit(s) in accordance with part 72 of this chapter and any nonaffected 
unit(s) 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

[[Page 225]]

monitoring system and flow monitoring system in the duct from each Phase 
II or nonaffected unit; calculate SO2 mass emissions from the 
Phase I units as the difference between SO2 mass emissions 
measured in the common stack and SO2 mass emissions measured 
in the ducts of the Phase II and nonaffected units; record and report 
the calculated SO2 mass emissions from the Phase I units, not 
to be reported as an hourly average value less than zero; and combine 
emissions for the Phase I units for compliance purposes; or
    (C) Install, certify, operate, and maintain an SO2 
continuous emission monitoring system and flow monitoring system in the 
duct from each Phase I or nonaffected unit; calculate SO2 
mass emissions from the Phase II units as the difference between 
SO2 mass emissions measured in the common stack and 
SO2 mass emissions measured in the ducts of the Phase I and 
nonaffected units, not to be reported as an hourly average value less 
than zero; and combine emissions for the Phase II units for 
recordkeeping and compliance purposes; or
    (D) Record the combined emissions from all units as the combined 
SO2 mass emissions for the Phase I units for recordkeeping 
and compliance purposes; or
    (E) 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. 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.
    (3) Phase II unit using common stack with non-affected unit(s). When 
one or more Phase II units uses a common stack with one or more 
nonaffected units, the owner or operator shall follow the procedures in 
paragraph (b)(2) of this section.
    (b) Phase II common stack procedures. On or after January 1, 2000, 
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
    (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

[[Page 226]]

    (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 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 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 an SO2 
continuous emission monitoring system or flow monitoring system on the 
bypass flue, duct, or stack gas stream and calculate SO2 mass 
emissions for the unit as the sum of the emissions recorded by all 
required monitoring systems; or
    (2) Monitor SO2 mass emissions on the bypass flue, duct, 
or stack gas stream using the reference methods in Sec. 75.22(b) for 
SO2 and flow 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) Where a Federal, State, or local regulation or permit prohibits 
operation of the bypass stack or duct or limits operation of the bypass 
stack or duct to emergency situations resulting from the malfunction of 
a flue gas desulfurization system record the following values for each 
hour during which emissions pass through the bypass stack or duct: the 
maximum potential concentration for SO2 as determined under 
section 2 of appendix A of this part, and the hourly volumetric flow 
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. 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

[[Page 227]]

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 units and stacks, pursuant to an approach approved by 
the Administrator, such that these emissions are not underestimated.
    (e) Heat input. The owner or operator of an affected unit using a 
common stack, bypass stack, or multiple stacks shall account for heat 
input 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 choose to install monitors to determine the 
heat input for the affected unit, wherever flow and diluent monitor 
measurements are used to determine the heat input, using the procedures 
specified in paragraphs (a) through (d) of this section, except that the 
term ``heat input'' 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 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 in paragraphs (a)(1)(ii), (a)(2)(ii), 
(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 at the common stack 
shall also determine and report heat input to each individual unit.
    (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 to the unit for each unit operating hour during which the 
bypass stack is used according to the missing data provisions for heat 
input under Sec. 75.36 or the procedures for calculating heat input from 
fuel sampling and analysis in section 5.5 of appendix F of 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 
at the common stack may choose to apportion the heat input 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 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 flow (in 1000 lb/hr) for each 
individual unit to the total steam flow for all units utilizing the 
common stack. 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 in Secs. 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]



Sec. 75.17  Specific provisions for monitoring emissions from common, by-pass, and multiple stacks for NOx emission rate.

    Notwithstanding the provisions of paragraphs (a), (b), and (c) 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

[[Page 228]]

program must also meet the provisions for monitoring NOX 
emission rate in Secs. 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 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 
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 bypass stack. When the flue gases 
from an affected unit utilize two or more ducts feeding into two or more 
stacks (that

[[Page 229]]

may include flue gases from other affected or nonaffected units), or 
when 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 monitor the NOX 
emission rate 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 
continuous emission monitoring system in each stack or duct and 
determine the NOX emission rate for the unit as the Btu-
weighted sum of the NOX emission rates measured in the stacks 
or ducts using the heat input estimation procedures in appendix F of 
this part; or
    (2) Install, certify, operate, and maintain a NOX 
continuous emission monitoring system in one stack or duct from each 
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.

[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]



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 SO2, NOX, and CO2 emissions calculation for low mass emissions units.

    (a) Applicability. (1) Consistent with the requirements of 
paragraphs (a)(2) and (b) of this section, the low mass emissions 
excepted methodology in paragraph (c) of this section may be used in 
lieu of continuous emission monitoring systems or, if applicable, in 
lieu of excepted methods under appendix D or E to this part, for the 
purpose of determining hourly heat input and hourly NOX, 
SO2, and CO2 mass emissions from a low mass 
emissions unit.

[[Page 230]]

    (i) A low mass emissions unit is an affected unit that is gas-fired, 
or oil-fired unit, that burns only natural gas or fuel oil and for 
which:
    (A) An initial demonstration is provided, in accordance with 
paragraph (a)(2) of this section, which shows that the unit emits no 
more than 25 tons of SO2 annually and no more than 50 tons of 
NOX annually; 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 emission unit continues to emit no more than 25 tons of 
SO2 annually and no more than 50 tons of NOX 
annually.
    (ii) Any qualifying unit must start using the low mass emissions 
excepted methodology in the first hour in which the unit operates in a 
calendar year. Notwithstanding, the earliest date for which a unit that 
meets the eligibility requirements of this section may begin to use this 
methodology is January 1, 2000.
    (2) A unit may initially qualify as a low mass emissions unit only 
under the following circumstances:
    (i) If the designated representative submits a certification 
application to use the low mass emissions excepted methodology and the 
Administrator certifies the use of such methodology. The certification 
application must contain:
    (A) Actual SO2 and NOX mass emissions data for 
each of the three calendar years prior to the calendar year in which the 
certification application is submitted demonstrating to the satisfaction 
of the Administrator that the unit emits less than 25 tons of 
SO2 and less than 50 tons of NOX annually; and
    (B) Calculated SO2 and NOX mass emissions, for 
each of the three calendar years prior to the calendar year in which the 
certification application is submitted, demonstrating to the 
satisfaction of the Administrator that the unit emits less than 25 tons 
of SO2 and less than 50 tons of NOX annually. The 
calculated emissions for each year shall be determined using either the 
maximum rated heat input methodology described in paragraph (c)(3)(i) of 
this section or the long term fuel flow heat input methodology described 
in paragraph (c)(3)(ii) of this section, in conjunction with the 
appropriate SO2, NOX, and CO2 emission 
rate from paragraph (c)(1)(i) of this section for SO2, 
paragraph (c)(1)(ii) or (c)(1)(iv) of this section for NOX 
and paragraph (c)(1)(iii) of this section for CO2; or
    (ii) When the three full years of actual, historical SO2 
and NOX mass emissions data required under paragraph 
(a)(2)(i) of this section are not available, the designated 
representative may submit an application to use the low mass emissions 
excepted methodology based upon a combination of historical 
SO2 and NOX mass emissions data and projected 
SO2 and NOX mass emissions, totaling three years. 
Historical data must be used for any years in which historical data 
exists and projected data should be used for any remaining future years 
needed to provide capacity factor data for three consecutive calender 
years. 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 unit that commenced operation after January 1, 
1997, 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 25 tons of 
SO2 and less than 50 tons of NOX annually. 
Projected emissions shall be calculated using either the default 
emission rates in tables 1,2 and 3 of this section, or for 
NOX emission rate a fuel-and-unit-specific NOX 
emission rate determined in accordance with the testing procedures in 
paragraph (c)(1)(iv) 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.
    (b) On-going qualification and disqualification. (1) Once a low mass 
emission 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 less than 25 tons of 
SO2 annually and less than 50 tons of NOX

[[Page 231]]

annually. The calculation methodology used for the annual demonstration 
shall be the same methodology, from paragraph (c) of this section, by 
which the unit initially qualified to use the low mass emissions 
excepted methodology.
    (2) If any low mass emission unit fails to provide the required 
annual demonstration under paragraph (b)(1) of this section, such that 
the calculated cumulative year-to-date emissions for the unit exceed 25 
tons of SO2 or 50 tons of NOX in any calendar 
quarter of any calendar year, then;
    (i) The low mass emission unit shall be disqualified from using the 
low mass emissions excepted methodology as of the end of the second 
calendar quarter following such quarter in which either the 25 ton limit 
for SO2 or the 50 ton limit for NOX was exceeded; 
and
    (ii) The owner or operator of the low mass emission unit shall have 
two calendar quarters from the end of the quarter in which the unit 
exceeded the 25 ton limit for SO2 or the 50 ton limit for 
NOX to install, certify, and report SO2, 
NOX, and CO2 emissions from monitoring systems 
that meet the requirements of Secs. 75.11, 75.12, and 75.13.
    (3) If a low mass emission 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 (e.g. natural gas or fuel oil) 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, certify, and report 
SO2, NOX, and CO2 from monitoring 
systems that meet the requirements of Secs. 75.11, 75.12, and 75.13 
prior to a change to such fuel. The owner or operator must notify the 
Administrator 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 
Secs. 75.11, 75.12, and 75.13.
    (4) If a unit commencing operation after January 1, 1997 initially 
qualifies to use the low mass emissions excepted methodology under this 
section and the owner or operator wants to use a 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 unit subject to an Acid Rain emission limitation, and 
beginning with the date and hour of the commencement of operation, for a 
unit subject to a NOX mass reduction program;
    (ii) Use these records to determine the cumulative heat input and 
SO2, NOX, and CO2 mass emissions in 
order to continue to qualify as a low mass emission unit; and
    (iii) Determine the cumulative SO2 and 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 1, 2 and 3 of this section or use the fuel-and-unit-specific 
NOX emission rate determined according to paragraph 
(c)(1)(iv) of this section. 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 emission unit that has been disqualified from using 
the low mass emissions excepted methodology may subsequently qualify 
again to use the low mass emissions methodology under paragraph (a)(2) 
of this section, provided that if such unit qualified under paragraph 
(a)(2)(ii) of this section, the unit may subsequently qualify again only 
if the unit meets the requirements of paragraph (a)(2)(i) of this 
section.
    (c) Low mass emissions excepted methodology, calculations, and 
values--(1) Determination of SO2, NOX, and 
CO2 emission rates. (i) Use Table 1 of this section to 
determine the appropriate SO2 emission rate for use in 
calculating hourly SO2 mass emissions under this section.
    (ii) Use either the appropriate NOX emission factor from 
Table 2 of this section, or a fuel-and-unit-specific NOX 
emission rate determined according to paragraph (c)(1)(iv) of this 
section, to

[[Page 232]]

calculate hourly NOX mass emissions under this section.
    (iii) Use Table 3 of this section to determine the appropriate 
CO2 emission rate for use in calculating hourly 
CO2 mass emissions under this section.
    (iv) In lieu of using the default NOX emission rate from 
Table 2 of this section, the owner or operator may, for each fuel 
combusted by a low mass emission 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. If this option is chosen, the following 
procedures shall be used.
    (A) Except as otherwise provided in paragraphs (c)(1)(iv)(F) and (G) 
of this paragraph, 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 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.
    (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 4 of this section.
    (3) If there are only two low mass emission units in the group of 
identical units, the results of the representative testing under 
paragraph (c)(1)(iv)(B)(1) of this section may be used to establish the 
fuel-and-unit-specific NOX emission rate(s) for the units. 
However, if there are more than two low mass emission units in the 
group, the testing must confirm that the units are identical by meeting 
the following criteria. The results of the representative testing may 
only be used to establish the fuel-and-unit-specific NOX 
emission rate(s) for such units if the following criteria are met:
    (i) at each of the four load levels tested, the NOX 
emission rate for each tested low mass emission unit does not differ by 
more than 10% from the average of the NOX 
emission rates for all units tested, or;
    (ii) if the average NOX emission rate of all low mass 
emission units tested at all four load levels is less than 0.20 lb/
mmBtu, an alternative criteria of 0.020 lb/mmBtu may be use 
in lieu of the 10% criteria. Units must all be within +0.020 lb/mmBtu of 
the average from the test to be considered identical units under this 
section.
    (4) If the acceptance criteria in paragaph (c)(1)(iv)(B)(3) of this 
section are not met then the group of low mass emission units is not 
considered an identical group of units and individual

[[Page 233]]

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 appendix E testing, determine the 
fuel-and-unit-specific NOX emission rate as follows:
    (1) For an individual low mass emission unit with no NOX 
emissions controls of any kind, the highest NOX emission rate 
obtained for a particular type of fuel in the appendix E test multiplied 
by 1.15 shall be the fuel-and-unit-specific NOX emission 
rate, for that type of fuel.
    (2) For a group of low mass emission units sharing a common fuel 
supply with no NOX controls of any kind on any of the units, 
the highest NOX emission rate obtained for a particular type 
of fuel in all of the appendix E tests of all units in the group of 
units sharing a common fuel supply multiplied by 1.15 shall be the fuel-
and-unit-specific NOX emission rate for each unit in the 
group, for that type of fuel.
    (3) For a group of identical low mass emission units which perform 
representative testing according to paragraph (c)(1)(iv)(B) of this 
section with no NOX controls of any kind on any of the units, 
the fuel-and-unit-specific NOX emission rate for all units, 
for a particular type of fuel, multiplied by 1.15 shall be the highest 
NOX emission rate from any unit tested in the group, for that 
type of fuel.
    (4) For an individual low mass emission unit which has 
NOX emission controls of any kind, 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 emission rate from the appendix E test for that type 
of fuel multiplied by 1.15; or
    (ii) 0.15 lb/mmBtu.
    (5) For a group of low mass emission units sharing a common fuel 
supply, one or more of which has NOX controls of any kind, 
the fuel-and-unit-specific NOX emission rate for each unit in 
the group of units sharing a common fuel supply shall, for a particular 
type of fuel combusted by the group of units sharing a common fuel 
supply, shall be the higher of:
    (i) The highest NOX emission rate from all appendix E 
tests of all low mass emission units in the group for that type of fuel 
multiplied by 1.15; or
    (ii) 0.15 lb/mmBtu.
    (6) For a group of identical low mass emission units, which perform 
representative testing according to paragraph (c)(1)(iv)(B) of this 
section and have identical NOX controls, 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 NOX emission rate from all appendix E 
tests of all tested low mass emission units in the group of identical 
units for that type of fuel multiplied by 1.15; or
    (ii) 0.15 lb/mmBtu.
    (D) For each low mass emission unit, each unit in a group of units 
sharing a common fuel supply, or 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 every five 
years, 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. If a low mass 
emission 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,

[[Page 234]]

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 emission unit, each low mass emission unit in a 
group of units combusting a common fuel, or each low mass emission 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 emission units for which at least 3 years of 
NOX emission rate continuous emissions monitoring system data 
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 with NOX emission controls of any kind, 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 NOX emission 
controls, 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-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.
    (2) For low mass emission units with other types of 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.
    (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:
    (i) For each low mass emission 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

[[Page 235]]

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 emission 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 output (in megawatts or thousands of pounds of steam), for the 
purpose of apportioning heat input to the individual unit operating 
hours.
    (iv) For each low mass emission unit with NOX emission 
controls of any kind, 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 emission 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, the hourly heat input (mmBtu) to a low mass emission 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:

HIqtr = Tqtr  x  HIhr    (Eq. LM-1)

Where:

Tqtr = Actual number of operating hours in the quarter (hr).
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.
    (ii) Long term fuel flow heat input method. The owner or operator 
may, for the purpose of demonstrating that a low mass emission 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 emission 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) standard, American Petroleum 
Institute (API) Petroleum Measurement Standards, Chapter 3, Tank

[[Page 236]]

Gauging: Section 1A, Standard Practice for the Manual Gauging of 
Petroleum and Petroleum Products, December 1994; Section 1B, Standard 
Practice for Level Measurement of Liquid Hydrocarbons in Stationary 
Tanks by Automatic Tank Gauging, April 1992 (reaffirmed January 1997); 
Section 2, Standard Practice for Gauging Petroleum and Petroleum 
Products in Tank Cars, September 1995; Section 3, Standard Practice for 
Level Measurement of Liquid Hydrocarbons in Stationary Pressurized 
Storage Tanks by Automatic Tank Gauging, June 1996; Section 4, Standard 
Practice for Level Measurement of Liquid Hydrocarbons on Marine Vessels 
by Automatic Tank Gauging, April 1995; and Section 5, Standard Practice 
for Level Measurement of Light Hydrocarbon Liquids Onboard Marine 
Vessels by Automatic Tank Gauging, March 1997; Shop Testing of Automatic 
Liquid Level Gages, Bulletin 2509 B, December 1961 (Reaffirmed August 
1987, October 1992) (incorporated by reference under Sec. 75.6); or;
    (3) A fuel flow meter certified and maintained according to appendix 
D to this part.
    (C) 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
    (2) Using the appropriate default specific gravity value in Table 
LM-6 of this section.
    (D) For each type of fuel oil combusted during the quarter, the 
specific gravity of the oil 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 shall be used; or
    (2) Using the appropriate default specific gravity value in Table 5 
of this section.
    (E) The quarterly heat input from each type of fuel combusted during 
the quarter by a low mass emission unit or group of low mass emission 
units sharing a common fuel supply shall be determined using Equation 
LM-2 for oil and LM-3 for natural gas.
[GRAPHIC] [TIFF OMITTED] TR27OC98.001


Eq LM-2 (for fuel oil or diesel fuel)

Where:

HIfuel-qtr = Quarterly total heat input from oil (mmBtu).
Mqtr = Mass of oil consumed during the entire 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] TR27OC98.002


Eq LM-3 (for natural gas)

Where:

HIfuel-qtr = Quarterly heat input from natural gas (mmBtu).
Qg = Value of natural gas combusted during the quarter, as 
determined under paragraph (c)(3)(ii)(B) of this section standard cubic 
feet (scf).
GCVg = Gross calorific value of the natural gas combusted 
during the quarter, as determined under paragraph (c)(3)(ii)(C) of this 
section (Btu/scf)
10\6\ = Conversion of Btu to mmBtu.

