[Title 40 CFR ]
[Code of Federal Regulations (annual edition) - July 1, 1996 Edition]
[From the U.S. Government Printing Office]


          40



          Protection of Environment



[[Page i]]

          PARTS 72 TO 80

          Revised as of July 1, 1996
          CONTAINING
          A CODIFICATION OF DOCUMENTS
          OF GENERAL APPLICABILITY
          AND FUTURE EFFECT

          AS OF JULY 1, 1996
          With Ancillaries
          Published by
          the Office of the Federal Register
          National Archives and Records
          Administration

          as a Special Edition of
          the Federal Register



[[Page ii]]

                                      

               ----------------------------------------------------------
               As of July 1, 1996
               Title 40, Parts 72 to 85
               Revised as of July 1, 1995
               Is Replaced by Two Volumes
               Title 40, Parts 72 to 80
               and
               Title 40, Parts 81 to 85
                                      
               ----------------------------------------------------------


                     U.S. GOVERNMENT PRINTING OFFICE
                            WASHINGTON : 1996



               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..........     681
    Table of CFR Titles and Chapters..........................     685
    Alphabetical List of Agencies Appearing in the CFR........     701
    Table of OMB Control Numbers..............................     711
    List of CFR Sections Affected.............................     731

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

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

      

[[Page v]]



                               EXPLANATION

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

Title 1 through Title 16.................................as of January 1
Title 17 through Title 27..................................as of April 1
Title 28 through Title 41...................................as of July 1
Title 42 through Title 50................................as of October 1
    The appropriate revision date is printed on the cover of each 
volume.

LEGAL STATUS

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

HOW TO USE THE CODE OF FEDERAL REGULATIONS

    The Code of Federal Regulations is kept up to date by the individual 
issues of the Federal Register. These two publications must be used 
together to determine the latest version of any given rule.
    To determine whether a Code volume has been amended since its 
revision date (in this case, July 1, 1996), 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), and Acts Requiring Publication 
in the Federal Register (Table II). 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.

[[Page vii]]

    A List of CFR Sections Affected (LSA) is published monthly, keyed to 
the revision dates of the 50 CFR titles.

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.
SALES

    The Government Printing Office (GPO) processes all sales and 
distribution of the CFR. For payment by credit card, call 202-512-1800, 
M-F, 8 a.m. to 4 p.m. e.s.t. or fax your order to 202-512-2233, 24 hours 
a day. For payment by check, write to the Superintendent of Documents, 
Attn: New Orders, P.O. Box 371954, Pittsburgh, PA 15250-7954. For GPO 
Customer Service call 202-512-1803.

                              Richard L. Claypoole,
                                    Director,
                          Office of the Federal Register.

July 1, 1996.



[[Page ix]]



                               THIS TITLE

    Title 40--Protection of Environment is composed of eighteen volumes. 
The parts in these volumes are arranged in the following order: parts 1-
51, part 52, parts 53-59, part 60, parts 61-71, parts 72-80, parts 81-
85, part 86, parts 87-135, parts 136-149, parts 150-189, parts 190-259, 
parts 260-299, 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, 
1996.

    Chapter I--Environmental Protection Agency appears in all eighteen 
volumes. A Pesticide Tolerance Commodity/Chemical Index appears 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 1-51, 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 the convenience of the user, Sec. 9.1 appears in the 
Finding Aids section of the volumes containing parts 52 to the end.

    For this volume, Cheryl E. Sirofchuck 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 continued in the volume 
  containing 40 CFR parts 81-85.
Part                                                                Page
72              Permits regulation..........................           5
73              Sulphur dioxide allowance system............          83
74              Sulfur dioxide opt-ins......................         188
75              Continuous emission monitoring..............         214
76              Acid rain nitrogen oxides emission reduction 
                    program.................................         340
77              Excess emissions............................         364
78              Appeal procedures for Acid Rain Program.....         370
79              Registration of fuels and fuel additives....         380
80              Regulation of fuels and fuel additives......         474

[[Page 5]]



                 SUBCHAPTER C--AIR PROGRAMS--(Continued)





PART 72--PERMITS REGULATION--Table of Contents




             Subpart A--Acid Rain Program General Provisions

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

                  Subpart B--Designated Representative

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

                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  Approval of state programs--general.
72.72  State permit program approval criteria.
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, 7651, et seq.

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



             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

[[Page 6]]

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 part 70 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.



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 the 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) and (a)(3) of the Act, 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 established by regulations promulgated by the Administrator 
pursuant to section 407 of the Act, as modified by an Acid Rain permit 
application submitted to the permitting authority, and an Acid Rain 
permit issued by the permitting authority, in accordance with 
regulations implementing section 407 of the Act.
    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, issued by a permitting authority 
under this part (following an opportunity for appeal pursuant to part 78 
of this chapter or any State administrative appeals procedure), 
including any permit revisions, specifying the Acid Rain Program 
requirements applicable to an affected source, to each affected unit at 
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

[[Page 7]]

reduction program established in accordance with title IV of the Act, 
this 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 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 January 30 or, if 
January 30 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 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

[[Page 9]]

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 NIST 
traceable reference material; (3) a Protocol 1 gas; (4) a research gas 
material; or (5) zero air material.
    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:
    (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,

[[Page 10]]

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 with a sulfur 
content no greater than natural gas), 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 (including 
for calculating allowance allocations pursuant to part 73 of this 
chapter and applicability of the requirements of section 407 of the 
Act), 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 ``PRIMFUEL''.
    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 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

[[Page 11]]

calendar year are recorded under Sec. 73.34(a) until December 31, 
allowances available for use by the unit 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 unit's 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.
    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
    (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 by the unit for the purpose of 
meeting its Acid Rain sulfur dioxide emissions limitation.
    Customer means a purchaser of electricity not for purposes of 
transmission or resale.
    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

[[Page 12]]

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 D396-90, 
``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 
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.
    Dispatch system means either:
    (1) A specified unit and generator or specified group of units, and 
portions of

[[Page 13]]

units, and generators that are interconnected and centrally dispatched, 
provided that the requirements of Sec. 72.33 are met; or
    (2) In the event the requirements specified in paragraph (1) of this 
definition are not met, the unit and generator or group of units and 
generators that make up one utility system.
    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.
    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 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.
    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 appendix D or E of part 75 of this 
chapter 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

[[Page 14]]

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 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) 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

[[Page 15]]

    (ii) Any fuel other than coal or coal-derived fuel (other than coal-
derived gaseous fuel) for the remaining heat input, if any; provided 
that for purposes of part 75 of this chapter, any fuel used other than 
natural gas, shall be limited to:
    (A) Gaseous fuels containing no more sulfur than natural gas; or
    (B) Fuel oil.
    (2) For purposes of part 75 of this chapter, a unit may initially 
qualify as gas-fired under the following circumstances:
    (i) If the designated representative provides fuel usage data for 
the unit for the three calendar years immediately prior to submission of 
the monitoring plan, and if the unit's fuel usage is projected to change 
on or before January 1, 1995, the designated representative submits a 
demonstration satisfactory to the Administrator that the unit will 
qualify as gas-fired under the first sentence of this definition using 
the years 1995 through 1997 as the three calendar year period; or
    (ii) If a unit does not have fuel usage data for one or more of the 
three calendar years immediately prior to submission of the monitoring 
plan, the designated representative submits:
    (A) The unit's designed fuel usage;
    (B) Any fuel usage data, beginning with the unit's first calendar 
year of commercial operation following 1992;
    (C) The unit's projected fuel usage for any remaining future period 
needed to provide fuel usage data for three consecutive calendar years; 
and
    (D) Demonstration satisfactory to the Administrator that the unit 
will qualify as gas-fired under the first sentence of this definition 
using those three consecutive calendar years as the three calendar year 
period.
    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 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

[[Page 16]]

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.
    Mail or serve by mail means to submit or serve by means other than 
personal service.
    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.
    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 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.

[[Page 17]]

    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) containing 1 grain or 
less hydrogen sulfide per 100 standard cubic feet, and 20 grains or less 
total sulfur per 100 standard cubic feet), produced in geological 
formations beneath the Earth's surface, and maintaining a gaseous state 
at standard atmospheric temperature and pressure under ordinary 
conditions.
    NERC region means the North American Electric Reliability Council 
region or, if any, subregion.
    Net income neutrality means, in the case of energy conservation 
measures undertaken by an investor-owned utility whose rates are 
regulated by a State utility regulatory authority, rates and charges 
established by the State utility regulatory authority that ensure that 
the net income earned by the utility on its State-jurisdictional equity 
investment will be no lower as a consequence of its expenditures on 
cost-effective qualified energy conservation measures and any associated 
lost sales than it would have been had the utility not made such 
expenditures, or that the State utility regulatory authority has 
implemented a ratemaking approach designed to meet this objective.
    New independent power production facility or new IPP means a unit 
that:
    (1) Commences commercial operation on or after November 15, 1990;
    (2) Is nonrecourse project-financed, as defined in 10 CFR part 715;
    (3) Sells 80% of electricity generated at wholesale; and
    (4) Does not sell electricity to any affiliate or, if it does, 
demonstrates it cannot obtain the required allowances from such an 
affiliate.
    New unit means a unit that commences commercial operation on or 
after November 15, 1990, including any such unit that serves a generator 
with a nameplate capacity of 25 MWe or less or that is a simple 
combustion turbine.
    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) 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 fuel, for the 
remaining heat

[[Page 18]]

input, if any; provided that for purposes of part 75 of this chapter, 
any fuel used other than fuel oil shall be limited to gaseous fuels 
containing no more sulfur than natural gas.
    (2) For purposes of part 75 of this chapter, a unit that does not 
have fuel usage data for one or more of the three calendar years 
immediately prior to submission of the monitoring plan may initially 
qualify as oil-fired under the following circumstances: the designated 
representative submits:
    (i) Unit design fuel usage,
    (ii) The unit's designed fuel usage,
    (iii) Any fuel usage data, beginning with the unit's first calendar 
year of commercial operation following 1992,
    (iv) The unit's projected fuel usage for any remaining future period 
needed to provide fuel usage data for three consecutive calendar years, 
and
    (v) A demonstration satisfactory to the Administrator that the unit 
will qualify as oil-fired under the first sentence of this definition 
using those three consecutive calendar years as the three calendar year 
period.
    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 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

[[Page 19]]

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 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 under the following circumstances:
    (i) If the designated representative provides capacity factor data 
for the unit for the three calendar years immediately prior to 
submission of the monitoring plan and if the unit's capacity factor is 
projected to change on or before the certification deadline for NOX 
monitoring in Sec. 75.4 of this chapter, the designated representative 
submits a demonstration satisfactory to the Administrator that the unit 
will qualify as a peaking unit under the first sentence of this 
definition using the three calendar years beginning with the year of the 
certification deadline for NOX monitoring in Sec. 75.4 of this 
chapter (either 1995 or 1996) as the three year period; or
    (ii) If the unit does not have capacity factor data for any one or 
more of the three calendar years immediately prior to submission of the 
monitoring plan, the designated representative submits:
    (A) Any capacity factor data, beginning with the unit's first 
calendar year of commercial operation following the first year of the 
three calendar years immediately prior to the certification deadline for 
NOX monitoring in Sec. 75.4 of this chapter (either 1992 or 1993),
    (B) Capacity factor information for the unit for any remaining 
future period needed to provide capacity factor data for three 
consecutive calendar years, and
    (C) A demonstration satisfactory to the Administrator that the unit 
will qualify as a peaking unit under the first sentence of this 
definition using the three consecutive calendar years specified in (2) 
(ii) (A) and (B) as the three calendar year period.
    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) The Administrator in the case of issuance and administration of 
Acid Rain permits; or
    (2) The State air pollution control agency, local agency, other 
State agency, or other agency authorized by the Administrator to issue 
proposed Acid Rain permits under subpart G of this part and the other 
regulations promulgated pursuant to titles IV and V of the Act.
    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 limitations 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 that is provided by a 
supplier through a pipeline.
    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.

[[Page 20]]

    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, 1992 or, where the letter of intent does not specify a 
timeframe, a power sales agreement applicable to the source is executed 
on or before November 15, 1992; or
    (4) A utility competitive bid solicitation that has resulted in the 
selection of the qualifying facility or independent power production 
facility as the winning bidder.
    Power sales agreement is a legally binding agreement between a QF, 
IPP, new IPP, or firm associated with such facility and a regulated 
electric utility that establishes the terms and conditions for the sale 
of power from the facility to the utility.
    Presiding Officer means an Administrative Law Judge appointed under 
5 U.S.C. 3105 and designated to preside at a hearing in an appeal under 
part 78 of this chapter or an EPA lawyer designated to preside at any 
such hearing under Sec. 78.6(b)(3)(ii) of this chapter.
    Primary fuel or primary fuel supply means the main fuel type 
(expressed in mmBtu) consumed by an affected unit for the applicable 
calendar year.
    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.
    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

[[Page 21]]

changed in such a way as to allow the costs of compliance with the Acid 
Rain Program to be shifted to the purchaser.
    Qualifying repowering technology means:
    (1) Replacement of an existing coal-fired boiler with one of the 
following clean coal technologies: Atmospheric or pressurized fluidized 
bed combustion, integrated gasification combined cycle, 
magnetohydrodynamics, direct and indirect coal-fired turbines, 
integrated gasification fuel cells, or as determined by the 
Administrator, in consultation with the Secretary of Energy, a 
derivative of one or more of these technologies, and any other 
technology capable of controlling multiple combustion emissions 
simultaneously with improved boiler or generation efficiency and with 
significantly greater waste reduction relative to the performance of 
technology in widespread commercial use as of the date of enactment of 
the Clean Air Act Amendments of 1990; or
    (2) Any oil- or gas-fired unit that has been awarded clean coal 
technology demonstration funding as of January 1, 1991, by the 
Department of Energy.
    Quality-assured monitor operating hour means any unit operating hour 
or portion thereof over which a certified CEMS, or other monitoring 
system approved by the Administrator under part 75 of this chapter, is 
operating:
    (1) Within the performance specifications set forth in part 75, 
appendix A of this chapter and the quality assurance/quality control 
procedures set forth in part 75, appendix B of this chapter, without 
unscheduled maintenance, repair, or adjustment; and
    (2) In accordance with Sec. 75.10(d), (e), and (f) of this chapter.
    Receive or receipt of means the date the Administrator or a 
permitting authority comes into possession of information or 
correspondence (whether sent in writing or by authorized electronic 
transmission), as indicated in an official 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.

[[Page 22]]

    Schedule of compliance means an enforceable sequence of actions, 
measures, or operations designed to achieve or maintain compliance, or 
correct non-compliance, with an applicable requirement of the Acid Rain 
Program, including any applicable Acid Rain permit requirement.
    Secretary of Energy means the Secretary of the United States 
Department of Energy or the Secretary's duly authorized representative.
    Serial number means, when referring to allowances, the unique 
identification number assigned to each allowance by the Administrator, 
pursuant to Sec. 73.34(d) of this chapter.
    Simple combustion turbine means a unit that is a rotary engine 
driven by a gas under pressure that is created by the combustion of any 
fuel. This term includes combined cycle units without auxiliary firing. 
This term excludes combined cycle units with auxiliary firing, unless 
the unit did not use the auxiliary firing from 1985 through 1987 and 
does not use auxiliary firing at any time after November 15, 1990.
    Site lease, as used in part 73, subpart E of this chapter, means a 
legally-binding agreement signed between a new IPP or a firm associated 
with a new IPP and a site owner that establishes the terms and 
conditions under which the new IPP or the firm associated with the new 
IPP has the binding right to utilize a specific site for the purposes of 
operating or constructing the new IPP.
    Small diesel refinery means a domestic motor diesel fuel refinery or 
portion of a refinery that, as an annual average of calendar years 1988 
through 1990 and as reported to the Department of Energy on Form 810, 
had bona fide crude oil throughput less than 18,250,000 barrels per 
year, and the refinery or portion of a refinery is owned or controlled 
by a refiner with a total combined bona fide crude oil throughput of 
less than 50,187,500 barrels per year.
    Solid waste incinerator means a source as defined in section 
129(g)(1) of the Act.
    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 range of values 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.
    Standard conditions means 68  deg.F at 1 atm (29.92 in. of mercury).
    Standard reference material or SRM means a calibration gas mixture 
issued and certified by NIST as having specific known chemical or 
physical property values.
    State means one of the 48 contiguous States and the District of 
Columbia and includes any non-federal authorities, including local 
agencies, interstate associations, and State-wide agencies with approved 
State operating permit programs. 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 as meeting the requirements of 
titles IV and V of the Act, part 70 of this chapter, and this part, 
including subpart G of this part.
    Stationary gas turbine means a turbine that is not self-propelled 
and that combusts natural gas, other gaseous fuel with a sulfur content 
no greater than 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