    (F) The quarterly heat input (mmBtu) for all fuels for the quarter, 
HIqtr-total, shall be the sum of the 
HIfuel-qtr values determined using Equations LM-2 and LM-3.
[GRAPHIC] [TIFF OMITTED] TR27OC98.003


(Eq. LM-4)

    (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.
    (H) For each low mass emission unit, each low mass emission unit of 
an identical group of units, or each low mass emission unit in a group 
of units sharing a common fuel supply, the owner or operator shall 
determine the quarterly unit output in megawatts or pounds of

[[Page 237]]

steam. The quarterly unit output shall be the sum of the hourly unit 
output values recorded under paragraph (c)(2) of this section and shall 
be determined using Equations LM-5 or LM-6.
[GRAPHIC] [TIFF OMITTED] TR27OC98.004


Eq LM-5 (for MW output)
[GRAPHIC] [TIFF OMITTED] TR27OC98.005


Eq LM-6 (for steam output)

Where:

MWqtr = the power produced during all hours of operation 
during the quarter by the unit (MW)
STfuel-qtr = the total quarterly steam output produced during 
all hours of operation during the quarter by the unit (klb)
MW = the power produced during each hour in which the unit operated 
during the quarter (MW).
ST = the steam output produced during each hour in which the unit 
operated during the quarter (klb)

    (I) For a low mass emission 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 output from the unit (MW)
SThr = hourly steam output from the unit (klb)

    (J) For each low mass emission 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 output from the individual unit (MW)
SThr = hourly steam output from the individual unit (klb)

[GRAPHIC] [TIFF OMITTED] TR27OC98.010

    (4) Calculation of SO2, NOX and CO2 
mass emissions. The owner or operator shall, for the purpose of 
demonstrating that a low mass emission 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 emission unit shall be determined 
using Equation LM-9 and the appropriate fuel-based SO2 
emission factor from Table 1 of this section 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).

[[Page 238]]

EFSO2 = SO2 emission factor from Table 1 of this 
section (lb/mmBtu).
HIhr = Either the maximum rated hourly heat input under 
paragraph (c)(3)(i)(A) of this section or the hourly heat input under 
paragraph (c)(3)(ii) of this section (mmBtu).

    (B) The quarterly SO2 mass emissions (tons) for the low 
mass emission 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 emission 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) NOX mass emissions. (A) The hourly NOX 
mass emissions for the low mass emission 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 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 emission 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 emission 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.
    (iii) CO2 Mass Emissions. (A) The hourly CO2 
mass emissions (tons) for the affected low mass emission unit shall be 
determined using Equation LM-11 and the appropriate fuel-based 
CO2 emission factor from Table 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 CO  mass emissions (tons).
EFCO2 = Fuel-based CO2 emission factor from Table 
3 of this section (ton/mmBtu).
HIhr = Either the maximum rated hourly heat input from 
paragraph (c)(3)(i)(A) of this section or the hourly heat input as 
determined under paragraph (c)(3)(ii) of this section (mmBtu).

    (B) The quarterly CO2 mass emissions (tons) for the low 
mass emission 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 emission 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

[[Page 239]]

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 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 American Petroleum Institute (API) standard, 
American Petroleum Institute (API) Petroleum Measurement Standards, 
Chapter 3, Tank Gauging: Section 1A, Standard Practice for the Manual 
Gauging of Petroleum and Petroleum Products, December 1994; Section 1B, 
Standard Practice for Level Measurement of Liquid Hydrocarbons in 
Stationary Tanks by Automatic Tank Gauging, April 1992 (reaffirmed 
January 1997); Section 2, Standard Practice for Gauging Petroleum and 
Petroleum Products in Tank Cars, September 1995; Section 3, Standard 
Practice for Level Measurement of Liquid Hydrocarbons in Stationary 
Pressurized Storage Tanks by Automatic Tank Gauging, June 1996; Section 
4, Standard Practice for Level Measurement of Liquid Hydrocarbons on 
Marine Vessels by Automatic Tank Gauging, April 1995; and Section 5, 
Standard Practice for Level Measurement of Light Hydrocarbon Liquids 
Onboard Marine Vessels by Automatic Tank Gauging, March 1997, Shop 
Testing of Automatic Liquid Level Gages, Bulletin 2509 B, December 1961 
(Reaffirmed August 1987, October 1992) (incorporated by reference under 
Sec. 75.6), 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 emission 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 emission unit for which fuel-and-unit-specific 
NOX emission rates are determined in accordance with 
paragraph (c)(1)(iv) of this section and which have NOX 
emission controls of any kind, 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.

   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.

[[Page 240]]

 
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
              Boiler 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
------------------------------------------------------------------------
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.
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]



            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, which includes the automated data acquisition and 
handling system, and, where applicable, the CO2 continuous 
emission monitoring system, 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 Secs. 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 for each 
continuous emission or opacity monitoring system or component thereof, 
continuous emission or opacity monitoring system or component thereof 
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

[[Page 241]]

recertification) application under paragraph (a)(4) of this section. 
Notwithstanding this paragraph, no continuous emission or opacity 
monitor systems for a combustion source seeking to enter the Opt-in 
Program in accordance with part 74 of this chapter shall be deemed 
provisionally certified (or recertified) for use under the Acid Rain 
Program. Data measured and recorded by a provisionally certified (or 
recertified) continuous emission or opacity monitoring system or 
component thereof, 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 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 or component thereof 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 or 
component thereof 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 
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 
data validation procedures

[[Page 242]]

of paragraph (b)(3) of this section were not used), 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 for loss of initial certification in paragraph 
(a)(5) of this section for each continuous emission or opacity 
monitoring system or component thereof 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 or component thereof, 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 or component thereof can be adjusted, repaired, or 
replaced and certification tests successfully completed, the owner or 
operator shall substitute the following values, as applicable, for each 
hour of unit operation during the period of invalid data specified in 
paragraph (a)(4)(iii) of this section or in Sec. 75.21: the maximum 
potential concentration of SO2, as defined in section 2.1.1.1 
of appendix A to this part, to report SO2 concentration; the 
maximum potential NOX emission rate, as defined in Sec. 72.2 
of this chapter, to report NOX emissions in lb/mmBtu; the 
maximum potential concentration of NOX, as defined in section 
2.1.2.1 of appendix A to this part, to report NOX emissions 
in ppm (when a NOX concentration monitoring system is used to 
determine NOX mass emissions, as defined under 
Sec. 75.71(a)(2)); the maximum potential flow rate, as defined in 
section 2.1.4.1 of appendix A to this part, to report volumetric flow; 
the maximum potential concentration of CO2, as defined in 
section 2.1.3.1 of appendix A to this part, to report CO2 
concentration data; and either the minimum potential moisture 
percentage, as defined in section 2.1.5 of appendix A to this part or, 
if Equation 19-3, 19-4 or 19-8 in Method 19 in appendix A to part 60 of 
this chapter is used to determine NOX emission rate, the 
maximum potential moisture percentage, as defined in section 2.1.6 of 
appendix A to this part; and
    (ii) The designated representative shall submit a notification of 
certification retest dates as specified in Sec. 75.61(a)(1)(ii) and a 
new certification application according to the procedures in paragraph 
(a)(2) of this section; and
    (iii) The owner or operator shall repeat all certification tests or 
other requirements that were failed by the continuous emission or 
opacity monitoring system, as indicated in the Administrator's notice of 
disapproval, no later than 30 unit operating days after the date of 
issuance of the notice of disapproval.
    (b) Recertification approval process. Whenever the owner or operator 
makes a replacement, modification, or change in a certified continuous 
emission monitoring system or continuous opacity monitoring system that 
may significantly affect the ability of the system to accurately measure 
or record the SO2 or CO2 concentration, stack gas 
volumetric flow rate, NOX emission rate, 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 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 recertify a continuous opacity

[[Page 243]]

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 not 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) 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 test(s) of the CEMS to the hour of 
successful completion of a probationary calibration error test 
(according to paragraph (b)(3)(ii) of this section) following the 
replacement, modification, or change to the CEMS, the owner or operator 
shall either substitute for missing data, according to the standard 
missing data procedures in Secs. 75.33 through 75.37, or report emission 
data using a reference method or another monitoring system that has been 
certified or approved for use under this part. Notwithstanding this 
requirement, 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 the period extending from the hour of commencement of the 
replacement,

[[Page 244]]

modification, or change requiring recertification of the CEMS to the 
hour of commencement of the recertification test period: 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. The first hour of quality-assured data 
for the recertified monitoring system shall be determined in accordance 
with paragraphs (b)(3)(ii) through (b)(3)(ix) of this section.
    (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 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

[[Page 245]]

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 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

[[Page 246]]

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 
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

[[Page 247]]

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. 75.31 or Sec. 75.33 shall be used from the date and 
hour of receipt of the disapproval notice back to the hour of the 
probationary calibration error test that began the recertification test 
period. Data from the monitoring system remain invalid 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 specified 
in paragraphs (b)(1), (d), and (e) of this section, 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:
    (1) For each SO2 pollutant concentration monitor, each 
NOX concentration monitoring system used to determine 
NOX mass emissions, as defined under Sec. 75.71(a)(2), and 
for each NOX-diluent continuous emission monitoring system:
    (i) A 7-day calibration error test, where, for the NOX-
diluent continuous emission monitoring system, the test is performed 
separately on the NOX pollutant concentration monitor and the 
diluent gas monitor;
    (ii) A linearity check, where, for the NOX-diluent 
continuous emission monitoring system, the test is performed separately 
on the NOX pollutant concentration monitor and the diluent 
gas monitor;
    (iii) A relative accuracy test audit. For the NOX-diluent 
continuous emission monitoring system, the RATA shall be done on a 
system basis, in units of lb/mmBtu. For the NOX concentration 
monitoring system, the RATA shall be done on a ppm basis.
    (iv) A bias test; and
    (v) A cycle time test.
    (v) A cycle time/response time test.

[[Page 248]]

    (2) For each flow monitor:
    (i) A 7-day calibration error test;
    (ii) Relative accuracy test audits at three flue gas velocities; and
    (iii) A bias test (at normal operating load).
    (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 
O2 monitor which is part of a CO2 continuous 
emission monitoring system, each diluent monitor used to monitor heat 
input and each SO2-diluent continuous emission monitoring 
system:
    (i) A 7-day calibration error test, where, for the SO2-
diluent system, this test is performed separately on each component 
monitor;
    (ii) A linearity check, where, for the SO2 diluent 
system, this check is performed separately on each component monitor;
    (iii) A relatively accuracy test audit; and
    (iv) A cycle-time test.
    (5) For each continuous moisture monitoring system consisting of 
wet- and dry-basis O2 analyzers:
    (i) A 7-day calibration error test of each O2 analyzer;
    (ii) A cycle time test of each O2 analyzer;
    (iii) A linearity test of each O2 analyzer; and
    (iv) A RATA, directly comparing the percent moisture measured by the 
monitoring system to a reference method.
    (6) For each continuous moisture sensor: A RATA, directly comparing 
the percent moisture measured by the monitor sensor to a reference 
method.
    (7) For a continuous moisture monitoring system consisting of a 
temperature sensor and a data acquisition and 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 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.
    (10) 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.

[[Page 249]]

    (ii) Basic facilities (e.g., electricity) for sampling and testing 
equipment.
    (d) Initial certification and recertification and quality assurance 
procedures for optional backup continuous emission monitoring systems. 
(1) Redundant backups. The owner or operator of an optional redundant 
backup CEMS shall comply with all the requirements for initial 
certification and recertification according to the procedures specified 
in paragraphs (a), (b), and (c) of this section. The owner or operator 
shall operate the redundant backup CEMS during all periods of unit 
operation, except for periods of calibration, quality assurance, 
maintenance, or repair. The owner or operator shall perform upon the 
redundant backup CEMS all quality assurance and quality control 
procedures specified in appendix B to this part, except that the daily 
assessments in section 2.1 of appendix B to this part are optional for 
days on which the redundant backup CEMS is not used to report emission 
data under this part. For any day on which a redundant backup CEMS is 
used to report emission data, the system must meet all of the applicable 
daily assessment criteria in appendix B to this part.
    (2) Non-redundant backups. The owner or operator of an optional non-
redundant backup CEMS or like-kind replacement analyzer shall comply 
with all of the following requirements for initial certification, 
quality assurance, recertification, and data reporting:
    (i) Except as provided in paragraph (d)(2)(v) of this section, for a 
regular non-redundant backup CEMS (i.e., a non-redundant backup CEMS 
that has its own separate probe, sample interface, and analyzer), or a 
non-redundant backup flow monitor, all of the tests in paragraph (c) of 
this section are required for initial certification of the system, 
except for the 7-day calibration error test.
    (ii) For a like-kind replacement non-redundant backup analyzer 
(i.e., a non-redundant backup analyzer that uses the same probe and 
sample interface as a primary monitoring system), no initial 
certification of the analyzer is required. A non-redundant backup 
analyzer, connected to the same probe and 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 or SO2-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

[[Page 250]]

passed within 168 unit (or stack) operating hours of the probationary 
calibration error test. However, if the linearity test is either failed, 
aborted due to a problem with the CEMS or like-kind replacement 
analyzer, or is not completed as required, 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.
    (iv) When data are reported from a non-redundant backup CEMS or 
like-kind replacement analyzer, the appropriate bias adjustment factor 
shall be determined as follows:
    (A) For a regular non-redundant backup CEMS, as described in 
paragraph (d)(2)(i) of this section, apply the bias adjustment factor 
from the most recent RATA of the non-redundant backup system (even if 
that RATA was done more than 12 months previously); or
    (B) When a like-kind replacement non-redundant backup analyzer is 
used as a component of a primary CEMS (as described in paragraph 
(d)(2)(ii) of this section), apply the primary monitoring system bias 
adjustment factor.
    (v) For each parameter monitored (i.e., SO2, 
CO2, NOX 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, unless the CEMS passes a RATA at that unit or stack. For 
each parameter monitored (SO2, CO2 or 
NOX) 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, 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 and specify the 
manufacturer, model and serial number of the like-kind replacement 
analyzer. This information may be added, deleted or updated as 
necessary, from quarter to quarter. The owner or operator shall also 
report data from the like-kind replacement analyzer using the system 
identification number of the primary monitoring system and the assigned 
component identification number of the like-kind replacement analyzer. 
For the purposes of the electronic quarterly report required under 
Sec. 75.64, the owner or operator may manually enter the appropriate 
component identification number(s) of any like-kind replacement 
analyzer(s) used for data reporting during the quarter.
    (viii) When reporting data from a certified regular non-redundant 
backup CEMS, use a method of determination (MODC) code of ``02.'' When 
reporting data from a like-kind replacement non-redundant backup 
analyzer, use a MODC of ``17'' (see Table 4a under Sec. 75.57). For the 
purposes of the electronic quarterly report required under Sec. 75.64, 
the owner or operator may manually enter the required MODC of ``17'' for 
a like-kind replacement analyzer.
    (3) Reference method backups. A monitoring system that is operated 
as a reference method backup system pursuant to the reference method 
requirements

[[Page 251]]

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.
    (1) The Administrator will publish each request for initial 
certification of an alternative monitoring system in the Federal 
Register and, following a public comment period of 60 days, will issue a 
notice of approval or disapproval.
    (2) No alternative monitoring system shall be authorized by the 
Administrator in a permit issued pursuant to part 72 of this chapter 
unless approved by the Administrator in accordance with this part.
    (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.
    (ii) For the automated data acquisition and handling system used 
under either the optional SO2 mass emissions estimation 
procedure in appendix D of this part or the optional NOX 
emissions estimation protocol in appendix E of this part, the owner or 
operator shall perform tests designed to verify:
    (A) The proper computation of hourly averages for pollutant 
concentrations, fuel flow rates, emission rates, heat input, and 
pollutant mass emissions; and
    (B) Proper computation and application of the missing data 
substitution procedures in appendix D or E of this part.
    (iii) When the optional NOX emissions protocol in 
appendix E is used, the owner or operator shall complete all initial 
performance testing under section 2.1 of appendix E.