[[Page 23]]

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

[[Page 24]]

    (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.
    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.
    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 either SO2, 
NO, or total hydrocarbons above 0.1 parts per million (ppm); a 
concentration of CO above 1 ppm; and a concentration of CO2 above 
400 ppm, or (2) ambient air conditioned and purified by a continuous 
emission monitoring system for which the continuous emission monitoring 
system manufacturer or vendor certifies that the particular continuous 
emission monitoring system model produces conditioned gas that does not 
contain concentrations of either SO2 or NO above 0.1 ppm 
or CO2 above 400 ppm; and that does not contain concentrations of 
other gases that interfere with instrument readings or cause the 
instrument to read concentrations of SO2, NO, or CO2 
for a particular continuous emission monitoring system model.

[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]



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).
cfm--cubic feet per minute.
cm--centimeter.
dcf--dry cubic feet.
DOE--Department of Energy.

[[Page 25]]

dscf--dry cubic feet at standard conditions.
dscfh--dry cubic feet per hour at standard conditions.
EIA--Energy Information Administration.
eq--equivalent.
 deg.F--degree Fahrenheit.
fps--feet per second.
gal--gallon.
hr--hour.
in--inch.
 deg.K--degree Kelvin.
Kwh--kilowatt hour.
lb--pounds.
m--meter.
mmBtu--million Btu.
min--minute.
mol. wt.--molecular weight.
MWe--megawatt electrical.
MWge--gross megawatt electrical.
ppm--parts per million.
psi--pounds per square inch.
 deg.R--degree Rankine.
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.



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

[[Page 26]]

system, an annual average of more than one-third of its potential 
electrical output capacity and more than 219,000 MWe-hrs electric 
output, on a gross basis;
    (v) Was an exempt qualifying facility under paragraph (b)(5) of this 
section but, at any time after the later of November 15, 1990 or the 
date the facility commences commercial operation, fails to meet the 
definition of qualifying facility;
    (vi) Was an exempt IPP under paragraph (b)(6) of this section but, 
at any time after the later of November 15, 1990 or the date the 
facility commences commercial operation, fails to meet the definition of 
independent power production facility; or
    (vii) Was an exempt solid waste incinerator under paragraph (b)(7) 
of this section but during any three calendar year period after November 
15, 1990 consumes 20 percent or more (on a Btu basis) fossil fuel.
    (b) The following types of units are not affected units subject to 
the requirements of the Acid Rain Program:
    (1) A simple combustion turbine that commenced 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.

[[Page 27]]

    (7) A solid waste incinerator, if more than 80 percent (on a Btu 
basis) of the annual fuel consumed at such incinerator is other than 
fossil fuels. For solid waste incinerators which began operation before 
January 1, 1985, the average annual fuel consumption of non-fossil fuels 
for calendar years 1985 through 1987 must be greater than 80 percent for 
such an incinerator to be exempt. For solid waste incinerators which 
began operation after January 1, 1985, the average annual fuel 
consumption of non-fossil fuels for the first three years of operation 
must be greater than 80 percent for such an incinerator to be exempt. 
If, during any three calendar year period after November 15, 1990, such 
incinerator consumes 20 percent or more (on a Btu basis) fossil fuel, 
such incinerator will be an affected source under the Acid Rain Program.
    (8) A non-utility unit.
    (c) A certifying official 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 and appropriate facts about the 
unit. The petition shall meet the requirements of Sec. 72.21. In 
accordance with Sec. 72.21(d), 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 shall be submitted to the Administrator 
prior to the issuance (including renewal) of a Phase II Acid Rain permit 
for the unit as a final agency action.
    (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]



Sec. 72.7  New units exemption.

    (a) Applicability. This section applies to any new utility 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, as determined in accordance with paragraph (d)(2) of this 
section.
    (b) Petition for written exemption. The designated representative, 
authorized in accordance with subpart B of this part, of a source that 
includes a unit under paragraph (a) of this section may petition the 
permitting authority for a written exemption, or to renew a written 
exemption, for the unit from certain requirements of the Acid Rain 
Program. The petition shall include the following elements in a format 
prescribed by the Administrator:
    (1) Identification of the unit.
    (2) The nameplate capacity of each generator served by the unit.
    (3) A list of all fuels currently burned by the unit and their 
percentage sulfur content by weight, determined in accordance with 
paragraph (a) of this section.
    (4) A list of all fuels that are expected to be burned by the unit 
and their sulfur content by weight.
    (5) The special provisions in paragraph (d) of this section.
    (c) Permitting authority's action.
    (1)(i) The permitting authority shall issue, for any unit meeting 
the requirements of paragraphs (a) and (b) of this section, a written 
exemption from the requirements of the Acid Rain Program except for the 
requirements specified in this section and Secs. 72.1 through 72.6 and 
Secs. 72.10 through 72.13; provided that no unit shall be exempted 
unless allowances, equal in number to, and with the same or earlier 
compliance use date as, all of those allocated under subpart B of part 
73 of this chapter for any year for which the unit will be exempted,

[[Page 28]]

are deducted from the unit's Allowance Tracking System account.
    (ii) The exemption shall take effect on January 1 of the year 
immediately following the earlier of the date on which the written 
exemption is issued subject to administrative appeal under part 78 of 
this chapter or is issued as a final agency action subject to judicial 
review, in accordance with paragraph (c)(2) of this section; provided 
that the owners and operators, and, to the extent applicable, the 
designated representative, shall comply with the requirements of the 
Acid Rain Program concerning all years for which the unit was not 
exempted, even if such requirements arise, or must be complied with, 
after the exemption takes effect. The exemption shall not be a defense 
against any violation of such requirements of the Acid Rain Program 
whether the violation occurs before or after the exemption takes effect.
    (2) In considering and issuing or denying a written exemption under 
paragraph (c)(1) of this section, the permitting authority shall apply 
the procedures in subparts F and G of this part and part 70 of this 
chapter, as applicable, by:
    (i) Treating the petition as an Acid Rain permit application under 
such provisions;
    (ii) Issuing or denying a draft written exemption that is treated as 
the issuance or denial of a draft permit under such provisions; and
    (iii) Where the Administrator is the permitting authority, issuing 
or denying a written exemption that is treated as the issuance or denial 
of a permit under subpart F of this part or, where a State is the 
permitting authority, issuing or denying a proposed written exemption 
that is treated as the issuance or denial of a proposed permit under 
subpart G of this part and part 70 of this chapter; provided that no 
provision under subparts F and G of this part and part 70 of this 
chapter concerning the content, effective date, or term of an Acid Rain 
permit shall apply to the written exemption or proposed written 
exemption under this section.
    (3) A written exemption issued under this section shall have a term 
of 5 years from its effective date, except as provided in paragraph 
(d)(4) of this section.
    (d) Special provisions. (1) The owners and operators of each unit 
exempted under this section shall surrender allowances equal in number 
to, and with the same or an earlier compliance use date as, all of those 
allocated to the unit under subpart B of part 73 of this chapter for any 
year for which the unit is exempted and shall waive the right to receive 
any allowances to be allocated under subpart B of part 73 of this 
chapter for any year for which the unit is exempted.
    (2) The owners and operators of each unit exempted under this 
section shall determine the sulfur content by weight of its fuel as 
follows:
    (i) For petroleum or petroleum products that the unit burns starting 
on the first day on which the exemption takes effect until the exemption 
terminates, a sample of each delivery of such fuel shall be tested using 
ASTM methods ASTM D4057-88 and ASTM D129-91, ASTM D2622-92, or ASTM 
D4294-90 (all methods incorporated by reference under Sec. 72.13 of this 
part.)
    (ii) For natural gas that the unit burns starting on the first day 
on which the exemption takes effect until the exemption terminates, the 
sulfur content shall be assumed to be 0.05 per cent or less by weight.
    (iii) For gaseous fuel (other than natural gas) that the unit burns 
starting on the first day on which the exemption takes effect until the 
exemption terminates, a sample of each delivery of such fuel shall be 
tested using ASTM methods ASTM D1072-90 and ASTM D1265-92 (incorporated 
by reference under Sec. 72.13 of this part); provided that if the 
gaseous fuel is delivered by pipeline to the unit, a sample of the fuel 
shall be tested, at least once every quarter in which the unit operates 
during any year for which the exemption is in effect, using ASTM method 
ASTM D1072-90 (incorporated by reference under Sec. 72.13 of this part).
    (3) The owners and operators of each unit exempted under this 
section shall retain at the source that includes the unit, the records 
of the results of the tests performed under paragraph (d)(2) (i) and 
(iii) of this section and a copy of the purchase agreements for the fuel