[[Page 252]]

    (2) Initial certification and recertification testing notification. 
The designated representative shall provide initial certification 
testing notification and routine periodic retesting notification for an 
excepted monitoring system under appendix E to this part as specified in 
Sec. 75.61. The designated representative shall also submit 
recertification testing notification, as specified in Sec. 75.61, for 
quality assurance related NOX emission rate re-testing under 
section 2.3 of appendix E to this part for an excepted monitoring system 
under appendix E to this part. Initial certification testing 
notification or periodic retesting notification is not required for 
testing of a fuel flowmeter or for testing of 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 Secs. 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 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 in paragraph (g)(7) of this section shall 
apply rather than the procedures for loss of certification in either 
paragraph (a)(5) or (b)(5) of this section. Data measured and recorded 
by a provisionally certified excepted monitoring system under appendix D 
or E to this part will be considered quality assured data from the date 
and time of completion of the last initial certification or 
recertification test, provided that the Administrator does not revoke 
the provisional certification or recertification by issuing a notice of 
disapproval in accordance with the provisions in paragraph (a)(4) or 
(b)(5) of this section.
    (6) Recertification requirements. Recertification of an excepted 
monitoring system under appendix D or E to this part is required for any 
modification to the system or change in operation that could 
significantly affect the ability of the system to accurately account for 
emissions and for which the Administrator determines that an accuracy 
test of the fuel flowmeter or a retest under appendix E to this part to 
re-establish the NOX correlation curve is required. Examples 
of such changes or modifications include fuel flowmeter replacement, 
changes in unit configuration, or exceedance of operating parameters.
    (7) Procedures for loss of certification or recertification for 
excepted monitoring systems under appendices D and E to this part. In 
the event that a certification or recertification application is 
disapproved for an excepted monitoring system, data from the monitoring 
system are invalidated, and the applicable missing data procedures in 
section 2.4 of appendix D or section 2.5 of appendix E to this part 
shall be used from the date and hour of receipt of such notice back to 
the hour of the provisional certification. Data from the excepted 
monitoring system remain invalid until all required tests are repeated 
and the excepted monitoring system is again provisionally certified. The 
owner or operator shall repeat all certification or recertification 
tests or other requirements, as indicated in the Administrator's notice 
of disapproval, no later than 30 unit operating days after the date of 
issuance of the notice of disapproval. The designated representative 
shall submit a notification of the certification or recertification 
retest dates if required under paragraph (g)(2) of this section and 
shall submit a new certification or recertification application 
according to the procedures in paragraph (g)(4) of this section.

[[Page 253]]

    (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 Secs. 75.53 and 75.62. The designated 
representative for an owner or operator who wishes to use fuel-and unit-
specific NOX emission rate testing for units with 
NOX controls under Sec. 75.19(c)(1)(iv) must submit in the 
monitoring plan the parameters monitored which will be used to determine 
operation of the NOX emission controls. For units using water 
or steam injection to control NOX, the water-to-fuel or 
steam-to-fuel range of values must be documented.
    (2) Certification application. The designated representative shall 
submit a certification application in accordance with 
Sec. 75.63(a)(1)(iii).
    (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 ``excepted methodology.'' The 
excepted methodology shall be deemed provisionally certified for use 
under the Acid Rain Program, as of the following dates:
    (i) For a unit that commenced operation on or before January 1, 
1997, from January 1 of the year following submission of the 
certification application until the completion of the period for the 
Administrator's review; or
    (ii) For a unit that commenced operation after January 1, 1997, from 
the date of submission of a certification application for approval to 
use the low mass emissions excepted methodology under Sec. 75.19 until 
the completion of the period for the Administrator's review, except that 
the methodology may be used retrospectively until the date and hour that 
the unit commenced operation for purposes of demonstrating that the unit 
qualified to use the methodology under Sec. 75.19(b)(4)(iii).
    (4) Disapproval of certification applications. If the Administrator 
determines that the certification application does not demonstrate that 
the unit meets the requirements of Secs. 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 the data recorded under the excepted methodology 
shall not be considered valid. The owner or operator shall follow the 
procedures for loss of certification:
    (i) 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 
Secs. 75.21(e) (introductory paragraph) and 75.21(e)(1): 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 emission rate; the maximum 
potential flow rate, as defined in section 2.1 of appendix A to this 
part to report volumetric flow; or the maximum CO2 
concentration used to determine the maximum potential concentration of 
SO2 in section 2.1.1.1 of appendix A to this part to report 
CO2 concentration data. 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 of appendix A to 
this part. The owner or operator shall substitute these values until 
such time, date, and hour as a continuous emission monitoring system or 
excepted monitoring system, where applicable, is installed and 
provisionally certified;

[[Page 254]]

    (ii) The designated representative shall submit a notification of 
certification test 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 install and provisionally certify 
continuous emission monitoring systems or excepted monitoring systems, 
where applicable, two calendar quarters from the end of the quarter in 
which the unit no longer qualifies as a low mass emissions unit.

[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]



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), 
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) or (e)(2). 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 as emergency backup 
fuel(s) or for short-term testing, the SO2 monitoring system 
shall be exempted from the RATA requirements of appendices A and B to 
this part in any calendar year that the unit combusts the higher-sulfur 
fuel(s) for no more than 480 hours. If, in a particular calendar year, 
the higher-sulfur fuel usage exceeds 480 hours, the owner or operator 
shall perform a RATA of the SO2 monitor (while

[[Page 255]]

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) On and after April 1, 2000, the quality assurance provisions of 
Secs. 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 under paragraphs (a)(6) or (a)(7) of this section from the 
SO2 RATA requirements of this part, 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 status is revoked prospectively by the 
Administrator. The data measured and

[[Page 256]]

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 another 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]



Sec. 75.22  Reference test methods.

    (a) The owner or operator shall use the following methods included 
in appendix A to part 60 of this chapter to conduct monitoring system 
tests for certification or recertification of continuous emission 
monitoring systems and excepted monitoring systems under appendix E of 
this part and quality assurance and quality control procedures. Unless 
otherwise specified in this part, use only codified versions of Methods 
3A, 4, 6C and 7E revised as of July 1, 1995 or July 1, 1996 or July 1, 
1997.
    (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 2 
of the method or the moisture approximation procedure described in 
section 3 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 
techniques for approximating the stack gas moisture content described in 
section 1.2 of Method 4 may be used in lieu of the procedures in 
sections 2 and 3 of the method.
    (5) Methods 6, 6A, 6B or 6C, and 7, 7A, 7C, 7D or 7E, as applicable, 
are the reference methods for determining SO2 and 
NOX pollutant concentrations. (Methods 6A and 6B may also be 
used to determine SO2 emission rate in lb/mmBtu. Methods 7, 
7A, 7C, 7D, or 7E 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 exception in section 5.1.2 of method 
7E.)
    (6) Method 20 is the reference method for determining NOX 
and diluent emissions from stationary gas turbines for testing under 
appendix E of this part.
    (b) The owner or operator may use the following methods in appendix 
A of part 60 of this chapter as a reference method backup monitoring 
system to provide quality-assured monitor data:
    (1) Method 3A for determining O2 or CO2 
concentration;
    (2) Method 6C for determining SO2 concentration;
    (3) Method 7E for determining total NOX concentration 
(both NO and NO2); and
    (4) Method 2, or its allowable alternatives, as provided in appendix 
A to part 60 of this chapter, except for Methods 2B and 2E, for 
determining volumetric flow. The sample point(s) for reference methods 
shall be located according to the provisions of section 6.5.5 of 
appendix A to this part.
    (c)(1) Instrumental EPA Reference Methods 3A, 6C, 7E, and 20 shall 
be conducted using calibration gases as defined in section 5 of appendix 
A to this part. Otherwise, performance tests shall be conducted and data 
reduced in accordance with the test methods and procedures of this part 
unless the Administrator:

[[Page 257]]

    (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 ]



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 5.0 percent based upon the span value, the calibration error of 
a diluent gas monitor exceeds 1.0 percent O2 or 
CO2, or the calibration error of a flow monitor exceeds 6.0 
percent based upon the span value, which is twice the applicable 
specification in appendix A 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 or certified portable monitor or 
monitoring system or a reference method for measuring and recording 
emissions from the affected unit(s); or
    (3) Adjust the gas discharge paths from the affected unit(s) with 
emissions normally observed by the out-of-control monitor or monitoring 
system so that all exhaust gases are monitored by a certified monitor or 
monitoring system meeting the requirements of appendices A and B of this 
part.
    (d) When the bias test indicates that an SO2 monitor, a 
flow monitor, a NOX-diluent continuous emission monitoring 
system or a NOX concentration monitoring system used to 
determine NOX mass emissions, as defined in Sec. 75.71(a)(2), 
is biased low (i.e., the arithmetic mean of the differences between the 
reference method value and the monitor or monitoring system measurements 
in a relative accuracy test audit exceed the bias statistic in section 7 
of appendix A to this part), the owner or operator shall adjust the 
monitor or continuous emission monitoring system to eliminate the cause 
of bias such that it passes the bias test or calculate and use the bias 
adjustment factor as specified in section 2.3.4 of appendix B to this 
part.
    (e) The owner or operator shall determine if a continuous opacity 
monitoring system is out-of-control and shall take appropriate 
corrective actions according to the procedures specified for State 
Implementation Plans,

[[Page 258]]

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]



             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.
    (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, 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

[[Page 259]]

data availability in Sec. 75.32, and to provide the quality-assured data 
used in the missing data procedures in Secs. 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. 75.54(b)(5) or Sec. 75.57(b)(5), 
as applicable, 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 Secs. 75.31 and 75.33 only, all hours during which the unit 
combusts only gaseous fuel shall be excluded from the definition of 
``monitor operating hour,'' ``quality assured monitor operating hour,'' 
``unit operating hour,'' and ``unit operating day,'' when SO2 
emissions are determined in accordance with Sec. 75.11(e)(1) or (e)(2).
    (4) During all hours in which a unit with an SO2 
continuous emission monitoring system combusts only gaseous fuel and the 
owner or operator uses the SO2 monitoring system to determine 
SO2 mass emissions pursuant to Sec. 75.11(e)(3), the owner or 
operator shall determine the percent monitor data availability for 
SO2 in accordance with Sec. 75.32 and shall use the standard 
SO2 missing data procedures of Sec. 75.33.

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



Sec. 75.31  Initial missing data procedures.

    (a) During the first 720 quality-assured monitor operating hours 
following initial certification (i.e., the date and time at which 
quality assured data begins to be recorded by the CEMS) of an 
SO2 pollutant concentration monitor, or a CO2 
pollutant concentration monitor (or an O2 monitor used to 
determine CO2 concentration in accordance with appendix F to 
this part), or an O2 or CO2 diluent monitor used 
to calculate heat input or a moisture monitoring system, and during the 
first 2,160 quality-assured monitor operating hours following initial 
certification of a flow monitor, or a NOX-diluent monitoring 
system, or a NOX concentration monitoring system used to 
determine NOX mass emissions, 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 and moisture data. For each hour of missing SO2 or 
CO2 pollutant concentration data (including CO2 
data converted from O2 data using the procedures in appendix 
F of this part), or

[[Page 260]]

missing O2 or CO2 diluent concentration data used 
to calculate heat input, or missing moisture data, the owner or operator 
shall calculate the substitute data as follows:
    (1) Whenever prior quality-assured data exist, the owner or operator 
shall substitute, by means of the data acquisition and handling system, 
for each hour of missing data, the average of the hourly SO2, 
CO2 or O2 concentrations or moisture percentages 
recorded by a certified monitor for the unit operating hour immediately 
before and the unit operating hour immediately after the missing data 
period.
    (2) Whenever no prior quality assured SO2, CO2 
or O2 concentration data or moisture data exist, the owner or 
operator shall substitute, as applicable, for each hour of missing data, 
the maximum potential SO2 concentration or the maximum 
potential CO2 concentration or the minimum potential 
O2 concentration or (unless Equation 19-3, 19-4 or 19-8 in 
Method 19 in appendix A to part 60 of this chapter is used to determine 
NOX emission rate) the minimum potential moisture percentage, 
as specified, respectively, in sections 2.1.1.1, 2.1.3.1, 2.1.3.2 and 
2.1.5 of appendix A to this part. If Equation 19-3, 19-4 or 19-8 in 
Method 19 in appendix A 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. 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 
corresponding to the operating load at the time the missing data period 
occurred, the owner or operator shall substitute, by means of the 
automated data acquisition and handling system, for each hour of missing 
data, the average hourly flow rate or NOX emission rate or 
NOX concentration recorded by a certified monitoring system. 
The average flow rate (or NOX emission rate or NOX 
concentration) shall be the arithmetic average of all data in the 
corresponding load range as determined using the procedure in appendix C 
to this part.
    (2) 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, 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.

[64 FR 28601, May 26, 1999]



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

    (a) Following initial certification (i.e., the date and time at 
which quality assured data begins to be recorded by the CEMS), upon 
completion of: the first 720 quality-assured monitor operating hours of 
an SO2 pollutant concentration monitor, or a CO2 
pollutant concentration monitor (or O2 monitor used to 
determine CO2 concentration), or an O2 or 
CO2 diluent monitor used to calculate heat input or a 
moisture monitoring system; or the first 2,160 quality-assured monitor 
operating hours of a flow monitor or a NOX-diluent monitoring 
system or a NOX concentration monitoring system, the owner or 
operator shall calculate and record, by means of the automated data 
acquisition and handling system, the percent monitor data availability 
for the SO2 pollutant concentration monitor, the 
CO2 pollutant concentration monitor, the O2 or 
CO2 diluent monitor used to calculate heat input, the 
moisture monitoring system, the flow monitor, the NOX-diluent 
monitoring system and the NOX concentration monitoring system 
as follows:

[[Page 261]]

    (1) Prior to completion of 8,760 unit 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 operating hours following initial 
certification (or, for a unit with less than 8,760 unit operating hours 
three years (26,280 clock hours) after initial certification, upon 
completion of three years (26,280 clock 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.
[GRAPHIC] [TIFF OMITTED] TC13NO91.042

    (3) 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 when 
calculating percent monitor data availability using equation 8 or 9. No 
hours from more than three years (26,280 clock hours) earlier shall be 
used in equation 9. The owner or operator of a unit with an 
SO2 monitoring system shall, when SO2 emissions 
are determined in accordance with Sec. 75.11(e)(1) or (e)(2), exclude 
hours in which a unit combusts only gaseous fuel from calculations of 
percent monitor data availability for SO2 pollutant 
concentration monitors, as provided in Sec. 75.30(d).
    (b) The monitor data availability need not be calculated during the 
missing data period. The owner or operator shall record the percent 
monitor data availability for the last hour of each missing data period 
as the monitor availability used 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]



Sec. 75.33  Standard missing data procedures for SO2, NOX and flow rate.

    (a) Following initial certification (i.e., the date and time at 
which quality assured data begins to be recorded by the CEMS) and upon 
completion of the first 720 quality-assured monitor operating hours of 
the SO2 pollutant concentration monitor or the first 2,160 
quality assured monitor operating hours of the flow monitor, 
NOX-diluent monitoring system or NOX concentration 
monitoring system used to determine NOX mass emissions, the 
owner or operator shall provide substitute data required under this 
subpart according to the procedures in paragraphs (b) and

[[Page 262]]

(c) of this section and depicted in Table 1 (SO2) and Table 2 
of this section (NOX, flow). The owner or operator of a unit 
shall substitute for missing data using only quality-assured monitor 
operating hours of data from the three years (26,280 clock hours) prior 
to the date and time of the missing data period.

[[Page 263]]



 Table 1--Missing Data Procedure for SO2 CEMS, CO2 CEMS, Moisture CEMS and Diluent (CO2 or O2) Monitors for Heat
                                               Input Determination
----------------------------------------------------------------------------------------------------------------
                     Trigger conditions                                      Calculation routines
----------------------------------------------------------------------------------------------------------------
   Monitor data availability     Duration (N) of CEMS outage
           (percent)                     (hours) \2\                       Method               Lookback  period
----------------------------------------------------------------------------------------------------------------
95 or more....................  N  24              Average........................  HB/HA.
                                N > 24                        For SO2, CO2 and H2O**, the      .................
                                                               greater of:                     HB/HA.
                                                                Average......................  720 hours.*
                                                                90th percentile..............
                                ............................  For O2, and H2OX, the lesser     .................
                                                               of:                             HB/HA.
                                                                Average......................  720 hours.*
                                                                10th percentile..............
90 or more, but below 95......  N  8               Average........................  HB/HA.
                                N > 8                         For SO2, CO2 and H2O**, the      .................
                                                               greater of:                     HB/HA.
                                                                Average......................  720 hours.*
                                                                95th percentile..............
                                ............................  For O2, and H2OX, the lesser     .................
                                                               of:                             HB/HA.
                                                                Average......................  720 hours.*
                                                                5th percentile...............
80 or more, but below 90......  N > 0                         For SO2, CO2 and H2O**:........  .................
                                                                Maximum value \1\............  720 hours.*
                                ............................  For O2, and H2OX:                .................
                                                                Minimum value................  720 hours.*
Below 80......................  N > 0                         Maximum potential concentration
                                                               or % (for SO2, CO2 and H2O**)
                                                               or
                                ............................  Minimum potential concentration  None.
                                                               or % (for O2, and H2OX).
----------------------------------------------------------------------------------------------------------------
HB/HA = hour before and hour after the CEMS outage.
* = Quality-assured, monitor operating hours, during unit operation.
\1\ Where unit with add-on emission controls can demonstrate that the controls are operating properly, as
  provided in Sec.  75.34, the unit may, upon approval, use the maximum controlled emission rate from the
  previous 720 operating hours.
\2\ During unit operating hours.
X Use this algorithm for moisture except when Equation 19-3, 19-4 or 19-8 in Method 19 in appendix A 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 to part 60
  of this chapter is used for NOX emission rate.


                            Table 2.--Missing Data Procedure for NOX-Diluent CEMS, NOX Concentration CEMS and Flow Rate CEMS
--------------------------------------------------------------------------------------------------------------------------------------------------------
                         Trigger conditions                                                          Calculation routines
--------------------------------------------------------------------------------------------------------------------------------------------------------
     Monitor data availability         Duration (N) of CEMS outage
             (percent)                          (hours) 2                            Method                      Lookback period          Load  ranges
--------------------------------------------------------------------------------------------------------------------------------------------------------
95 or more........................  N  24................  Average.............................  2160 hours*..............  Yes.
                                    N > 24..........................  The greater of:                                                  .................
                                                                        Average...........................  HB/HA....................  No.
                                                                        90th percentile...................  2160 hours*..............  Yes.
90 or more, but below 95..........  N  8.................  Average.............................  2160 hours*..............  Yes.
                                    N > 8...........................  The greater of:                                                  .................

[[Page 264]]

 
                                                                        Average...........................  HB/HA....................  No.
                                                                        95th percentile...................  2160 hours*..............  Yes.
80 or more, but below 90..........  N > 0...........................  Maximum value 1.....................  2160 hours*..............  Yes.
Below 80..........................  N > 0...........................  Maximum NOX emission rate; or         None.....................  No.
                                                                       maximum potential NOX
                                                                       concentration; or maximum potential
                                                                       flow rate.
--------------------------------------------------------------------------------------------------------------------------------------------------------
HB/HA=hour before and hour after the CEMS outage.
*=Quality-assured, monitor operating hours, in the corresponding load range (``load bin'') for each hour of the missing data period.
\1\ Where unit with add-on emission controls can demonstrate that the controls are operating properly, as provided in Sec.  75.34, the unit may, upon
  approval, use the maximum controlled emission rate from the previous 720 operating hours.
\2\ During unit operating hours.


[[Page 265]]

    (b) SO2 concentration data. For each hour of missing 
SO2 concentration data,
    (1) Whenever 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 each 
hour of each 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) Whenever 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 each hour of each 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) Whenever the monitor data availability is at least 80.0 percent 
but less than 90.0 percent, the owner or operator shall substitute for 
each missing data period the maximum hourly SO2 concentration 
recorded by an SO2 pollutant concentration monitor during the 
previous 720 quality-assured monitor operating hours.
    (4) Whenever the monitor data availability is less than 80.0 
percent, the owner or operator shall substitute for each missing data 
period the maximum potential SO2 concentration, as defined in 
section 2.1.1.1 of appendix A to this part.
    (c) Volumetric flow rate, NOX emission rate and 
NOX concentration 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 the monitor or continuous emission monitoring system 
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 each hour of each missing data 
period according to the following procedures:
    (i) For a missing data period less than or equal to 24 hours, 
substitute, as applicable, for each missing hour, the arithmetic average 
of the flow rates or NOX emission rates or NOX 
concentrations recorded by a monitoring system during the previous 2,160 
quality assured monitor operating hours at the corresponding unit load 
range, 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, 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.

[[Page 266]]

    (2) Whenever the monitor or continuous emission monitoring system 
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 each hour of each 
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, 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, 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) Whenever 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 each hour of each 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, as determined using the procedure in 
section 2 of appendix C to this part.
    (4) Whenever the monitor data availability is less than 80.0 
percent, the owner or operator shall substitute, as applicable, for each 
hour of each 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.
    (5) 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 for either 
the corresponding load range or a higher load range, the owner or 
operator shall substitute, as applicable, either the maximum potential 
NOX emission rate or the maximum potential NOX 
concentration, as defined in section 2.1.2.1 of appendix A to this part 
or the maximum potential flow rate, as defined in section 2.1.4.1 of 
appendix A to this part.

[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]



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 use one of 
the following options 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 as specified for all affected units in Secs. 75.31 through 
75.33 to substitute data for each hour in which the add-on emission 
controls are operating within the proper parametric ranges specified in 
the quality assurance/quality control program for the unit, required by 
section 1 in appendix B of this part. The designated representative 
shall document in the quality assurance/ quality control program the 
ranges of the add-on emission control operating

[[Page 267]]

parameters that indicate proper operation of the controls. The owner or 
operator shall, for each missing data period, record 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. In addition, under Sec. 75.64(c), the designated representative 
shall submit a certified verification of the proper operation of the 
SO2 or NOX add-on emission control for each 
missing data period at the end of each quarter.
    (2) The designated representative may petition the Administrator 
under Sec. 75.66 to replace the maximum recorded value in the last 720 
quality-assured monitor operating hours with a value corresponding to 
the maximum controlled emission rate (an emission rate recorded when the 
add-on emission controls were operating) recorded during the last 720 
quality-assured monitor operating hours. For such a petition, the 
designated representative must demonstrate that the following conditions 
are met: the monitor data availability, calculated in accordance with 
Sec. 75.32, for the affected unit is below 90.0 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) during the time period under 
petition.
    (3) 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. 75.55(b) or Sec. 75.58(b), as applicable.
    (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 Secs. 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 NOX2 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) The owner or operator shall keep records of information as 
described in subpart F of this part to verify the proper operation of 
the SO2 or NOX emission controls during all 
periods of SO2 or NOX emission missing data. The 
owner or operator shall provide these records to the Administrator or to 
the EPA Regional Office upon request. Whenever such data are not 
provided or such data do not demonstrate that

[[Page 268]]

proper operation of the SO2 or NOX add-on emission 
controls has been maintained in accordance with the range of add-on 
emission control operating parameters reported in the quality assurance/
quality control program for the unit, the owner or operator shall 
substitute the maximum potential NOX emission rate, as 
defined in Sec. 72.2 of this chapter, to report the NOX 
emission rate, and either the maximum hourly SO2 
concentration recorded by the inlet monitor during the previous 720 
quality-assured monitor operating hours, if available, or the maximum 
potential concentration for SO2, as defined by section 
2.1.1.1. of appendix A of this part, to report SO2 
concentration for each hour of missing data until information 
demonstrating proper operation of the SO2 or NOX 
emission controls is available.

[60 FR 26567, May 17, 1995, as amended at 61 FR 59160, Nov. 20, 1996; 64 
FR 28604, May 26, 1999]



Sec. 75.35  Missing data procedures for CO2 data.

    (a) On and after April 1, 2000, the owner or operator of a unit with 
a CO2 continuous emission monitoring system for determining 
CO2 mass emissions in accordance with Sec. 75.10 (or an 
O2 monitor that is used to determine CO2 
concentration in accordance with appendix F to this part) shall 
substitute for missing CO2 pollutant concentration data using 
the procedures of paragraphs (b) and (d) of this section. The procedures 
of paragraphs (b) and (d) of this section shall also be used on and 
after April 1, 2000 to provide substitute CO2 data for heat 
input determination. Prior to April 1, 2000, the owner or operator shall 
substitute for missing CO2 data using either the procedures 
of paragraphs (b) and (c), or paragraphs (b) and (d) of this section.
    (b) During the first 720 quality assured monitor operating hours 
following initial certification (i.e., the date and time at which 
quality assured data begins to be recorded by the CEMS), of the 
CO2 continuous emission monitoring system, or (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) Upon completion of the first 720 quality-assured monitor 
operating hours following initial certification of the CO2 
continuous emission monitoring system, the owner or operator shall 
provide substitute data for CO2 concentration or 
CO2 mass emissions required under this subpart according to 
the procedures in paragraphs (c)(1), (c)(2), or (c)(3) of this section, 
including CO2 data calculated from O2 measurements 
using the procedures in appendix F of this part.
    (1) Whenever a quality-assured monitoring operating hour of 
CO2 concentration data has not been obtained and recorded for 
a period less than or equal to 72 hours or for a missing data period 
where the percent monitor data availability for the CO2 
continuous emission monitoring system as of the last unit operating hour 
of the previous calendar quarter was greater than or equal to 90.0 
percent, then the owner or operator shall substitute the average of the 
recorded CO2 concentration for the hour before and the hour 
after the missing data period for each hour in each missing data period.
    (2) Whenever no quality-assured CO2 concentration data 
are available for a period of 72 consecutive unit operating hours or 
more, the owner or operator shall begin substituting CO2 mass 
emissions calculated using the procedures in appendix G of this part 
beginning with the seventy-third hour of the missing data period until 
quality-assured CO2 concentration data are again available. 
The owner or operator shall use the CO2 concentration from 
the hour before the missing data period to substitute for hours 1 
through 72 of the missing data period.
    (3) Whenever no quality-assured CO2 concentration data 
are available for a period where the percent monitor data availability 
for the CO2 continuous emission monitoring system as of the 
last unit operating hour of the previous calendar quarter was less than 
90.0 percent, the owner or operator shall substitute CO2 mass 
emissions calculated

[[Page 269]]

using the procedures in appendix G of this part for each hour of the 
missing data period until quality-assured CO2 concentration 
data are again available.
    (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 
data 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'' and the term ``CO2 pollutant 
concentration monitor'' or ``COE2 diluent monitor'' shall 
apply rather than ``SO2 pollutant concentration monitor.''

[60 FR 26529, May 17, 1995, as amended at 64 FR 28604, May 26, 1999]



Sec. 75.36  Missing data procedures for heat input determinations.

    (a) When hourly heat input 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 calculation shall be provided 
according to Sec. 75.31 or Sec. 75.33, as applicable. On and after April 
1, 2000, when diluent gas data are unavailable, the owner or operator 
shall provide substitute O2 or CO2 data for the 
heat input calculations in accordance with paragraphs (b) and (d) of 
this section. Prior to April 1, 2000, the owner or operator shall 
substitute for missing CO2 or O2 concentration 
data in accordance with either paragraphs (c) and (d) or paragraphs (b) 
and (d) of this section.
    (b) During the first 720 quality assured monitor operating hours 
following initial certification (i.e., the date and time at which 
quality assured data begins to be recorded by the CEMS), or (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) Upon completion of the first 720 quality-assured monitor 
operating hours following initial certification of the CO2 
(or O2) pollutant concentration monitor, the owner or operator shall 
provide substitute data for CO2 or O2 
concentration to calculate heat input or shall substitute heat input 
determined under appendix F of this part according to the procedures in 
paragraphs (c)(1), (c)(2), or (c)(3) of this section. Upon completion of 
2,160 quality-assured monitor operating hours following initial 
certification of the flow monitor, the owner or operator shall provide 
substitute data for volumetric flow according to the procedures in 
Sec. 75.33 in order to calculate heat input, unless required to 
determine heat input using the fuel sampling procedures in appendix F of 
this part under paragraphs (c)(1), (c)(2) or (c)(3) of this section.
    (1) Whenever a quality-assured monitor operating hour of 
CO2 or O2 concentration data has not been obtained 
and recorded for a period less than or equal to 72 hours or for a 
missing data period where the percent monitor data availability for the 
CO2 or O2 pollutant concentration monitor as of 
the last unit operating hour of the previous calendar quarter was 
greater than or equal to 90.0 percent, the owner or operator shall 
substitute the average of the recorded CO2 or O2 
concentration for the hour before and the hour after the missing data 
period for each hour in each missing data period to calculate heat 
input.
    (2) Whenever a quality-assured monitor operating hour of 
CO2 or O2 concentration data has not been obtained 
and recorded for a period of 72 consecutive unit operating hours or 
more, the owner or operator shall begin substituting heat input 
calculated using the procedures in section 5.5 of appendix F of this 
part beginning with the seventy-third hour of the missing data period 
until quality-assured CO2 or O2 concentration data 
are again available. The owner or operator shall use the CO2 
or O2 concentration from the hour

[[Page 270]]

before the missing data period to substitute for hours 1 through 72 of 
the missing data period.
    (3) Whenever no quality-assured CO2 or O2 
concentration data are available for a period where the percent monitor 
data availability for the CO2 continuous emission monitoring 
system (or O2 diluent monitor) as of the last unit operating 
hour of the previous calendar quarter was less than 90.0 percent, the 
owner or operator shall substitute heat input calculated using the 
procedures in section 5.5 of appendix F of this part for each hour of 
the missing data period until quality-assured CO2 or 
O2 concentration data are again available.
    (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, as follows. 
Substitute CO2 data for heat input determinations shall be 
provided according to Sec. 75.35(d). Substitute O2 data for 
the heat input determinations shall be provided in accordance with the 
procedures in Sec. 75.33(b), except that the term ``O2 
concentration'' shall apply rather than the term ``SO2 
concentration'' and the term ``O2 diluent monitor'' shall 
apply rather than the term ``SO2 pollutant concentration 
monitor.'' In addition, the term ``substitute the lesser of'' shall 
apply rather than ``substitute the greater of;'' the terms ``minimum 
hourly O2 concentration'' and ``minimum potential 
O2 concentration, as determined under section 2.1.3.2 of 
appendix A to this part'' shall apply rather than, respectively, the 
terms ``maximum hourly SO2 concentration'' and ``maximum 
potential SO2 concentration, as determined under section 
2.1.1.1 of appendix A to this part;'' and the terms ``10th percentile'' 
and ``5th percentile'' shall apply rather than, respectively, the terms 
``90th percentile'' and ``95th percentile'' (see Table 1 of Sec. 75.33).

[60 FR 26530, May 17, 1995, as amended at 64 FR 28604, May 26, 1999]



Sec. 75.37  Missing data procedures for moisture.

    (a) On and after April 1, 2000, 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. Prior to April 1, 
2000, the owner or operator may 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 (i.e., the date and time at which 
quality assured data begins to be recorded by the moisture monitoring 
system), 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 of the moisture 
monitoring system, 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

[[Page 271]]

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'' and the term ``moisture monitoring 
system'' shall apply rather than ``SO2 pollutant 
concentration monitor;'' 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]



                Subpart E--Alternative Monitoring Systems



Sec. 75.40  General demonstration requirements.

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



Sec. 75.41  Precision criteria.

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

[[Page 272]]

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,

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

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


[[Page 273]]


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 =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, , computed from an AR(1) 
autoregression model, such that:
[GRAPHIC] [TIFF OMITTED] TC01SE92.101


(Eq. 13)

where,

x'i = The original data value at hour i.
x"i = The LAG1 data value at hour i.
COV(x'i, x"i) = The autocovariance of x'i 
and defined by,

[GRAPHIC] [TIFF OMITTED] TC01SE92.102


(Eq. 14)

where,

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

[GRAPHIC] [TIFF OMITTED] TC01SE92.103


(Eq. 15)

where,

s"x i = The standard deviation of the LAG1 data values, 
x"i, defined by


[[Page 274]]


[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, , 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, , 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, S2, may be adjusted using the following 
equation:

S2adj = VIF  x  S2

(Eq. 20)

where,

S2 = The original, unadjusted variance of the data set.
VIF = The variance inflation factor, defined by

[GRAPHIC] [TIFF OMITTED] TC01SE92.108


(Eq. 21)

S2adj = The autocorrelation-adjusted variance for the data 
set.

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

[[Page 275]]

[GRAPHIC] [TIFF OMITTED] TC01SE92.109


where
[GRAPHIC] [TIFF OMITTED] TC01SE92.110

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


(Eq. 23)

where,

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

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


(Eq. 24)


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

[[Page 276]]

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] TR08AU95.066


(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]



Sec. 75.42  Reliability criteria.

    To demonstrate reliability equal to or better than the continuous 
emission monitoring system, the owner or operator shall demonstrate that 
the alternative monitoring system is capable of providing valid 1-hr 
averages for 95.0 percent or more of unit operating hours over a 1-yr 
period and that the system meets the applicable requirements of appendix 
B of this part.



Sec. 75.43  Accessibility criteria.

    To demonstrate accessibility equal to or better than the continuous 
emission monitoring system, the owner or operator shall provide reports 
and onsite records of emission data to demonstrate that the alternative 
monitoring system provides data meeting the requirements of subparts F 
and G of this part.



Sec. 75.44  Timeliness criteria.