[[Page 29]]

under paragraph (d)(2) of this section, stating the sulfur content of 
such fuel. Such records and documents shall be retained for 5 years from 
the date they are created.
    (4) On the earlier of the date the written exemption expires, the 
date a unit exempted under this section burns any fuel with a sulfur 
content in excess of 0.05 percent by weight (as determined in accordance 
with paragraph (d)(2) of this section), or 24 months prior to the date 
the unit first serves one or more generators with total nameplate 
capacity in excess of 25 MWe, the unit shall no longer be exempted under 
this section and shall be subject to all requirements of the Acid Rain 
Program, except that:
    (i) Notwithstanding Sec. 72.30 (b) and (c), the designated 
representative of the source that includes the unit shall submit a 
complete Acid Rain permit application on the later of January 1, 1998 or 
the date the unit is no longer exempted under this section.
    (ii) For purposes of applying monitoring requirements under part 75 
of this chapter, the unit shall be treated as a new unit that commenced 
commercial operation on the date the unit no longer meets the 
requirements of paragraph (a) of this section.



Sec. 72.8  Retired units exemption.

    (a) Applicability. This section applies to any affected unit that is 
retired prior to the issuance (including renewal) of a Phase II Acid 
Rain permit for the unit as a final agency action.
    (b) Petition for Written Exemption. (1) The designated 
representative, authorized in accordance with subpart B of this part, of 
a source that includes a unit under paragraph (a) of this section may 
petition the permitting authority for a written exemption, or to renew a 
written exemption, for the unit from certain requirements of this part.
    (2) A petition under this section shall be submitted on or before:
    (i) The deadline for submitting an Acid Rain permit application for 
Phase II; or
    (ii) If the unit has a Phase II Acid Rain permit, the deadline for 
reapplying for such permit.
    (3) The petition under this section shall include the following 
elements in a format prescribed by the Administrator:
    (i) Identification of the unit.
    (ii) The applicable deadline under paragraph (b)(2) of this section.
    (iii) The actual or expected date of retirement of the unit.
    (iv) The following statement: ``I certify that this unit [`is' or 
`will be', as applicable] permanently retired on the date specified in 
this petition and will not emit any sulfur dioxide or nitrogen oxides 
after such date.''
    (v) A description of any actions that have been or will be taken and 
provide the basis for the certification in paragraph (b)(3)(iv) of this 
section.
    (vi) The special provisions in paragraph (d) of this section.
    (c) Permitting Authority's Action. (1)(i) The permitting authority 
shall issue, for any unit meeting the requirements of paragraphs (a) and 
(b) of this section, a written exemption from the requirements of this 
part except for the requirements specified in this section and 
Secs. 72.1 through 72.6 and Secs. 72.10 through 72.13.
    (ii) The exemption shall take effect on January 1 of the year 
following the earlier of the date on which the written exemption is 
issued subject to administrative appeal under part 78 of this chapter or 
is issued as a final agency action subject to judicial review, in 
accordance with paragraph (c)(2) of this section; provided that the 
owners and operators, and, to the extent applicable, the designated 
representative, shall comply with the requirements of this part 
concerning all years for which the unit was not exempted, even if such 
requirements arise or must be complied with after the exemption takes 
effect. The exemption shall not be a defense against any violation of 
such requirements of the Acid Rain Program whether the violation occurs 
before or after the exemption takes effect.
    (2) In considering and issuing or denying a written exemption under 
paragraph (c)(1) of this section, the permitting authority shall apply 
the procedures in subparts F and G of this part and part 70 of this 
chapter, as applicable, by:
    (i) Treating the petition as an Acid Rain permit application under 
such provisions;

[[Page 30]]

    (ii) Issuing or denying a draft written exemption that is treated as 
the issuance or denial of a draft permit under such provisions; and
    (iii) Where the Administrator is the permitting authority, issuing 
or denying a written exemption that is treated as a permit under subpart 
F of this part or, where a State is the permitting authority, issuing or 
denying a proposed written exemption that is treated as a proposed 
permit under subpart G of this part and part 70 of this chapter; 
provided that no provision under subparts F and G of this part and part 
70 of this chapter concerning, the content, effective date, or term of 
an Acid Rain permit shall apply to the written exemption or proposed 
written exemption under this section.
    (3) A written exemption issued under this section shall have a term 
of 5 years, except as provided in paragraph (d)(3) of this section.
    (d) Special Provisions. (1) A unit exempted under this section shall 
not emit any sulfur dioxide and nitrogen dioxide starting on the date it 
is exempted.
    (2) The owners and operators of a unit exempted under this section 
shall comply with monitoring requirements in accordance with part 75 of 
this chapter and will be allocated allowances in accordance with part 73 
of this chapter.
    (3) A unit exempted under this section shall not resume operation 
unless the designated representative of the source that includes the 
unit submits an Acid Rain permit application for the unit not less than 
24 months prior to the later of January 1, 2000 or the date the unit is 
to resume operation. On the earlier of the date the written exemption 
expires or the date an Acid Rain permit application is submitted or is 
required to be submitted under this paragraph, the unit shall no longer 
be exempted under this section and shall be subject to all requirements 
of this part.

[58 FR 3650, Jan. 11, 1993; 58 FR 40747, July 30, 1993]



Sec. 72.9  Standard requirements.

    (a) Permit Requirements. (1) The designated representative of each 
affected source and each affected unit at the source shall:
    (i) Submit a complete Acid Rain permit application (including a 
compliance plan) under this part in accordance with the deadlines 
specified in Sec. 72.30;
    (ii) Submit in a timely manner a complete reduced utilization plan 
if required under Sec. 72.43; and
    (iii) Submit in a timely manner any supplemental information that 
the permitting authority determines is necessary in order to review an 
Acid Rain permit application and issue or deny an Acid Rain permit.
    (2) The owners and operators of each affected source and each 
affected unit at the source shall:
    (i) Operate the unit in compliance with a complete Acid Rain permit 
application or a superseding Acid Rain permit issued by the permitting 
authority; and
    (ii) Have an Acid Rain Permit.
    (b) Monitoring Requirements. (1) The owners and operators and, to 
the extent applicable, designated representative of each affected source 
and each affected unit at the source shall comply with the monitoring 
requirements as provided in part 75 of this chapter and section 407 of 
the Act and regulations implementing section 407 of the Act.
    (2) The emissions measurements recorded and reported in accordance 
with part 75 of this chapter and section 407 of the Act and regulations 
implementing section 407 of the Act 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 and regulations 
implementing section 407 of the Act 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

[[Page 31]]

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 the written 
exemption under Secs. 72.7 and 72.8 and no provision of law shall be 
construed to limit the authority of the United States to terminate or 
limit such authorization.
    (7) An allowance allocated by the Administrator under the Acid Rain 
Program does not constitute a property right.
    (d) Nitrogen Oxides Requirements. The owners and operators of the 
source and each affected unit at the source shall comply with the 
applicable Acid Rain emissions limitation for nitrogen oxides.
    (e) Excess Emissions Requirements. (1) The designated representative 
of an affected 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.
    (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.