    To demonstrate timeliness equal to or better than the continuous 
emission monitoring system, the owner or operator shall demonstrate that 
the alternative monitoring system can meet the requirements of subparts 
F and G of this part; can provide a continuous, 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.

[[Page 277]]



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.
    (4) Data plots, specified in Secs. 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.

[[Page 278]]

    (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. 75.50-75.52  [Reserved]



Sec. 75.53  Monitoring plan.

    (a) General provisions. (1) The provisions of paragraphs (c) and (d) 
of this section shall remain in effect prior to April 1, 2000. The owner 
or operator shall meet the requirements of either paragraphs (a) through 
(d) or paragraphs (a), (b), (e) and (f) of this section prior to April 
1, 2000. On and after April 1, 2000, the owner or operator shall meet 
the requirements of paragraphs (a), (b), (e) and (f) of this section 
only. In addition, the provisions in paragraphs (e) and (f) 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 
April 1, 2000.
    (2) The owner or operator of an affected unit shall prepare and 
maintain a monitoring plan. Except as provided in paragraphs (d) or (f) 
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.
    (c) Contents of the monitoring plan. Each monitoring plan shall 
contain the following:
    (1) Precertification information, including, as applicable, the 
identification of the test strategy, protocol for the relative accuracy 
test audit, other relevant test information, span calculations, and 
apportionment strategies under Secs. 75.10 through 75.18 of this part.
    (2) Unit table. A table identifying ORISPL numbers developed by the 
Department of Energy and used in the National Allowance Database, for 
all affected units involved in the monitoring plan, with the following 
information for each unit:
    (i) Short name;
    (ii) Classification of unit as one of the following: Phase I 
(including substitution or compensating units), Phase II, new, or 
nonaffected;
    (iii) Type of boiler (or boilers for a group of units using a common 
stack);
    (iv) Type of fuel(s) fired, by boiler, and if more than one fuel, 
the fuel classification of the boiler;
    (v) Type(s) of emission controls for SO2, NOx, 
and particulates installed or to be installed, including specifications 
of whether such controls are pre-combustion, post-combustion, or 
integral to the combustion process; and
    (vi) Identification of all units using a common stack.
    (3) Description of monitor site location. 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 (c)(7) and (c)(8) of this section, and 
any other documentation that demonstrates each monitor location meets 
the appropriate siting criteria.

[[Page 279]]

    (4) Monitoring component table. Identification and description of 
each monitoring component (including each monitor and its identifiable 
components such as analyzer and/or probe) in the continuous emission 
monitoring systems (i.e., SO2 pollutant concentration 
monitor, flow monitor, moisture monitor; NOX pollutant 
concentration monitor and diluent gas monitor) the continuous opacity 
monitoring system, or excepted monitoring system (i.e., fuel flowmeter, 
data acquisition and handling system), including:
    (i) Manufacturer model number and serial number;
    (ii) Component/system identification code assigned by the utility to 
each identifiable monitoring component (such as the analyzer and/or 
probe). The code shall use a six-digit format, unique to each monitoring 
component, where the first three digits indicate the number of the 
component and the second three digits indicate the system to which the 
component belongs;
    (iii) Actual or projected installation date (month and year);
    (iv) A brief description of the component type or method of 
operation, such as in situ pollutant concentration monitor or thermal 
flow monitor;
    (v) A brief description of the flow monitor that is sufficiently 
detailed to allow a determination of whether the applicable interference 
check design specification meets the requirements specified in appendix 
A of this part; and
    (vi) A designation of the system as a primary, redundant backup, 
non-redundant backup or reference method backup system, as provided for 
in Sec. 75.10(e).
    (5) Data acquisition and handling system table. Identification and 
description of all major hardware and software components of the 
automated data acquisition and handling system, including:
    (i) For hardware components, the manufacturer, model number, and 
actual or projected installation date;
    (ii) For software components, identification of the provider and a 
brief description of features;
    (iii) A data flow diagram denoting the complete information handling 
path from output signals of continuous emission monitoring system 
components to final reports;
    (iv) A copy of the test results verifying the accuracy of the 
automated data acquisition and handling system (once such results are 
available).
    (6) Emissions formula table. A table giving explicit formulas for 
each reported unit emission parameter, using component/system 
identification codes to link continuous emission monitoring system or 
excepted monitoring system observations with reported concentrations, 
mass emissions, or emission rates, according to the conversions listed 
in appendix D, E, or F to this part. The formulas must contain all 
constants and factors required to derive mass emissions or emission 
rates from component/system code observations, and each emissions 
formula is identified with a unique three digit code.
    (7) Schematic stack diagrams. 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 
(c)(2), (c)(4), (c)(5), and (c)(6) 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.
    (8) Stack and duct engineering diagrams. 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 which affects the monitoring 
system location, performance or quality control checks.
    (9) Inside crosssectional area (ft \2\) at flue exit and at flow 
monitoring location.
    (10) Span and calibration gas. A table or description identifying 
maximum potential concentration, maximum expected concentration (if 
applicable),

[[Page 280]]

maximum potential flow rate, maximum potential NOX emission 
rate, span value, and full-scale range for each SO2, 
NOX, CO2, O2, or flow component 
monitor. In addition, the table must identify calibration gas levels for 
the calibration error test and the linearity check, and calculations 
made to determine each span value.
    (d) Contents of monitoring plan for specific situations. The 
following additional information shall be included in the monitoring 
plan for gas-fired or oil-fired units:
    (1) For each gas-fired unit or oil-fired unit for which the owner or 
operator uses the optional protocol in appendix D of this part for 
estimating SO2 mass emissions or appendix E of this part for 
estimating NOX emission rate (using a fuel flow meter), the 
designated representative shall include in the monitoring plan:
    (i) A description of the fuel flowmeter (and data demonstrating its 
flow meter accuracy, when available);
    (ii) The installation location of each fuel flowmeter;
    (iii) The fuel sampling location(s); and
    (iv) Procedures used for calibrating each fuel flowmeter.
    (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 
of this part for estimating NOX emission rate, the designated 
representative shall include in the monitoring plan:
    (i) A protocol containing methods used to perform the baseline or 
periodic NOX emission test, and a copy of initial performance 
test results (when such results are available);
    (ii) Unit operating and capacity factor information demonstrating 
that the unit qualifies as a peaking unit, as defined in Sec. 72.2 of 
this chapter; and
    (iii) 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 monitoring plan 
information demonstrating that the unit qualifies for the exemption.
    (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, for all affected 
units involved in the monitoring plan, with the following information 
for each unit:
    (A) Short name;
    (B) Classification of the unit as one of the following: Phase I 
(including substitution or compensating units), Phase II, new, or 
nonaffected;
    (C) Type of boiler (or boilers for a group of units using a common 
stack);
    (D) Type of fuel(s) fired by boiler, fuel type start and end dates, 
primary/secondary fuel indicator, and, if more than one fuel, the fuel 
classification of the boiler;
    (E) Type(s) of emission controls for SO2, NOX, 
and particulates installed or to be installed, including specifications 
of whether such controls are pre-combustion, post-combustion, or 
integral to the combustion process; control equipment code, installation 
date, and optimization date; control equipment retirement date (if 
applicable); 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.

[[Page 281]]

    (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 and diluent gas monitor), the continuous 
opacity monitoring system, or the excepted monitoring system (e.g., fuel 
flowmeter, data acquisition and handling system), including:
    (A) Manufacturer, model number and serial number;
    (B) Component/system identification code assigned by the utility to 
each identifiable monitoring component (such as the analyzer and/or 
probe). Each code shall use a three-digit format, unique to each 
monitoring component and unique to each monitoring system;
    (C) Designation of the component type and method of sample 
acquisition or operation, (e.g., in situ pollutant concentration monitor 
or thermal flow monitor);
    (D) Designation of the system as a primary, redundant backup, non-
redundant backup, data backup, or reference method backup system, as 
provided in Sec. 75.10(e);
    (E) First and last dates the system reported data;
    (F) Status of the monitoring component; and
    (G) Parameter monitored.
    (v) Identification and description of all major hardware and 
software components of the automated data acquisition and handling 
system, including:
    (A) Hardware components that perform emission calculations or store 
data for quarterly reporting purposes (provide the manufacturer and 
model number); and
    (B) Software components (provide the identification of the provider 
and model/version number).
    (vi) Explicit formulas for each measured emission parameter, using 
component/system identification codes for the primary system used to 
measure the parameter that links CEMS or excepted monitoring system 
observations with reported concentrations, mass emissions, or emission 
rates, according to the conversions listed in appendix D or E to this 
part. Formulas for backup monitoring systems are required only if 
different formulas for the same parameter are used for the primary and 
backup monitoring systems (e.g., if the primary system measures 
pollutant concentration on a different moisture basis from the backup 
system). The formulas must contain all constants and factors required to 
derive mass emissions or emission rates from component/system code 
observations and an indication of whether the formula is being added, 
corrected, deleted, or is unchanged. Each emissions formula is 
identified with a unique three digit code. The owner or operator of a 
low mass emissions unit for which the owner or operator is using the 
optional low mass emissions excepted methodology in Sec. 75.19(c) is not 
required to report such formulas.
    (vii) Inside cross-sectional area (ft2) at flue exit (for 
all units) and at flow monitoring location (for units with flow 
monitors, only).
    (viii) Stack height (ft) above ground level and stack base elevation 
above sea level.
    (ix) Part 75 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

[[Page 282]]

identification number, flue identification number, boiler identification 
number, reporting year, and 767 reporting indicator.
    (x) For each parameter monitored: scale, maximum potential 
concentration (and method of calculation), maximum expected 
concentration (if applicable) (and method of calculation), maximum 
potential flow rate (and method of calculation), maximum potential 
NOX emission rate, span value, full-scale range, daily 
calibration units of measure, span effective date/hour, span 
inactivation date/hour, indication of whether dual spans are required, 
default high range value, flow rate span, and flow rate span value and 
full scale value (in scfh) for each unit or stack using SO2, 
NOX, CO2, O2, or flow component 
monitors.
    (xi) If the monitoring system or excepted methodology provides for 
the use of a constant, assumed, or default value for a parameter under 
specific circumstances, then include the following information for each 
such value for each parameter:
    (A) Identification of the parameter;
    (B) Default, maximum, minimum, or constant value, and units of 
measure for the value;
    (C) Purpose of the value;
    (D) Indicator of use during controlled/uncontrolled hours;
    (E) Type of fuel;
    (F) Source of the value;
    (G) Value effective date and hour;
    (H) Date and hour value is no longer effective (if applicable); and
    (I) For units using the excepted methodology under Sec. 75.19, the 
applicable SO2 emission factor.
    (xii) For each unit or common stack (except for peaking units) 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;
    (B) The load 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;
    (C) The two load 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 load analysis used to determine the normal load 
level(s) and the two most frequently-used load levels; and
    (E) Activation and deactivation dates, when the normal load level(s) 
or two most frequently-used load levels change and are updated.
    (xiii) For each unit for which the optional fuel flow-to-load test 
in section 2.1.7 of appendix D to this part is used:
    (A) The upper and lower boundaries of the range of operation (as 
defined in section 6.5.2.1 of appendix A to this part), expressed in 
megawatts or thousands of lb/hr of steam;
    (B) The load level designated as normal, pursuant to section 6.5.2.1 
of appendix A to this part, expressed in megawatts or thousands of lb/hr 
of steam; and
    (C) The date of the load analysis used to determine the normal load 
level.
    (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 Secs. 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,

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monitor components, and stacks corresponding to the identification 
numbers provided in paragraphs (e)(1)(i), (e)(1)(iv), (e)(1)(vi), and 
(e)(1)(ix) of this section. The schematic diagram must depict stack 
height and the height of any monitor locations. Comprehensive and/or 
separate schematic diagrams shall be used to describe groups of units 
using a common stack.
    (v) For units monitored by a continuous emission or opacity 
monitoring system, stack and duct engineering diagrams showing the 
dimensions and location of fans, turning vanes, air preheaters, monitor 
components, probes, reference method sampling ports, and other equipment 
that affects the monitoring system location, performance, or quality 
control checks.
    (f) Contents of monitoring plan for specific situations. The 
following additional information shall be included in the monitoring 
plan for the specific situations described:
    (1) For each gas-fired unit or oil-fired unit for which the owner or 
operator uses the optional protocol in appendix D to this part for 
estimating heat input and/or SO2 mass emissions, or for each 
gas-fired or oil-fired peaking unit for which the owner/operator uses 
the optional protocol in appendix E to this part for estimating 
NOX emission rate (using a fuel flowmeter), the designated 
representative shall include the following additional information in the 
monitoring plan:
    (i) Electronic.
    (A) Parameter monitored;
    (B) Type of fuel measured, maximum fuel flow rate, units of measure, 
and basis of maximum fuel flow rate (i.e., upper range value or unit 
maximum) for each fuel flowmeter;
    (C) Test method used to check the accuracy of each fuel flowmeter;
    (D) Submission status of the data;
    (E) Monitoring system identification code; and
    (F) For gaseous fuels fired by the unit, the method used to verify 
that the fuel meets the definition in Sec. 72.2 of pipeline natural gas 
or natural gas, if applicable, and the demonstration methods used for 
other gaseous fuels, if applicable, to determine the appropriate 
frequency for sampling for GCV or sulfur content of the fuel.
    (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 values and corresponding NOX 
rates;
    (G) Type of fuel; and
    (H) To document the unit qualifies as a peaking unit, current 
calendar year, capacity factor data as specified in the definition of 
peaking unit in Sec. 72.2 of this part, and an indication of whether the 
data are actual or projected data.

[[Page 284]]

    (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:
    (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 and the emissions calculated using the 
methodology which will be used by the unit to estimate future emissions.
    (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 natural gas or fuel oil and 
a list of the fuels that are burned or a statement that the unit is 
projected to burn only natural gas 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 Secs. 75.19(a) and (b); and
    (E) Any unit historical actual and projected emissions data and 
calculated emissions data demonstrating that the affected unit qualifies 
as a low mass emissions unit under Secs. 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.

[58 FR 3701, Jan. 11, 1993, as amended at 60 FR 26532, 26568, May 17, 
1995; 61 FR 59161, Nov. 20, 1996; 64 FR 28605, May 26, 1999]



Sec. 75.54  General recordkeeping provisions.

    (a) Recordkeeping requirements for affected sources. On and after 
January 1, 1996, and before April 1, 2000, the owner or operator shall 
meet the requirements of either this section or Sec. 75.57. On and after 
April 1, 2000, the owner or operator shall meet the requirements of 
Sec. 75.57. The owner or operator of any affected source subject to the 
requirements of this part shall maintain for each affected unit a file 
of all measurements, data, reports, and other information required by 
this part at the source in a form suitable for inspection for at least 
three (3) years from the date of each record. Unless otherwise provided, 
throughout this subpart the

[[Page 285]]

phrase ``for each affected unit'' also applies to each group of affected 
or nonaffected units utilizing a common stack and common monitoring 
systems, pursuant to Secs. 75.16 through 75.18, or utilizing a common 
pipe header and common fuel flowmeter, pursuant to section 2.1.2 of 
appendix D to this part. The file shall contain the following 
information:
    (1) The data and information required in paragraphs (b) through (g) 
of this section, beginning with the earlier of the date of provisional 
certification, or the deadline in Sec. 75.4(a), (b) or (c);
    (2) The supporting data and information used to calculate values 
required in paragraphs (b) through (f) of this section, excluding the 
subhourly data points used to compute hourly averages under 
Sec. 75.10(d), beginning with the earlier of the date of provisional 
certification, or the deadline in Sec. 75.4(a), (b) or (c);
    (3) The data and information required in Sec. 75.55 of this part for 
specific situations, as applicable, beginning with the earlier of the 
date of provisional certification, or the deadline in Sec. 75.4(a), (b) 
or (c);
    (4) The certification test data and information required in 
Sec. 75.56 for tests required under Sec. 75.20, beginning with the date 
of the first certification test performed, and the quality assurance and 
quality control data and information required in Sec. 75.56 for tests 
and the quality assurance/quality control plan required under Sec. 75.21 
and appendix B of this part, beginning with the date of provisional 
certification;
    (5) The current monitoring plan as specified in Sec. 75.53, 
beginning with the initial submission required by Sec. 75.62; and
    (6) The quality control plan as described in appendix B to this 
part, beginning with the date of provisional certification.
    (b) Operating parameter record provisions. The owner or operator 
shall record for each hour the following information on unit operating 
time, heat input, and load separately for each affected unit, and also 
for each group of units utilizing a common stack and a common monitoring 
system or utilizing a common pipe header and common fuel flowmeter, 
except that separate heat input data for each unit shall not be required 
after January 1, 2000 for any unit, other than an opt-in source, that 
does not have a NOX emission limitation under part 76 of this 
chapter.
    (1) Date and hour;
    (2) Unit operating time (rounded up to nearest 15 minutes);
    (3) Total hourly gross unit load (rounded to nearest MWge) (or steam 
load in lb/hr at stated temperature and pressure, rounded to the nearest 
1000 lb/hr, if elected in the monitoring plan);
    (4) Operating load range corresponding to total gross load of 1-10, 
except for units using a common stack or common pipe header, which may 
use the number of unit load ranges up to 20 for flow, as specified in 
the monitoring plan; and
    (5) Total heat input (mmBtu, rounded to the nearest tenth).
    (c) SO2 emission record provisions. The owner or operator 
shall record for each hour the information required by this paragraph 
for each affected unit or group of units using a common stack and common 
monitoring systems, except as provided under Sec. 75.11(e) or for a gas-
fired or oil-fired unit for which the owner or operator is using the 
optional protocol in appendix D to this part for estimating 
SO2 mass emissions:
    (1) For SO2 concentration, as measured and reported from 
each certified primary monitor, certified back-up monitor, or other 
approved method of emissions determination:
    (i) Component-system identification code as provided for in 
Sec. 75.53;
    (ii) Date and hour;
    (iii) Hourly average SO2 concentration (ppm, rounded to 
the nearest tenth);
    (iv) Hourly average SO2 concentration (ppm, rounded to 
the nearest tenth) adjusted for bias, if bias adjustment factor is 
required as provided for in Sec. 75.24(d);
    (v) Percent monitor data availability (recorded to the nearest tenth 
of a percent) calculated pursuant to Sec. 75.32; and
    (vi) Method of determination for hourly average SO2 
concentration using Codes 1-15 in table 4 of this section.
    (2) For flow as measured and reported from each certified primary 
monitor,

[[Page 286]]

certified back-up monitor or other approved method of emissions 
determination:
    (i) Component/system identification code as provided for in 
Sec. 75.53;
    (ii) Date and hour;
    (iii) Hourly average volumetric flow rate (in scfh, rounded to the 
nearest thousand);
    (iv) Hourly average volumetric flow rate (in scfh, rounded to the 
nearest thousand) adjusted for bias, if bias adjustment factor required 
as provided for in Sec. 75.24(d);
    (v) Hourly average moisture content of flue gases (percent, rounded 
to the nearest tenth) where SO2 concentration is measured on 
dry basis;
    (vi) Percent monitor data availability (recorded to the nearest 
tenth of a percent), calculated pursuant to Sec. 75.32; and
    (vii) Method of determination for hourly average flow rate using 
Codes 1-15 in table 4.
    (3) For SO2 mass emissions as measured and reported from 
the certified primary monitoring system(s), certified redundant or non-
redundant back-up monitoring system(s), or other approved method(s) of 
emissions determination:
    (i) Date and hour;
    (ii) Hourly SO2 mass emissions (lb/hr, rounded to the 
nearest tenth);
    (iii) Hourly SO2 mass emissions (lb/hr, rounded to the 
nearest tenth) adjusted for bias, if bias adjustment factor required, as 
provided for in Sec. 75.24(d); and
    (iv) Identification code for emissions formula used to derive hourly 
SO2 mass emissions from SO2 concentration and flow 
data in paragraphs (c)(1) and (c)(2) of this section as provided for in 
Sec. 75.53.

      Table 4--Codes for Method of Emissions and Flow Determination
------------------------------------------------------------------------
                                    Hourly emissions/flow measurement or
               Code                          estimation method
------------------------------------------------------------------------
  1..............................  Certified primary emission/flow
                                    monitoring system.
  2..............................  Certified back-up emission/flow
                                    monitoring system.
  3..............................  Approved alternative monitoring
                                    system.
  4..............................  Reference method:
                                       SO2: Method 6C.
                                       Flow: Method 2.
                                       NOX: Method 7E.
                                       CO2 or O2: Method 3A.
  5..............................  For units with add-on SO2 and/or NOX
                                    emission controls: SO2 concentration
                                    or NOX emission rate estimate from
                                    Agency preapproved parametric
                                    monitoring method.
  6..............................  Average of the hourly SO2
                                    concentrations, CO2 concentrations,
                                    flow, or NOX emission rate for the
                                    hour before and the hour following a
                                    missing data period.
  7..............................  Hourly average SO2 concentration, CO2
                                    concentration, flow rate, or NOX
                                    emission rate using initial missing
                                    data procedures.
  8..............................  90th percentile hourly SO2
                                    concentration, flow rate, or NOX
                                    emission rate.
  9..............................  95th percentile hourly SO2
                                    concentration, flow rate, or NOX
                                    emission rate.
10...............................  Maximum hourly SO2 concentration,
                                    flow rate, or NOX emission rate.
11...............................  Hourly average flow rate or NOX
                                    emission rate in corresponding load
                                    range.
12...............................  Maximum potential concentration of
                                    SO2, maximum potential flow rate, or
                                    maximum potential NOX emission rate,
                                    as determined using section 2.1 of
                                    appendix A of this part, or maximum
                                    CO2 concentration.
13...............................  Other data (specify method).
14...............................  Minimum CO2 concentration of 5.0
                                    percent CO2 or maximum O2
                                    concentration of 14.0 percent to be
                                    substituted optionally for measured
                                    diluent gas concentrations during
                                    unit startup, for NOX emission rate
                                    or SO2 emission rate in lb/mmBtu or
                                    for CO2 concentration.
15...............................  Fuel analysis data from appendix G of
                                    this part for CO2 mass emissions.
------------------------------------------------------------------------

    (d) NOX emission record provisions. The owner or operator 
shall record the information required by this paragraph for each 
affected unit for each hour, except for a gas-fired peaking unit or oil-
fired peaking unit for which the owner or operator is using the optional 
protocol in appendix E to this part for estimating NOX 
emission rate. For each NOX emission rate as measured and 
reported from the certified primary monitor, certified back-up monitor, 
or other approved method of emissions determination:
    (1) Component/system identification code as provided for in 
Sec. 75.53;
    (2) Date and hour;
    (3) Hourly average NOX concentration (ppm, rounded to the 
nearest tenth);
    (4) Hourly average diluent gas concentration (percent O2 
or percent CO2, rounded to the nearest tenth);
    (5) Hourly average NOX emission rate (lb/mmBtu, rounded 
to nearest hundredth);

[[Page 287]]

    (6) Hourly average NOX emission rate (lb/mmBtu, rounded 
to nearest hundredth) adjusted for bias, if bias adjustment factor is 
required as provided for in Sec. 75.24(d);
    (7) Percent monitoring system data availability, (recorded to the 
nearest tenth of a percent), calculated pursuant to Sec. 75.32;
    (8) Method of determination for hourly average NOX 
emission rate using Codes 1-15 in table 4; and
    (9) Identification code for emissions formula used to derive hourly 
average NOX emission rate, as provided for in Sec. 75.53.
    (e) CO2emission record provisions. The owner or operator 
shall record or calculate CO2 emissions for each affected 
unit using one of the following methods specified in this section:
    (1) If the owner or operator chooses to use a CO2 
continuous emission monitoring system (including an O2 
monitor and flow monitor as specified in appendix F of this part), then 
the owner or operator shall record for each hour the following 
information for CO2 mass emissions, as measured and reported 
from the certified primary monitor, certified back-up monitor, or other 
approved method of emissions determination:
    (i) Component/system identification code as provided for in 
Sec. 75.53;
    (ii) Date and hour;
    (iii) Hourly average CO2 concentration (in percent, 
rounded to the nearest tenth);
    (iv) Hourly average volumetric flow rate (scfh, rounded to the 
nearest thousand scfh);
    (v) Hourly CO2 mass emissions (tons/hr, rounded to the 
nearest tenth);
    (vi) Percent monitor data availability (recorded to the nearest 
tenth of a percent); calculated pursuant to Sec. 75.32;
    (vii) Method of determination for hourly CO2 mass 
emissions using Codes 1-15 in table 4; and
    (viii) Identification code for emissions formula used to derive 
average hourly CO2 mass emissions, as provided for in 
Sec. 75.53.
    (2) As an alternative to Sec. 75.54(e)(1), the owner or operator may 
use the procedures in Sec. 75.13 and in appendix G to this part, and 
shall record daily the following information for CO2 mass 
emissions:
    (i) Date;
    (ii) Daily combustion-formed CO2 mass emissions (tons/
day, rounded to the nearest tenth);
    (iii) For coal-fired units, flag indicating whether optional 
procedure to adjust combustion-formed CO2 mass emissions for 
carbon retained in flyash has been used and, if so, the adjustment;
    (iv) For a unit with a wet flue gas desulfurization system or other 
controls generating CO2, daily sorbent-related CO2 
mass emissions (tons/day, rounded to the nearest tenth); and
    (v) For a unit with a wet flue gas desulfurization system or other 
controls generating CO2, total daily CO2 mass 
emissions (tons/day, rounded to the nearest tenth) as sum of combustion-
formed emissions and sorbent-related emissions.
    (f) Opacity records. The owner or operator shall record opacity data 
as specified by the State or local air pollution control agency. If the 
State or local air pollution control agency does not specify 
recordkeeping requirements for opacity, then record the information 
required by paragraphs (f) (1) through (5) of this section for each 
affected unit, except as provided for in Sec. 75.14 (b), (c), and (d). 
The owner or operator shall also keep records of all incidents of 
opacity monitor downtime during unit operation, including reason(s) for 
the monitor outage(s) and any corrective action(s) taken for opacity, as 
measured and reported by the continuous opacity monitoring system:
    (1) Component/system identification code;
    (2) Date, hour, and minute;
    (3) Average opacity of emissions for each six minute averaging 
period (in percent opacity);
    (4) If the average opacity of emissions exceeds the applicable 
standard, then a code indicating such an exceedance has occurred; and
    (5) Percent monitor data availability, recorded to the nearest tenth 
of a percent, calculated according to the requirements of the procedure 
recommended for State Implementation Plans in appendix M of part 51 of 
this chapter.

[[Page 288]]

    (g) Missing data records. The owner or operator shall record the 
causes of any missing data periods and the actions taken by the owner or 
operator to cure such causes.

[60 FR 26533, May 17, 1995, as amended at 64 FR 28608, May 26, 1999]



Sec. 75.55  General recordkeeping provisions for specific situations.

    Before April 1, 2000, the owner or operator shall meet the 
requirements of either this section or Sec. 75.58. On and after April 1, 
2000, the owner or operator shall meet the requirements of Sec. 75.58.
    (a) Specific SO2emission record provisions for units with 
qualifying Phase I technology. In addition to the SO2 
emissions information required in Sec. 75.54(c), from January 1, 1997, 
through December 31, 1999, the owner or operator shall record the 
applicable information in this paragraph for each affected unit on which 
SO2 emission controls have been installed and operated for 
the purpose of meeting qualifying Phase I technology requirements 
pursuant to Sec. 72.42 of this chapter and Sec. 75.15.
    (1) For units with post-combustion emission controls:
    (i) Component/system identification codes for each inlet and outlet 
SO2-diluent continuous emission monitoring system;
    (ii) Date and hour;
    (iii) Hourly average inlet SO2 emission rate (lb/mmBtu, 
rounded to nearest hundredth);
    (iv) Hourly average outlet SO2 emission rate (lb/mmBtu, 
rounded to nearest hundredth);
    (v) Percent data availability for both inlet and outlet 
SO2-diluent continuous emission monitoring systems (recorded 
to the nearest tenth of a percent), calculated pursuant to equation 8 of 
Sec. 75.32 (for the first 8,760 unit operating hours following initial 
certification) and equation 9 of Sec. 75.32, thereafter; and
    (vi) Identification code for emissions formula used to derive hourly 
average inlet and outlet SO2 mass emissions rates for each 
affected unit or group of units using a common stack.
    (2) For units with combustion and/or pre-combustion emission 
controls:
    (i) Component/system identification codes for each outlet 
SO2-diluent continuous emission monitoring system;
    (ii) Date and hour;
    (iii) Hourly average outlet SO2 emission rate (lb/mmBtu, 
rounded to nearest hundredth);
    (iv) For units with combustion controls, average daily inlet 
SO2 emission rate (lb/mmBtu, rounded to nearest hundredth), 
determined by coal sampling and analysis procedures in Sec. 75.15; and
    (v) For units with pre-combustion controls (i.e., fuel 
pretreatment), fuel analysis demonstrating the weight, sulfur content, 
and gross calorific value of the product and raw fuel lots.
    (b) Specific parametric data record provisions for calculating 
substitute emissions data for units with add-on emission controls. In 
accordance with Sec. 75.34, the owner or operator of an affected unit 
with add-on emission controls shall either record the applicable 
information in paragraph (b)(3) of this section for each hour of missing 
SO2 concentration data or NOX emission rate (in 
addition to other information), or shall record the information in 
paragraph (b)(1) of this section for SO2 or paragraph (b)(2) 
of this section for NOX through an automated data acquisition 
and handling system, as appropriate to the type of add-on emission 
controls:
    (1) For units with add-on SO2 emission controls 
petitioning to use or using the optional parametric monitoring 
procedures in appendix C of this part, for each hour of missing 
SO2 concentration or volumetric flow data:
    (i) The information required in Sec. 75.54(c) for SO2 
concentration and volumetric flow if either one of these monitors is 
still operating:
    (ii) Date and hour;
    (iii) Number of operating scrubber modules;
    (iv) Total feedrate of slurry to each operating scrubber module 
(gal/min);
    (v) Pressure differential across each operating scrubber module 
(inches of water column);
    (vi) For a unit with a wet flue gas desulfurization system, an 
inline measure of absorber pH for each operating scrubber module;
    (vii) For a unit with a dry flue gas desulfurization system, the 
inlet and

[[Page 289]]

outlet temperatures across each operating scrubber module;
    (viii) For a unit with a wet flue gas desulfurization system, the 
percent solids in slurry for each scrubber module.
    (ix) For a unit with a dry flue gas desulfurization system, the 
slurry feed rate (gal/min) to the atomizer nozzle;
    (x) For a unit with SO2 add-on emission controls other 
than wet or dry limestone, corresponding parameters approved by the 
Administrator;
    (xi) Method of determination of SO2 concentration and 
volumetric flow, using Codes 1-15 in Table 4 of Sec. 75.54; and
    (xii) Inlet and outlet SO2 concentration values recorded 
by an SO2 continuous emission monitoring system and the 
removal efficiency of the add-on emission controls.
    (2) For units with add-on NOX emission controls 
petitioning to use or using the optional parametric monitoring 
procedures in appendix C of this part, for each hour of missing 
NOX emission rate data:
    (i) Date and hour;
    (ii) Inlet air flow rate (acfh, rounded to the nearest thousand);
    (iii) Excess O2 concentration of flue gas at stack outlet 
(percent, rounded to nearest tenth of a percent);
    (iv) Carbon monoxide concentration of flue gas at stack outlet (ppm, 
rounded to the nearest tenth);
    (v) Temperature of flue gas at furnace exit or economizer outlet 
duct (  deg.F); and
    (vi) Other parameters specific to NOX emission controls 
(e.g., average hourly reagent feedrate);
    (vii) Method of determination of NOX emission rate using 
Codes 1-15 in Table 4 of Sec. 75.54; and
    (viii) Inlet and outlet NOX emission rate values recorded 
by a NOX continuous emission monitoring system and the 
removal efficiency of the add-on emission controls.
    (3) For units with add-on SO2 or NOX emission 
controls following the provisions of Sec. 75.34 (a)(1) or (a)(2), the 
owner or operator shall, for each hour of missing SO2 or 
NOX emission data, record:
    (i) Parametric data which demonstrate the proper operation of the 
add-on emission controls, as described in the quality assurance/quality 
control program for the unit. The parametric data shall be maintained on 
site, and shall be submitted upon request to the Administrator, an EPA 
Regional office, State, or local agency;
    (ii) A flag indicating either that the add-on emission controls are 
operating properly, as evidenced by all parameters being within the 
ranges specified in the quality assurance/quality control program, or 
that the add-on emission controls are not operating properly;
    (iii) For units petitioning under Sec. 75.66 for substituting a 
representative SO2 concentration during missing data periods, 
any available inlet and outlet SO2 concentration values 
recorded by an SO2 continuous emission monitoring system; and
    (iv) For units petitioning under Sec. 75.66 for substituting a 
representative NOX emission rate during missing data periods, 
any available inlet and outlet NOX emission rate values 
recorded by a NOX continuous emission monitoring system.
    (c) Specific SO2 emission record provisions for gas-fired 
or oil-fired units using optional protocol in appendix D of this part. 
In lieu of recording the information in Sec. 75.54(c) of this section, 
the owner or operator shall record the applicable information in this 
paragraph for each affected gas-fired or oil-fired unit for which the 
owner or operator is using the optional protocol in appendix D of this 
part for estimating SO2 mass emissions.
    (1) For each hour when the unit is combusting oil:
    (i) Date and hour;
    (ii) Hourly average flow rate of oil with the units in which oil 
flow is recorded, (gal/hr, lb/hr, m\3\/hr, or bbl/hr, rounded to the 
nearest tenth)(flag value if derived from missing data procedures);
    (iii) Sulfur content of oil sample used to determine SO2 
mass emissions, rounded to nearest hundredth for diesel fuel or to the 
nearest tenth of a percent for other fuel oil (flag value if derived 
from missing data procedures);
    (iv) Method of oil sampling (flow proportional, continuous drip, as 
delivered or manual);