[[Page 32]]

    (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 a written exemption under Sec. 72.7 
or Sec. 72.8, including any requirement for the payment of any penalty 
owed to the United States, shall be subject to enforcement pursuant to 
section 113(c) of the Act.
    (2) Any person who knowingly makes a false, material statement in 
any record, submission, or report under the Acid Rain Program shall be 
subject to criminal enforcement pursuant to section 113(c) of the Act 
and 18 U.S.C. 1001.
    (3) No permit revision shall excuse any violation of the 
requirements of the Acid Rain Program that occurs prior to the date that 
the revision takes effect.
    (4) Each affected source and each affected unit shall meet the 
requirements of the Acid Rain Program.
    (5) Any provision of the Acid Rain Program that applies to an 
affected source (including a provision applicable to the designated 
representative of an affected source) shall also apply to the owners and 
operators of such source and of the affected units at the source.
    (6) Any provision of the Acid Rain Program that applies to an 
affected unit (including a provision applicable to the designated 
representative of an affected unit) shall also apply to the owners and 
operators of such unit. 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 part 76 
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 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 a 
written exemption under Sec. Sec. 72.7 or 72.8 shall be construed as:
    (1) Except as expressly provided in title IV of the Act, exempting 
or excluding the owners and operators and, to the extent applicable, the 
designated representative of an affected source or affected unit from 
compliance with any other provision of the Act, including the provisions 
of title I of the Act relating to applicable National Ambient Air 
Quality Standards or State Implementation Plans.
    (2) Limiting the number of allowances a 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]



Sec. 72.10  Availability of information.

    The availability to the public of information provided to, or 
otherwise obtained by, the Administrator under the

[[Page 33]]

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.
    (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 Sec. 72.7 of this chapter.
    (2) ASTM D388-92, Standard Classification of Coals by Rank for 
Sec. 72.2 of this chapter.
    (3) ASTM D396-90a, Standard Specification for Fuel Oils, for 
Sec. 72.2 of this chapter.
    (4) ASTM D975-91, Standard Specification for Diesel Fuel Oils, for 
Sec. 72.2 of this chapter.
    (5) ASTMD1072-90, Standard Test Method for Total Sulfur in Fuel 
Gases, for Sec. 72.7 of this chapter.
    (6) ASTMD1265-92, Standard Practice for Sampling Liquified Petroleum 
(LP) Gases (Manual Method), for Sec. 72.7 of this chapter.
    (7) ASTM D2622-92, Standard Test Method for Sulfur in Petroleum 
Products by X-Ray Spectrometry, for Sec. 72.7 of this chapter.
    (8) ASTM D2880-90a, Standard Specification for Gas Turbine Fuel 
Oils, for Sec. 72.2 of this part.
    (9) ASTM D4057-88, Standard Practice for Manual Sampling of 
Petroleum and Petroleum Products, for Sec. 72.7 of this part.
    (10) ASTM D4294-90, Standard Test Method for Sulfur in Petroleum 
Products by Energy-Dispersive X-Ray Fluorescence Spectroscopy, for 
Sec. 72.7 of this part.
    (b) [Reserved]

[58 FR 3650, Jan. 11, 1993, as amended at 60 FR 26526, May 17, 1995]



                  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

[[Page 34]]

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.
    (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]

[[Page 35]]



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.



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

    (a) Changing the designated representative. The designated 
representative may be changed at any time upon receipt by the 
Administrator of a superseding complete certificate of representation. 
Notwithstanding any such change, all 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.

[[Page 36]]

    (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 and all State or local utility 
regulatory authorities with jurisdiction over each owner.
    (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' or 
`alternate designated representative,' as applicable for the affected 
source and each affected unit at the source identified in this 
certificate of representation, daily for a period of one week 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 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 there is an alternate designated representative, 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 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.



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 submitted to the Administrator.

[[Page 37]]

    (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.



                Subpart C--Acid Rain Permit Applications



Sec. 72.30  Requirement to apply.

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

[[Page 38]]

    (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).
    (3) Acid Rain Compliance Option Deadlines. The deadlines for 
applying for approval of any Acid Rain compliance options shall be the 
deadlines specified in the relevant section of subpart D of this part 
and in section 407 of the Act and regulations implementing section 407 
of the Act.
    (c) Duty to reapply. The designated representative shall submit a 
complete Acid Rain permit application for each source with an affected 
unit at least 6 months prior to the expiration of an existing Acid Rain 
permit governing the unit during Phase II or an opt-in permit governing 
an opt-in source or such longer time as may be approved under part 70 of 
this chapter that ensures that the term of the existing permit will not 
expire before the effective date of the permit for which the application 
is submitted.
    (d) The original and three copies of all permit applications for 
Phase I and where the Administrator is the permitting authority, for 
Phase II, shall be submitted to the EPA Regional Office for the Region 
where the affected source is located. The original and three copies of 
all permit applications for Phase II, where the Administrator is not the 
permitting authority, shall be submitted to the State permitting 
authority for the State where the affected source is located.

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



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 Phase II unit 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.



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 earlier of the date on which an Acid Rain permit is 
issued subject to administrative appeal under part 78 of this chapter or 
is issued as a

[[Page 39]]

final agency action subject to judicial review, 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 and subject to administrative appeal, where 
the Administrator is the permitting authority, or the issuance or denial 
of such permit as a final agency action subject to judicial review, 
where the State is the permitting authority.



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 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.
    (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.

[[Page 40]]

    (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 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

[[Page 41]]

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 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;

[[Page 42]]

    (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 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]



       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) 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 limitation established by regulations implementing 
section 407 of the Act or shall specify one or more Acid Rain compliance 
options, in accordance with section 407 of the Act and regulations 
implementing section 407.
    (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 an NOX averaging plan contained in 
part 76 of this chapter, that includes units at more than one affected 
source shall be complete only if:
    (i) Such plan is signed and certified by the designated 
representative for each source with an affected unit governed by such 
plan; and
    (ii) A complete permit application is submitted covering each unit 
governed by such plan.
    (2) A permitting authority's approval of a plan under paragraph 
(b)(1) of this section that includes units in more than one State shall 
be final only after every permitting authority with jurisdiction over 
any such unit has approved the plan with the same modifications or 
conditions, if any.
    (c) Conditional Approval. In the compliance plan, the designated 
representative of an affected unit may propose, in accordance with this 
subpart, any Acid Rain compliance option for conditional approval, 
except a Phase I extension plan; provided that an Acid Rain compliance 
option under section 407 of

[[Page 43]]

the Act may be conditionally proposed only to the extent provided in 
regulations implementing section 407 of the Act.
    (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 regulations implementing section 407 of 
the Act.
    (2) The notification under paragraph (c)(1) of this section shall 
specify the first calendar year and the last calendar year for which the 
conditionally approved Acid Rain compliance option is to be activated. A 
conditionally approved compliance option shall be activated, if at all, 
before the date of any enforceable milestone applicable to the 
compliance option. The date of activation of the compliance option shall 
not be a defense against failure to meet the requirements applicable to 
that compliance option during each calendar year for which the 
compliance option is activated.
    (3) Upon submission of a notification meeting the requirements of 
paragraphs (c) (1) and (2) of this section, the conditionally-approved 
Acid Rain compliance option becomes binding on the owners and operators 
and the designated representative of any unit governed by the 
conditionally-approved compliance option.
    (4) A notification meeting the requirements of paragraphs (c) (1) 
and (2) of this section will revise the unit's permit in accordance with 
Sec. 72.83 (administrative permit amendment).
    (d) Termination of compliance option. (1) The designated 
representative for a unit may terminate an Acid Rain compliance option 
by notifying the permitting authority in writing that an approved 
compliance option will be terminated beginning January 1 of a specified 
year. If the compliance option includes a plan described in paragraph 
(b)(1) of this section, the designated representative for each source 
governed by the plan shall sign and certify the notification. Such 
notification shall be subject to the limitations on termination under 
subpart D of this part and regulations implementing section 407 of the 
Act.
    (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]



Sec. 72.41  Phase I substitution plans.

    (a) Applicability. This section shall apply during Phase I to the 
designated representative of:
    (1) Any unit listed in Table 1 of Sec. 73.10(a) of this chapter; and
    (2) Any other existing utility unit that is an affected unit under 
this part, provided that this section shall not apply to a unit under 
section 410 of the Act.
    (b)(1) The designated representative may include, in the Acid Rain 
permit application for a unit under paragraph (a)(1) of this section, a 
substitution plan under which one or more units under paragraph (a)(2) 
of this section are designated as substitution units, provided that:
    (i) Each unit under paragraph (a)(2) of this section is under the 
control of the owner or operator of each unit under paragraph (a)(1) of 
this section that designates the unit under paragraph (a)(2) of this 
section as a substitution unit; and
    (ii) In accordance with paragraph (c)(3) of this section, the 
emissions reductions achieved under the plan shall be the same or 
greater than would have

[[Page 44]]

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 90 days, or a notification to activate a conditionally 
approved plan in accordance with Sec. 72.40(c) not later than 60 days, 
before the allowance transfer deadline applicable to the first year for 
which the plan is to take effect.
    (c) Contents of a substitution plan. A complete substitution plan 
shall include the following elements in a format prescribed by the 
Administrator:
    (1) Identification of each unit under paragraph (a)(1) of this 
section and each substitution unit to be governed by the substitution 
plan. A unit shall not be a substitution unit in more than one 
substitution plan.
    (2) Except where the designated representative requests conditional 
approval of the plan, the first calendar year and, if known, the last 
calendar year in which the substitution plan is to be in effect. Unless 
the designated representative specifies an earlier calendar year, the 
last calendar year will be deemed to be 1999.
    (3) Demonstration that the total emissions reductions achieved under 
the substitution plan will be equal to or greater than the total 
emissions reductions that would have been achieved without the plan, as 
follows:
    (i) For each substitution unit:
    (A) The unit's baseline.
    (B) Each of the following: the unit's 1985 actual SO2 emissions 
rate; the unit's 1985 allowable SO2 emissions rate; the unit's 1989 
actual SO2 emissions rate; the unit's 1990 actual SO2 
emissions rate; and, as of November 15, 1990, the most stringent unit-
specific federally enforceable or State enforceable SO2 emissions 
limitation covering the unit for 1995-1999. For purposes of determining 
the most stringent emissions limitation, applicable emissions 
limitations shall be converted to lbs/mmBtu in accordance with appendix 
B of this part. Where the most stringent emissions limitation is not the 
same for every year in 1995-1999, the most stringent emissions 
limitation shall be stated separately for each year.
    (C) The lesser of: the unit's 1985 actual SO2 emissions rate; 
the unit's 1985 allowable SO2 emissions rate; the greater of the 
unit's 1989 or 1990 actual SO2 emissions rate; or, as of November 
15, 1990, the most stringent unit-specific federally enforceable or 
State enforceable SO2 emissions limitation covering the unit for 
1995-99. Where the most stringent emissions limitation is not the same 
for every year during 1995-1999, the lesser of the emissions rates shall 
be determined separately for each year using the most stringent 
emissions limitation for that year.
    (D) The product of the baseline in paragraph (c)(3)(i)(A) of this 
section and the emissions rate in paragraph (c)(3)(i)(C) of this 
section, divided by 2000 lbs/ton. Where the most stringent emissions 
limitation is not the same for every year during 1995-1999, the product 
in the prior sentence shall be calculated separately for each year using 
the emissions rate determined for that year in paragraph (c)(3)(i)(C) of 
this section.
    (ii)(A) The sum of the amounts in paragraph (c)(3)(i)(D) of this 
section for all substitution units to be governed by the plan. Except as 
provided in paragraph (c)(3)(ii)(B) of this section, this sum is the 
total number of allowances available each year under the substitution 
plan.
    (B) Where the most stringent unit-specific federally enforceable or 
State enforceable SO2 emissions limitation is not the same for 
every year during 1995-1999, the sum in paragraph (c)(3)(ii)(A) of this 
section shall be calculated separately for each year using the amounts 
calculated for that year in paragraph (c)(3)(i)(D) of this section. Each 
separate sum is the total number of allowances available for the 
respective year under the substitution plan.
    (iii) Where, as of November 15, 1990, a non-unit-specific federally 
enforceable or State enforceable SO2 emissions limitation covers 
the unit for any year

[[Page 45]]

during 1995-1999, the designated representative shall state each such 
limitation and propose a method for applying the unit-specific and non-
unit-specific emissions limitations under paragraph (d) of this section.
    (4) Distribution of substitution allowances. (i) A statement that 
the allowances in paragraph (c)(3)(ii) of this section are not to be 
distributed to any units under paragraph (a)(1) of this section that are 
to be governed by the plan; or
    (ii) A list showing any annual distribution of the allowances in 
paragraph (c)(3)(ii) of this section from a substitution unit to a unit 
under paragraph (a)(1) of this section that, under the plan, designates 
the substitution unit.
    (5) A demonstration that the substitution plan meets the requirement 
that each unit under paragraph (a)(2) of this section is under the 
control of the owner or operator of each unit under paragraph (a)(1) of 
this section that designates the unit under paragraph (a)(2) of this 
section as a substitution unit. The demonstration shall be one of the 
following:
    (i) If the unit under paragraph (a)(1) of this section has one or 
more owners or operators that have an aggregate percentage ownership 
interest of 50 percent or more in the capacity of the unit under 
paragraph (a)(2) of this section or the units have a common operator, a 
statement identifying such owners or operators and their aggregate 
percentage ownership interest in the capacity of the unit under 
paragraph (a)(2) of this section or identifying the units' common 
operator. The designated representative shall submit supporting 
documentation upon request by the Administrator.
    (ii) If the unit under paragraph (a)(1) of this section has one or 
more owners or operators that have an aggregate percentage ownership 
interest of at least 10 percent and less than 50 percent in the capacity 
of the unit under paragraph (a)(2) of this section and the units do not 
have a common operator, a statement identifying such owners or operators 
and their aggregate percentage ownership interest in the capacity of the 
unit under paragraph (a)(2) of this 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,