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    (v) Mass of oil combusted each hour (lb/hr, rounded to the nearest 
tenth);
    (vi) SO2 mass emissions from oil (lb/hr, rounded to the 
nearest tenth);
    (vii) For units using volumetric oil flowmeters, density of oil 
(flag value if derived from missing data procedures);
    (viii) Gross calorific value (heat content) of oil, used to 
determine heat input (Btu/mass unit) (flag value if derived from missing 
data procedures);
    (ix) Hourly heat input rate from oil according to procedures in 
appendix F of this part (mmBtu/hr, to the nearest tenth); and
    (x) Fuel usage time for combustion of oil during the hour, rounded 
up to the nearest 15 min.
    (2) For gas-fired units or oil-fired units using the optional 
protocol in appendix D of this part of daily manual oil sampling, when 
the unit is combusting oil, the highest sulfur content recorded from the 
most recent 30 daily oil samples rounded to nearest tenth of a percent.
    (3) For each hour when the unit is combusting gaseous fuel,
    (i) Date and hour;
    (ii) Hourly heat input rate from gaseous fuel according to 
procedures in appendix F to this part (mmBtu/hr, rounded to the nearest 
tenth);
    (iii) Sulfur content or SO2 emission rate, in one of the 
following formats, in accordance with the appropriate procedure from 
appendix D of this part:
    (A) Sulfur content of gas sample, (rounded to the nearest 0.1 
grains/100 scf) (flag value if derived from missing data procedures); or
    (B) SO2 emission rate of 0.0006 lb/mmBtu for pipeline 
natural gas;
    (iv) Hourly flow rate of gaseous fuel, in 100 scfh (flag value if 
derived from missing data procedures);
    (v) Gross calorific value (heat content) of gaseous fuel, used to 
determine heat input (Btu/scf) (flag value if derived from missing data 
procedures);
    (vi) Heat input rate from gaseous fuel (mmBtu/hr, rounded to the 
nearest tenth);
    (vii) SO2 mass emissions due to the combustion of gaseous 
fuels, lb/hr; and
    (viii) Fuel usage time for combustion of gaseous fuel during the 
hour, rounded up to the nearest 15 min.
    (4) For each oil sample or sample of diesel fuel:
    (i) Date of sampling;
    (ii) Sulfur content (percent, rounded to the nearest hundredth for 
diesel fuel and to the nearest tenth for other fuel oil) (flag value if 
derived from missing data procedures);
    (iii) Gross calorific value or heat content (Btu/lb) (flag value if 
derived from missing data procedures); and
    (iv) Density or specific gravity, if required to convert volume to 
mass (flag value if derived from missing data procedures).
    (5) For each daily sample of gaseous fuel:
    (i) Date of sampling;
    (ii) Sulfur content (grains/100 scf, rounded to the nearest tenth) 
(flag value if derived from missing data procedures);
    (6) For each monthly sample of gaseous fuel:
    (i) Date of sampling;
    (ii) Gross calorific value or heat content (Btu/scf) (flag value if 
derived from missing data procedures).
    (d) Specific NOX emission record provisions for gas-fired 
peaking units or oil-fired peaking units using optional protocol in 
appendix E of this part. In lieu of recording the information in 
paragraph Sec. 75.54(d), the owner or operator shall record the 
applicable information in this paragraph for each affected gas-fired 
peaking unit or oil-fired peaking unit for which the owner or operator 
is using the optional protocol in appendix E of this part for estimating 
NOX emission rate.
    (1) For each hour when the unit is combusting oil,
    (i) Date and hour;
    (ii) Hourly average fuel flow rate of oil with the units in which 
oil flow is recorded (gal/hour, lb/hr or bbl/hour) (flag value if 
derived from missing data procedures);
    (iii) Gross calorific value (heat content) of oil, used to determine 
heat input (Btu/lb) (flag value if derived from missing data 
procedures);
    (iv) Hourly average NOX emission rate from combustion of 
oil (lb/mmBtu);
    (v) Heat input rate of oil (mmBtu/hr, rounded to the nearest tenth); 
and

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    (vi) Fuel usage time for combustion of oil during the hour, rounded 
to the nearest 15 min.
    (2) For each hour when the unit is combusting gaseous fuel,
    (i) Date and hour;
    (ii) Hourly average fuel flow rate of gaseous fuel (100 scfh) (flag 
value if derived from missing data procedures);
    (iii) Gross calorific value (heat content) of gaseous fuel, used to 
determine heat input (Btu/scf) (flag value if derived from missing data 
procedures);
    (iv) Hourly average NOX emission rate from combustion of 
gaseous fuel (lb/mmBtu, rounded to nearest hundredth);
    (v) Heat input rate from gaseous fuel (mmBtu/hr, rounded to the 
nearest tenth); and
    (vi) Fuel usage time for combustion of gaseous fuel during the hour, 
rounded to the nearest 15 min.
    (3) For each hour when the unit combusts any fuel:
    (i) Date and hour;
    (ii) Total heat input from all fuels (mmBtu, rounded to the nearest 
tenth);
    (iii) Hourly average NOX emission rate for the unit for 
all fuels;
    (iv) For stationary gas turbines and diesel or dual-fuel 
reciprocating engines, hourly averages of operating parameters under 
section 2.3 of appendix E (flag if value is outside of manufacturer's 
recommended range);
    (v) For boilers, hourly average boiler O2 reading 
(percent, rounded to the nearest tenth) (flag if value exceeds by more 
than 2 percentage points the O2 level recorded at the same 
heat input during the previous NOX emission rate test).
    (4) For each fuel sample:
    (i) Date of sampling;
    (ii) Gross calorific value (heat content) (Btu/lb for oil, Btu/scf 
for gaseous fuel); and
    (iii) Density or specific gravity, if required to convert volume to 
mass.
    (e) Specific SO2 emission record provisions during the 
combustion of gaseous fuel. (1) If SO2 emissions are 
determined in accordance with the provisions in Sec. 75.11(e)(2) during 
hours in which only gaseous fuel is combusted in a unit with an 
SO2 CEMS, the owner or operator shall record the information 
in paragraph (c)(3) of this section in lieu of the information in 
Secs. 75.54(c)(1) and (c)(3) or Secs. 75.57(c)(1) and (c)(4), for those 
hours.
    (2) The provisions of this paragraph apply to a unit which, in 
accordance with the provisions of Sec. 75.11(e)(3), uses an 
SO2 CEMS to determine SO2 emissions during hours 
in which only gaseous fuel is combusted in the unit. If the unit 
sometimes burns only gaseous fuel that is very low sulfur fuel (as 
defined in Sec. 72.2 of this chapter) as a primary and/or backup fuel 
and at other times combusts higher-sulfur fuels, such as coal or oil, as 
primary and/or backup fuel(s), then the owner or operator shall keep 
records on-site, suitable for inspection, of the type(s) of fuel(s) 
burned during each period of missing SO2 data and the number 
of hours that each type of fuel was combusted in the unit during each 
missing data period. This recordkeeping requirement does not apply to an 
affected unit that burns very low sulfur fuel exclusively, nor does it 
apply to a unit that burns such gaseous fuel(s) only during unit 
startup.

[60 FR 26535, 26568, May 17, 1995, as amended at 61 FR 59161, Nov. 20, 
1996; 64 FR 28608, May 26, 1999]



Sec. 75.56  Certification, quality assurance and quality control record provisions.

    Before April 1, 2000, the owner or operator shall meet the 
requirements of either this section or Sec. 75.59. On and after April 1, 
2000, the owner or operator shall meet the requirements of Sec. 75.59.
    (a) Continuous emission or opacity monitoring systems. The owner or 
operator shall record the applicable information in this section for 
each certified monitor or certified monitoring system (including 
certified backup monitors) measuring and recording emissions or flow 
from an affected unit.
    (1) For each SO2 or NOX pollutant 
concentration monitor, flow monitor, CO2 monitor, or diluent 
gas monitor, the owner or operator shall record the following for all 
daily and 7-day calibration error tests, including any follow-up tests 
after corrective action:
    (i) Component/system identification code;
    (ii) Instrument span;

[[Page 292]]

    (iii) Date and hour;
    (iv) Reference value, (i.e., calibration gas concentration or 
reference signal value, in ppm or other appropriate units);
    (v) Observed value (monitor response during calibration, in ppm or 
other appropriate units);
    (vi) Percent calibration error (rounded to nearest tenth of a 
percent); and
    (vii) For 7-day calibration tests for certification or 
recertification, a certification from the cylinder gas vendor or CEMS 
vendor, that calibration gas as defined in Sec. 72.2 and appendix A of 
this part, were used to conduct calibration error testing; and
    (viii) Description of any adjustments, corrective actions, or 
maintenance following test.
    (2) For each flow monitor, the owner or operator shall record the 
following for all daily interference checks, including any follow-up 
tests after corrective action:
    (i) Code indicating whether monitor passes or fails the interference 
check; and
    (ii) Description of any adjustments, corrective actions, or 
maintenance following test.
    (3) For each SO2 or NOX pollutant 
concentration monitor, CO2 monitor, or diluent gas monitor, 
the owner or operator shall record the following for the initial and all 
subsequent linearity check(s), including any follow-up tests after 
corrective action:
    (i) Component/system identification code;
    (ii) Instrument span;
    (iii) Date and hour;
    (iv) Reference value (i.e., reference gas concentration, in ppm or 
other appropriate units);
    (v) Observed value (average monitor response at each reference gas 
concentration, in ppm or other appropriate units);
    (vi) Percent error at each of three reference gas concentrations 
(rounded to nearest tenth of a percent); and
    (vii) Description of any adjustments, corrective action, or 
maintenance following test.
    (4) For each flow monitor, where applicable, the owner or operator 
shall record the following for all quarterly leak checks, including any 
follow-up tests after corrective action:
    (i) Code indicating whether monitor passes or fails the quarterly 
leak check; and
    (ii) Description of any adjustments, corrective actions, or 
maintenance following test.
    (5) For each SO2 pollutant concentration monitor, flow 
monitor, CO2 pollutant concentration monitor; NOX 
continuous emission monitoring system, SO2-diluent continuous 
emission monitoring system, and approved alternative monitoring system, 
the owner or operator shall record the following information for the 
initial and all subsequent relative accuracy tests and test audits:
    (i) Date and hour;
    (ii) Reference method(s) used;
    (iii) Individual test run data from the relative accuracy test audit 
for the SO2 concentration monitor, flow monitor, 
CO2 pollutant concentration monitor, NOX 
continuous emission monitoring system, SO2-diluent continuous 
emission monitoring system, or approved alternative monitoring systems, 
including:
    (A) Date, hour, and minute of beginning of test run,
    (B) Date, hour, and minute of end of test run,
    (C) Component/system identification code,
    (D) Run number,
    (E) Run data for monitor;
    (F) Run data for reference method; and
    (G) Flag value (0 or 1) indicating whether run has been used in 
calculating relative accuracy and bias values.
    (iv) Calculations and tabulated results, as follows:
    (A) Arithmetic mean of the monitoring system measurement values, 
reference method values, and of their differences, as specified in 
equation A-7 in appendix A to this part.
    (B) Standard deviation, as specified in equation A-8 in appendix A 
to this part.
    (C) Confidence coefficient, as specified in equation A-9 in appendix 
A to this part.
    (D) Relative accuracy test results, as specified in equation A-10 in 
appendix

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A to this part. (For the 3-level flow monitor test only, relative 
accuracy test results should be recorded at each of three gas 
velocities. Each of these three gas velocities shall be expressed as a 
total gross unit load, rounded to the nearest MWe or as steam load, 
rounded to the nearest thousand lb/hr.)
    (E) Bias test results as specified in section 7.6.4 in appendix A to 
this part.
    (F) Bias adjustment factor from equations A-11 and A-12 in appendix 
A to this part for any monitoring system or component that failed the 
bias test and 1.0 for any monitoring system or component that passed the 
bias test. (For flow monitors only, bias adjustment factors should be 
recorded at each of three gas velocities).
    (v) Description of any adjustment, corrective action, or maintenance 
following test.
    (vi) F-factor value(s) used to convert NOX pollutant 
concentration and diluent gas (O2 or CO2) 
concentration measurements into NOX emission rates (in lb/
mmBtu), heat input or CO2 emissions.
    (vii) For flow monitors, the equation used to linearize the flow 
monitor and the numerical values of the polynomial coefficients or K 
factor(s) of that equation.
    (viii) The raw data and calculated results for any stratification 
tests performed in accordance with sections 6.5.6.1 through 6.5.6.3 in 
appendix A to this part.
    (ix) For moisture monitoring systems, the coefficient or ``K'' 
factor or other mathematical algorithm used to adjust the monitoring 
system with respect to the reference method.
    (6) [Reserved]
    (7) Results of all trial runs and certification tests and quality 
assurance activities and measurements (including all reference method 
field test sheets, charts, records of combined system responses, 
laboratory analyses, and example calculations) necessary to substantiate 
compliance with all relevant appendices in this part. This information 
shall include, but shall not be limited to, the following reference 
method data:
    (i) For each run of each test using method 2 in appendix A of part 
60 of this chapter to determine volumetric flow rate:
    (A) Pitot tube coefficient;
    (B) Date of pitot tube calibration;
    (C) Average square root of velocity head of stack gas (inches of 
water) for the run;
    (D) Average absolute stack gas temperature,  deg.R;
    (E) Barometric pressure at test port, inches of mercury;
    (F) Stack static pressure, inches of H2 O;
    (G) Absolute stack gas pressure, inches of mercury;
    (H) Moisture content of stack gas, percent;
    (I) Molecular weight of stack gas, wet basis (lb/lb-mole);
    (J) Number of reference method measurements during the run; and
    (K) Total volumetric flowrate (scfh, wet basis).
    (ii) For each test using method 2 in appendix A of part 60 of this 
chapter to determine volumetric flow rate:
    (A) Information indicating whether or not the location meets 
requirements of method 1 in appendix A of part 60 of this chapter;
    (B) Information indicating whether or not the equipment passed the 
leak check after every run included in the relative accuracy test;
    (C) Stack inside diameter at test port (ft);
    (D) Duct side height and width at test port (ft);
    (E) Stack or duct cross-sectional area at test port 
(ft2); and
    (F) Designation as to the load level of the test.
    (iii) For each run of each test using method 6C, 7E, or 3A in 
appendix A of part 60 of this chapter to determine SO2, 
NOX, CO2, or O2 concentration:
    (A) Run start date;
    (B) Run start time;
    (C) Run end date;
    (D) Run end time;
    (E) Span of reference method analyzer;
    (F) Reference gas concentration (low, mid-, and high gas levels);
    (G) Initial and final analyzer calibration response (low, mid- and 
high gas levels);
    (H) Analyzer calibration error (low, mid-, and high gas levels);

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    (I) Pre-test and post-test analyzer bias (zero and upscale gas 
levels);
    (J) Calibration drift and zero drift of analyzer;
    (K) Indication as to which data are from a pretest and which are 
from a posttest;
    (L) Calibration gas level (zero, mid-level, or high); and
    (M) Moisture content of stack gas, in percent, if needed to convert 
to moisture basis of CEMS being tested.
    (iv) For each test using method 6C, 7E, or 3A in appendix A of part 
60 of this chapter to determine SO2, NOX 
CO2, or O2 concentration:
    (A) Pollutant being measured;
    (B) Test number;
    (C) Date of interference test;
    (D) Results of interference test;
    (E) Date of NO2 to NO conversion test (method 7E only);
    (F) Results of NO2 to NO conversion test (method 7E 
only).
    (v) For each calibration gas cylinder used to test using method 6C, 
7E, or 3A in appendix A of part 60 of this chapter to determine 
SO2, NOX, CO2, or O2 
concentration:
    (A) Cylinder gas vendor name from certification;
    (B) Cylinder number;
    (C) Cylinder expiration date;
    (D) Pollutant(s) in cylinder; and
    (E) Cylinder gas concentration(s).
    (b) Excepted monitoring systems for gas-fired and oil-fired units. 
The owner or operator shall record the applicable information in this 
section for each excepted monitoring system following the requirements 
of appendix D of this part or appendix E of this part for determining 
and recording emissions from an affected unit.
    (1) For each oil-fired unit or gas-fired unit using the optional 
procedures of appendix D of this part for determining SO2 
mass emissions and heat input or the optional procedures of appendix E 
of this part for determining NOX emission rate, for 
certification and quality assurance testing of fuel flowmeters:
    (i) Date of test,
    (ii) Upper range value of the fuel flowmeter,
    (iii) Flowmeter measurements during accuracy test,
    (iv) Reference flow rates during accuracy test,
    (v) Average flowmeter accuracy as a percent of upper range value,
    (vi) Fuel flow rate level (low, mid-level, or high); and
    (vii) Description of fuel flowmeter calibration specification or 
procedure (in the certification application, or periodically if a 
different method is used for annual quality assurance testing).
    (2) For gas-fired peaking units or oil-fired peaking units using the 
optional procedures of appendix E of this part, for each initial 
performance, periodic, or quality assurance/quality control-related 
test:
    (i) For each run of emissions data;
    (A) Run start date and time;
    (B) Run end date and time;
    (C) Fuel flow (lb/hr, gal/hr, scf/hr, bbl/hr, or m3/hr);
    (D) Gross calorific value (heat content) of fuel (Btu/lb or Btu/
scf);
    (E) Density of fuel (if needed to convert mass to volume);
    (F) Total heat input during the run (mmBtu);
    (G) Hourly heat input rate for run (mmBtu/hr);
    (H) Response time of the O2 and NOX reference 
method analyzers;
    (I) NOX concentration (ppm);
    (J) O2 concentration (percent O2);
    (K) NOX emission rate (lb/mmBtu); and
    (L) Fuel or fuel combination (by heat input fraction) combusted.
    (ii) For each unit load and heat input;
    (A) Average NOX emission rate (lb/mmBtu);
    (B) F-factor used in calculations;
    (C) Average heat input rate (mmBtu/hr);
    (D) Unit operating parametric data related to NOX 
formation for that unit type (e.g., excess O2 level, water/
fuel ratio); and
    (E) Fuel or fuel combination (by heat input fraction) combusted.
    (iii) For each test report;
    (A) Graph of NOX emission rate against heat input rate;
    (B) Results of the tests for verification of the accuracy of 
emissions calculations and missing data procedures performed by the 
automated data acquisition and handling system, and the calculations 
used to

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produce NOX emission rate data at different heat input 
conditions; and
    (C) Results of all certification tests and quality assurance 
activities and measurements (including reference method field test 
sheets, charts, laboratory analyses, example calculations, or other data 
as appropriate), necessary to substantiate compliance with the 
requirements of appendix E of this part.
    (c) For units with add-on SO2 and NOX emission 
controls following the provisions of Sec. 75.34(a)(1) or (a)(2), the 
owner or operator shall keep the following records on-site in the 
quality assurance/quality control plan required by section 1 in appendix 
B of this part:
    (1) A list of operating parameters for the add-on emission controls, 
including parameters in Sec. 75.55 (b), appropriate to the particular 
installation of add-on emission controls; and
    (2) The range of each operating parameter in the list that indicates 
the add-on emission controls are properly operating.