[[Page 46]]

the Administrator will determine, on a case-by-case basis, how to apply 
the non-unit-specific emissions limitation for purposes of determining 
whether the maximum annual average SO2 emissions rate meets the 
requirement of the prior sentence. If a non-unit-specific federally 
enforceable SO2 emissions limitation is not different from a non-
unit-specific federally enforceable SO2 emissions limitation that 
was effective and applicable to the unit in 1985, the Administrator will 
apply the non-unit-specific SO2 emissions limitation by using the 
1985 allowable SO2 emissions rate.
    (C) For each year that the actual SO2 emissions rate of the 
unit under paragraph (a)(2) of this section exceeds the maximum annual 
average SO2 emissions rate, the designated representative of the 
unit under paragraph (a)(1) of this section must surrender allowances 
for deduction from the Allowance Tracking System account of the unit 
under paragraph (a)(1) of this section. The designated representative 
shall surrender allowances authorizing emissions equal to the baseline 
of the unit under paragraph (a)(2) of this section multiplied by the 
difference between the actual SO2 emissions rate of the unit under 
paragraph (a)(2) of this section and the maximum annual average SO2 
emissions rate and divided by 2000 lbs/ton. The surrender shall be made 
by the allowance transfer deadline of the year of the exceedance, and 
the surrendered allowances shall have the same or an earlier compliance 
use date as the allowances allocated to the unit under paragraph (a)(2) 
of this section for that year. The designated representative may 
identify the serial numbers of the allowances to be deducted. In the 
absence of such identification, allowances will be deducted on a first-
in, first-out basis under Sec. 73.35(c)(2) of this chapter.
    (D) The unit under paragraph (a)(2) of this section and the unit 
under paragraph (a)(1) of this section shall designate a common 
designated representative during the period that the substitution plan 
is in effect. Having a common alternate designated representative shall 
not satisfy the requirement in the prior sentence.
    (E) Except as provided in paragraph (c)(6)(i) of this section, the 
actual SO2 emissions rate for any year and the average actual 
SO2 emissions rate for any period shall be determined in accordance 
with part 75 of this chapter.
    (6) A demonstration under paragraph (c)(5)(iii) of this section 
shall include the following supporting documentation:
    (i) The calculation of the average actual SO2 emissions rate 
and the most stringent federally enforceable or State enforceable 
SO2 emissions limitation for the unit for the four consecutive 
quarters that immediately preceded the 30-day period ending on the date 
the substitution plan is submitted to the Administrator. To the extent 
that the four consecutive quarters include a quarter prior to January 1, 
1995, the SO2 emissions rate for the quarter shall be determined 
applying the methodology for calculating SO2 emissions set forth in 
appendix C of this part. This methodology shall be applied using data 
submitted for the quarter to the Secretary of Energy on United States 
Department of Energy Form 767 or, if such data has not been submitted 
for the quarter, using the data prepared for such submission for the 
quarter.
    (ii) A description of the actions that will be taken in order for 
the unit under paragraph (a)(2) of this section to comply with the 
maximum annual average SO2 emissions rate under paragraph 
(c)(5)(iii) of this section.
    (iii) A description of any contract for implementing the actions 
described in paragraph (c)(6)(ii) of this section that was executed 
before the date on which the agreement under paragraph (c)(5)(iii) of 
this section is executed. The designated representative shall state the 
execution date of each such contract and state whether the contract is 
expressly contingent on the agreement under paragraph (c)(5)(iii) of 
this section.
    (iv) A showing that the actions described under paragraph (c)(6)(ii) 
of this section will not be implemented during Phase I unless the unit 
is approved as a substitution unit.
    (7) The special provisions in paragraph (e) of this section.

[[Page 47]]

    (d) Administrator's action. (1) If the Administrator approves a 
substitution plan, he or she will allocate allowances to the Allowance 
Tracking System accounts of the units under paragraph (a)(1) of this 
section and substitution units, as provided in the approved plan, upon 
issuance of an Acid Rain permit containing the plan, except that if the 
substitution plan is conditionally approved, the allowances will be 
allocated upon revision of the permit to activate the plan.
    (2) In no event shall allowances be allocated to a substitution 
unit, under an approved substitution plan, for any year in excess of the 
sum calculated and applicable to that year under paragraph (c)(3)(ii) of 
this section, as adjusted by the Administrator in approving the plan.
    (3) Where, as of November 15, 1990, a non-unit-specific federally 
enforceable or State enforceable SO2 emissions limitation covers 
the unit for any year during 1995-1999, the Administrator will specify 
on a case-by-case basis a method for using unit-specific and non-unit-
specific emissions limitations in allocating allowances to the 
substitution unit. The specified method will not treat a non-unit-
specific emissions limitation as a unit-specific emissions limitation 
and will not result in substitution units retaining allowances allocated 
under paragraph (d)(1) of this section for emissions reductions 
necessary to meet a non-unit- specific emissions limitation. Such method 
may require an end-of-year review and the adjustment of the allowances 
allocated to the substitution unit and may require the designated 
representative of the substitution unit to surrender allowances by the 
allowance transfer deadline of the year that is subject to the review. 
Any surrendered allowances shall have the same or an earlier compliance 
use date as the allowances originally allocated for the year, and the 
designated representative may identify the serial numbers of the 
allowances to be deducted. In the absence of such identification, such 
allowances will be deducted on a first-in, first-out basis under 
Sec. 73.35(c)(2) of this chapter.
    (e) Special provisions--(1) Emissions Limitations. (i) Each 
substitution unit governed by an approved substitution plan shall become 
a Phase I unit from January 1 of the year for which the plan takes 
effect until January 1 of the year for which the plan is no longer in 
effect or is terminated. The designated representative of a substitution 
unit shall surrender allowances, and the Administrator will deduct 
allowances, in accordance with paragraph (d)(3) of this section.
    (ii) Each unit under paragraph (a)(1) of this section, and each 
substitution unit, governed by an approved substitution plan shall be 
subject to the Acid Rain emissions limitations for nitrogen oxides in 
accordance with section 407 of the Act and regulations implementing 
section 407 of the Act.
    (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

[[Page 48]]

(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 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

[[Page 49]]

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 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]



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

[[Page 50]]

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

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

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

[[Page 51]]

    (8) For each control unit, the number of Phase I extension reserve 
allowances requested for 1997, for 1998, and for 1999, calculated as 
follows:
    The unit's baseline multiplied by 1.2 lbs/mmBtu and divided by 2000 
lbs/ton, minus the projected controlled emissions (in tons/yr) under 
paragraph (c)(7) of this section for the given year.
    (9) The total of Phase I extension reserve allowances requested for 
all units in the plan for 1995 through 1999.
    (10) With regard to each executed contract for the design 
engineering and construction of qualifying Phase I technology at each 
control unit governed by the early ranking application, either a copy of 
the contract or a certification that the contract is on site at the 
source and will be submitted to the Administrator upon written request. 
The contract or contracts may be contingent on the Administrator 
approving the Phase I extension plan.
    (11) For each contract for which a certification is submitted under 
paragraph (c)(10) of this section, a binding letter agreement, signed 
and dated by each party and specifying:
    (i) The type of qualifying Phase I technology to which the contract 
applies;
    (ii) The parties to the contract;
    (iii) The date each party executed the contracts;
    (iv) The unit to which the contract applies;
    (v) A brief list identifying each provision of the contract;
    (vi) Any dates to which the parties agree, including construction 
completion date; and
    (vii) The total dollar amount of the contract.
    (12) A vendor certification of the sulfur dioxide removal efficiency 
guaranteed to be achievable by the qualifying Phase I technology for the 
type and range of fossil fuels (before any treatment prior to 
combustion) that will be used at the control unit; provided that a 
vendor certification shall not be a defense against a control unit's 
failure to achieve 90% control of sulfur dioxide.
    (13) The date (not later than December 31, 1996) on which the owners 
and operators plan to commence operation of the qualifying Phase I 
technology.
    (14) The special provisions of paragraph (f) of this section.
    (d) Contents of Phase I extension plan. A complete Phase I extension 
plan shall include the following elements in a format prescribed by the 
Administrator:
    (1) Identification of each unit in the plan.
    (2)(i) A statement that the elements in the Phase I extension plan 
are identical to those in the previously submitted early ranking 
application for the plan and that such early ranking application is 
incorporated by reference; or
    (ii) All elements that are different from those in the previously 
submitted early ranking application for the plan and a statement that 
the early ranking application is incorporated by reference as modified 
by the newly submitted elements; provided that the Phase I extension 
plan shall not add any new control units or increase the total Phase I 
extension allowances requested; or
    (iii) All elements required for an early ranking application and a 
statement that no early ranking application for the plan was submitted.
    (e) Administrator's action. (1) Early ranking applications. (i) The 
Administrator may approve in whole or in part or with changes or 
conditions, as appropriate, or disapprove an early ranking application.
    (ii) The Administrator will act on each early ranking application in 
the order of receipt.
    (iii) The Administrator will determine the order of receipt by the 
following procedures:
    (A) Hand-delivered submissions and mailed submissions will be deemed 
to have been received on the date they are received by the 
Administrator; provided that all submissions received by the 
Administrator prior to the 40th day after publication of this subpart in 
the Federal Register will be deemed received on the 40th day.
    (B) All submissions received by the Administrator on the same day 
will be

[[Page 52]]

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 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.