[60 FR 26536, 26568, May 17, 1995, as amended at 61 FR 59161, Nov. 20, 
1996; 64 FR 28608, May 26, 1999]



Sec. 75.57  General recordkeeping provisions.

    Before April 1, 2000, the owner or operator shall meet the 
requirements of either this section or Sec. 75.54. However, the 
provisions of this section which support a regulatory option provided in 
another section of this part must be followed if that regulatory option 
is used prior to April 1, 2000. On or after April 1, 2000, the owner or 
operator shall meet the requirements of this section.
    (a) Recordkeeping requirements for affected sources. The owner or 
operator of any affected source subject to the requirements of this part 
shall maintain for each affected unit a file of all measurements, data, 
reports, and other information required by this part at the source in a 
form suitable for inspection for at least three (3) years from the date 
of each record. Unless otherwise provided, throughout this subpart the 
phrase ``for each affected unit'' also applies to each group of affected 
or nonaffected units utilizing a common stack and common monitoring 
systems, pursuant to Secs. 75.16 through 75.18, or utilizing a common 
pipe header and common fuel flowmeter, pursuant to section 2.1.2 of 
appendix D to this part. The file shall contain the following 
information:
    (1) The data and information required in paragraphs (b) through (h) 
of this section, beginning with the earlier of the date of provisional 
certification or the deadline in Sec. 75.4(a), (b), or (c);
    (2) The supporting data and information used to calculate values 
required in paragraphs (b) through (g) of this section, excluding the 
subhourly data points used to compute hourly averages under 
Sec. 75.10(d), beginning with the earlier of the date of provisional 
certification or the deadline in Sec. 75.4(a), (b), or (c);
    (3) The data and information required in Sec. 75.55 or Sec. 75.58 
for specific situations, as applicable, beginning with the earlier of 
the date of provisional certification or the deadline in Sec. 75.4(a), 
(b), or (c);
    (4) The certification test data and information required in 
Sec. 75.56 or Sec. 75.59 for tests required under Sec. 75.20, beginning 
with the date of the first certification test performed, the quality 
assurance and quality control data and information required in 
Sec. 75.56 or Sec. 75.59 for tests, and the quality assurance/quality 
control plan required under Sec. 75.21 and appendix B to this part, 
beginning with the date of provisional certification;
    (5) The current monitoring plan as specified in Sec. 75.53, 
beginning with the initial submission required by Sec. 75.62; and
    (6) The quality control plan as described in section 1 of appendix B 
to this part, beginning with the date of provisional certification.
    (b) Operating parameter record provisions. The owner or operator 
shall record for each hour the following information on unit operating 
time, heat input rate, and load, separately for each affected unit and 
also for each group of units utilizing a common stack and a common 
monitoring system or utilizing a common pipe header and common fuel 
flowmeter:
    (1) Date and hour;
    (2) Unit operating time (rounded up to the nearest fraction of an 
hour (in

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equal increments that can range from one hundredth to one quarter of an 
hour, at the option of the owner or operator));
    (3) Hourly gross unit load (rounded to nearest MWge) (or steam load 
in 1000 lb/hr at stated temperature and pressure, rounded to the nearest 
1000 lb/hr, if elected in the monitoring plan);
    (4) Operating load range corresponding to hourly gross load of 1 to 
10, except for units using a common stack or common pipe header, which 
may use up to 20 load ranges for stack or fuel flow, as specified in the 
monitoring plan;
    (5) Hourly heat input rate (mmBtu/hr, rounded to the nearest tenth);
    (6) Identification code for formula used for heat input, as provided 
in Sec. 75.53; and
    (7) For CEMS units only, F-factor for heat input calculation and 
indication of whether the diluent cap was used for heat input 
calculations for the hour.
    (c) SO2 emission record provisions. The owner or operator 
shall record for each hour the information required by this paragraph 
for each affected unit or group of units using a common stack and common 
monitoring systems, except as provided under Sec. 75.11(e) or for a gas-
fired or oil-fired unit for which the owner or operator is using the 
optional protocol in appendix D to this part or for a low mass emissions 
unit for which the owner or operator is using the optional low mass 
emissions methodology in Sec. 75.19(c) for estimating SO2 
mass emissions:
    (1) For SO2 concentration during unit operation, as 
measured and reported from each certified primary monitor, certified 
back-up monitor, or other approved method of emissions determination:
    (i) Component-system identification code, as provided in Sec. 75.53;
    (ii) Date and hour;
    (iii) Hourly average SO2 concentration (ppm, rounded to 
the nearest tenth);
    (iv) Hourly average SO2 concentration (ppm, rounded to 
the nearest tenth), adjusted for bias if bias adjustment factor is 
required, as provided in Sec. 75.24(d);
    (v) Percent monitor data availability (recorded to the nearest tenth 
of a percent), calculated pursuant to Sec. 75.32; and
    (vi) Method of determination for hourly average SO2 
concentration using Codes 1-55 in Table 4a of this section.
    (2) For flow rate during unit operation, as measured and reported 
from each certified primary monitor, certified back-up monitor, or other 
approved method of emissions determination:
    (i) Component-system identification code, as provided in Sec. 75.53;
    (ii) Date and hour;
    (iii) Hourly average volumetric flow rate (in scfh, rounded to the 
nearest thousand);
    (iv) Hourly average volumetric flow rate (in scfh, rounded to the 
nearest thousand), adjusted for bias if bias adjustment factor required, 
as provided in Sec. 75.24(d);
    (v) Percent monitor data availability (recorded to the nearest tenth 
of a percent) for the flow monitor, calculated pursuant to Sec. 75.32; 
and
    (vi) Method of determination for hourly average flow rate using 
Codes 1-55 in Table 4a of this section.
    (3) For flue gas moisture content during unit operation (where 
SO2 concentration is measured on a dry basis), as measured 
and reported from each certified primary monitor, certified back-up 
monitor, or other approved method of emissions determination:
    (i) Component-system identification code, as provided in Sec. 75.53;
    (ii) Date and hour;
    (iii) Hourly average moisture content of flue gas (percent, rounded 
to the nearest tenth). If the continuous moisture monitoring system 
consists of wet- and dry-basis oxygen analyzers, also record both the 
wet- and dry-basis oxygen hourly averages (in percent O2, 
rounded to the nearest tenth);
    (iv) Percent monitor data availability (recorded to the nearest 
tenth of a percent) for the moisture monitoring system, calculated 
pursuant to Sec. 75.32; and
    (v) Method of determination for hourly average moisture percentage, 
using Codes 1-55 in Table 4a of this section.

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    (4) For SO2 mass emission rate during unit operation, as 
measured and reported from the certified primary monitoring system(s), 
certified redundant or non-redundant back-up monitoring system(s), or 
other approved method(s) of emissions determination:
    (i) Date and hour;
    (ii) Hourly SO2 mass emission rate (lb/hr, rounded to the 
nearest tenth);
    (iii) Hourly SO2 mass emission rate (lb/hr, rounded to 
the nearest tenth), adjusted for bias if bias adjustment factor 
required, as provided in Sec. 75.24(d); and
    (iv) Identification code for emissions formula used to derive hourly 
SO2 mass emission rate from SO2 concentration and 
flow and (if applicable) moisture data in paragraphs (c)(1), (c)(2), and 
(c)(3) of this section, as provided in Sec. 75.53.

     Table 4a.--Codes for Method of Emissions and Flow Determination
------------------------------------------------------------------------
                                Hourly emissions/flow measurement or
           Code                          estimation method
------------------------------------------------------------------------
1........................  Certified primary emission/flow monitoring
                            system.
2........................  Certified backup emission/flow monitoring
                            system.
3........................  Approved alternative monitoring system.
4........................  Reference method:
                             SO2: Method 6C.
                             Flow: Method 2 or its allowable
                            alternatives under appendix A to part 60 of
                            this chapter.
                             NOX: Method 7E.
                             CO2 or O2: Method 3A.
5........................  For units with add-on SO2 and/or NOX emission
                            controls: SO2 concentration or NOX emission
                            rate estimate from Agency preapproved
                            parametric monitoring method.
6........................  Average of the hourly SO2 concentrations, CO2
                            concentrations, O2 concentrations, NOX
                            concentrations, flow rates, moisture
                            percentages or NOX emission rates for the
                            hour before and the hour following a missing
                            data period.
7........................  Hourly average SO2 concentration, CO2
                            concentration, O2 concentration, NOX
                            concentration, moisture percentage, flow
                            rate, or NOX emission rate using initial
                            missing data procedures.
8........................  90th percentile hourly SO2 concentration, CO2
                            concentration, NOX concentration, flow rate,
                            moisture percentage, or NOX emission rate or
                            10th percentile hourly O2 concentration or
                            moisture percentage (moisture missing data
                            algorithm depends on which equations are
                            used for emissions and heat input).
9........................  95th percentile hourly SO2 concentration, CO2
                            concentration, NOX concentration, flow rate,
                            moisture percentage, or NOX emission rate or
                            5th percentile hourly O2 concentration or
                            moisture percentage (moisture missing data
                            algorithm depends on which equations are
                            used for emissions and heat input)
10.......................  Maximum hourly SO2 concentration, CO2
                            concentration, NOX concentration, flow rate,
                            moisture percentage, or NOX emission rate or
                            minimum hourly O2 concentration or moisture
                            percentage in the applicable lookback period
                            (moisture missing data algorithm depends on
                            which equations are used for emissions and
                            heat input).
11.......................  Average of hourly flow rates, NOX
                            concentrations or NOX emission rates in
                            corresponding load range, for the applicable
                            lookback period.
12.......................  Maximum potential concentration of SO2,
                            maximum potential concentration of CO2,
                            maximum potential concentration of NOX
                            maximum potential flow rate, maximum
                            potential NOX emission rate, maximum
                            potential moisture percentage, minimum
                            potential O2 concentration or minimum
                            potential moisture percentage, as determined
                            using section 2.1 of appendix A to this part
                            (moisture missing data algorithm depends on
                            which equations are used for emissions and
                            heat input).
13.......................  Fuel analysis data from appendix G to this
                            part for CO2 mass emissions. (This code is
                            optional through 12/31/99, and shall not be
                            used after 1/1/00.)
14.......................  Diluent cap value (if the cap is replacing a
                            CO2 measurement, use 5.0 percent for boilers
                            and 1.0 percent for turbines; if it is
                            replacing an O2 measurement, use 14.0
                            percent for boilers and 19.0 percent for
                            turbines).
15.......................  Fuel analysis data from appendix G to this
                            part for CO2 mass emissions. (This code is
                            optional through 12/31/99, and shall not be
                            used after 1/1/00.)
16.......................  SO2 concentration value of 2.0 ppm during
                            hours when only ``very low sulfur fuel'', as
                            defined in Sec.  72.2 of this chapter, is
                            combusted.
17.......................  Like-kind replacement non-redundant backup
                            monitoring analyzer.
19.......................  200 percent of the MPC; default high range
                            value.
20.......................  200 percent of the full-scale range setting
                            (full-scale exceedance of high range).
25.......................  Maximum potential NOX emission rate (MER).
                            (Use only when a NOX concentration full-
                            scale exceedance occurs and the diluent
                            monitor is unavailable.)
54.......................  Other quality assured methodologies approved
                            through petition. These hours are included
                            in missing data lookback and are treated as
                            unavailable hours for percent monitor
                            availability calculations.
55.......................  Other substitute data approved through
                            petition. These hours are not included in
                            missing data lookback and are treated as
                            unavailable hours for percent monitor
                            availability calculations.
------------------------------------------------------------------------


[[Page 298]]

    (d) NOX emission record provisions. The owner or operator 
shall record the applicable information required by this paragraph for 
each affected unit for each hour or partial hour during which the unit 
operates, except for a gas-fired peaking unit or oil-fired peaking unit 
for which the owner or operator is using the optional protocol in 
appendix E to this part or a low mass emissions unit for which the owner 
or operator is using the optional low mass emissions excepted 
methodology in Sec. 75.19(c) for estimating NOX emission 
rate. For each NOX emission rate (in lb/mmBtu) measured by a 
NOX-diluent monitoring system, or, if applicable, for each 
NOX concentration (in ppm) measured by a NOX 
concentration monitoring system used to calculate NOX mass 
emissions under Sec. 75.71(a)(2), record the following data as measured 
and reported from the certified primary monitor, certified back-up 
monitor, or other approved method of emissions determination:
    (1) Component-system identification code, as provided in Sec. 75.53 
(including identification code for the moisture monitoring system, if 
applicable);
    (2) Date and hour;
    (3) Hourly average NOX concentration (ppm, rounded to the 
nearest tenth) and hourly average NOX concentration (ppm, 
rounded to the nearest tenth) adjusted for bias if bias adjustment 
factor required, as provided in Sec. 75.24(d);
    (4) Hourly average diluent gas concentration (for NOX-
diluent monitoring systems, only, in units of percent O2 or 
percent CO2, rounded to the nearest tenth);
    (5) If applicable, the hourly average moisture content of the stack 
gas (percent H2O, rounded to the nearest tenth). If the 
continuous moisture monitoring system consists of wet- and dry-basis 
oxygen analyzers, also record both the hourly wet- and dry-basis oxygen 
readings (in percent O2, rounded to the nearest tenth);
    (6) Hourly average NOX emission rate (for NOX-
diluent monitoring systems only, in units of lb/mmBtu, rounded either to 
the nearest hundredth or thousandth prior to April 1, 2000 and rounded 
to the nearest thousandth on and after April 1, 2000);
    (7) Hourly average NOX emission rate (for NOX-
diluent monitoring systems only, in units of lb/mmBtu, rounded either to 
the nearest hundredth or thousandth prior to April 1, 2000 and rounded 
to the nearest thousandth on and after April 1, 2000), adjusted for bias 
if bias adjustment factor is required, as provided in Sec. 75.24(d). The 
requirement to report hourly NOX emission rates to the 
nearest thousandth shall not affect NOX compliance 
determinations under part 76 of this chapter; compliance with each 
applicable emission limit under part 76 shall be determined to the 
nearest hundredth pound per million Btu;
    (8) Percent monitoring system data availability (recorded to the 
nearest tenth of a percent), for the NOX-diluent or 
NOX concentration monitoring system, and, if applicable, for 
the moisture monitoring system, calculated pursuant to Sec. 75.32;
    (9) Method of determination for hourly average NOX 
emission rate or NOX concentration and (if applicable) for 
the hourly average moisture percentage, using Codes 1-55 in Table 4a of 
this section; and
    (10) Identification codes for emissions formulas used to derive 
hourly average NOX emission rate and total NOX 
mass emissions, as provided in Sec. 75.53, and (if applicable) the F-
factor used to convert NOX concentrations into emission 
rates.
    (e) CO2 emission record provisions. Except for a low ma