[[Page 53]]

    (iii) For 1997, to each control unit in the order in which it is 
listed in the plan, then likewise for 1998, and then likewise for 1999.
    (iv) The Administrator will allocate any Phase I extension reserve 
allowances returned to the Administrator to the next Phase I extension 
plan, in the rank order established under paragraph (e)(1)(iii) of this 
section, that continues to meet the requirements of this section and 
this part.
    (f) Special provisions--(1) Emissions Limitations--(i) Sulfur 
Dioxide.
    (A) If a control or transfer unit governed by an approved Phase I 
extension plan emits in 1997, 1998, or 1999 sulfur dioxide in excess of 
the projected controlled emissions for the unit specified for the year 
under paragraph (c)(7) of this section as adjusted under paragraph (d) 
of this section and by the Administrator in approving the Phase I 
extension plan, the Administrator will deduct allowances equal to such 
exceedence from the unit's annual allowance allocation in the following 
calendar year.\2\
---------------------------------------------------------------------------

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

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

Allowances deducted=(1-(percent reduction 
    achievedbullet90%)) 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.

[[Page 54]]



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 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. 72.92;

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

[[Page 55]]

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 90 days, or a notification to activate a conditionally 
approved plan in accordance with Sec. 72.40(c) not later than 60 days, 
before the allowance transfer deadline applicable to the first year for 
which the plan is to take effect.
    (5) The designated representative of each source with a unit 
designated as a compensating unit in any plan submitted under paragraphs 
(b) (1) or (4) of this section shall incorporate by reference in the 
permit application each such plan.
    (c) Contents of reduced utilization plan. A complete reduced 
utilization plan shall include the following elements in a format 
prescribed by the Administrator:
    (1) Identification of each Phase I unit for which the owners and 
operators plan reduced utilization.
    (2) Except where the designated representative requests conditional 
approval of the plan, the first calendar year and, if known, the last 
calendar year in which the reduced utilization plan is to be in effect. 
Unless the designated representative specifies an earlier calendar year, 
the last calendar year shall be deemed to be 1999.
    (3) A statement whether the plan designates a compensating unit or 
relies on sulfur-free generation, any energy conservation measure, or 
any improved unit efficiency measure to account for any amount of 
reduced utilization.
    (4) If the plan designates a compensating unit, or relies on sulfur-
free generation, to account for any amount of reduced utilization:
    (i) Identification of each compensating unit or sulfur-free 
generator.
    (ii) For each compensating unit. (A) Each of the following: The 
unit's 1985 actual SO2 emissions rate; the unit's 1985 allowable 
emissions rate; the unit's 1989 actual SO2 emissions rate; the 
unit's 1990 actual SO2 emissions rate; and, as of November 15, 
1990, the most stringent unit-specific federally enforceable or State 
enforceable SO2 emissions limitation covering the unit for 1995-
1999. For purposes of determining the most stringent emissions 
limitation, applicable emissions limitations shall be converted to lbs/
mmBtu in accordance with appendix B of this part. Where the most 
stringent emissions limitation is not the same for every year in 1995-
1999, the most stringent emissions limitation shall be stated separately 
for each year.
    (B) The unit's baseline divided by 2,000 lbs/ton and multiplied by 
the lesser of the unit's 1985 actual SO2 emissions rate or 1985 
allowable SO2 emissions rate.
    (C) The unit's baseline divided by 2000 lbs/ton and multiplied by 
the lesser of: The greater of the unit's 1989 or 1990 actual SO2 
emissions rate; or, as of November 15, 1990, the most stringent unit-
specific federally enforceable or State enforceable SO2 emissions 
limitation covering the unit for 1995-1999. Where the most stringent 
emissions limitation is not the same for every year in 1995-1999, the 
calculation in the prior sentence shall be made separately for each 
year.
    (D) The difference between the amount under paragraph (c)(4)(ii)(B) 
of this section and the amount under paragraph (c)(4)(ii)(C) of this 
section. If the difference calculated in the prior sentence for any year 
exceeds the lesser of 10 percent of the amount under paragraph 
(c)(4)(ii)(B) of this section or 200 tons, the unit shall not be 
designated as a compensating unit for the year. Where the most stringent 
unit-specific federally enforceable or State enforceable SO2 
emissions limitation is not the same for every year in 1995-1999, the 
difference shall be calculated separately for each year.
    (E) The allowance allocation calculated as the amount under 
paragraph (c)(4)(ii)(B) of this section. If the compensating unit is a 
new unit, it shall be deemed to have a baseline of zero and shall be 
allocated no allowances.

[[Page 56]]

    (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.
    (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 section 407 of the Act and regulations 
implementing section 407 of the Act.
    (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.

[[Page 57]]

    (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:
    (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]



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.

[[Page 58]]

    (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
    (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.

[[Page 59]]

    (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 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 proposed permit revision, 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. 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

[[Page 60]]

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 proposed permit revision, 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. 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 21, 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 section 407 of the 
Act and regulations implementing section 407 of the Act 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]

[[Page 61]]



                  Subpart E--Acid Rain Permit Contents



Sec. 72.50  General.

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



Sec. 72.51  Permit shield.

    Each affected unit operated in accordance with the Acid Rain permit 
that governs the unit and that was issued in compliance with title IV of 
the Act, as provided in this part and parts 73, 75, 77, and 78 of this 
chapter, and the regulations implementing section 407 of the Act, shall 
be deemed to be operating in compliance with the Acid Rain Program, 
except as provided in Sec. 72.9(g)(6) of this part.



         Subpart F--Federal Acid Rain Permit Issuance Procedures



Sec. 72.60  General.

    (a) Scope. This subpart contains the procedures for federal issuance 
of Acid Rain permits for Phase I of the Acid Rain Program and Phase II 
for sources in States or geographic areas where the Administrator is the 
permitting authority as provided under regulations implementing title V 
of the Act. 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. 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.



Sec. 72.61  Completeness.

    (a) Determination of Completeness. The Administrator will determine 
whether the Acid Rain permit application is complete within 30 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 30 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) The designated representative shall submit the information 
required under paragraph (b)(1) of this section within 30 days after he 
or she is notified of the requirement for supplemental information 
unless the Administrator allows for additional time to collect and 
submit the information.
    (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.



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.

[[Page 62]]

    (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
    (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 State or local air pollution agency and any State or local 
utility regulatory authority with jurisdiction over the owners of any 
source or any unit covered by the Acid Rain permit application;
    (iii) The State or local air pollution agency for any contiguous 
State whose air quality may be affected by, or for any State located 
within a 50-mile radius of, any source covered by the Acid Rain permit 
application; and
    (iv) 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.

[[Page 63]]

    (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.



Sec. 72.66  Public comments.

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



Sec. 72.67  Opportunity for public  hearing.

    (a) During the public comment period, any person may request a 
public hearing. A request for a public hearing shall be made in writing 
and shall state the issues proposed to be raised in the hearing.
    (b) On the Administrator's own motion or on the request of any 
person, the Administrator may, at his or her

[[Page 64]]

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 any persons 
who are entitled to written notice under Sec. 72.65(b)(1) (ii), (iii), 
and (iv) of this part. 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.



              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 the requirements with which State 
permitting authorities with approved programs shall comply, and with 
which the Administrator will comply in the absence of an approved 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 part 70, and part 78 of this chapter for the purpose of 
incorporating Acid Rain Program requirements into each affected source's 
operating permit or for issuing written exemptions under Secs. 72.7 and 
72.8. To the extent that any requirements of this part and part 78 of 
this chapter are inconsistent with the requirements of part 70 of this 
chapter, this part and part 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. For purposes of 
applying this subpart, the provisions of this subpart and of part 70 
applicable to Acid Rain permit applications and draft, proposed, and 
final Acid Rain permits shall also apply to petitions for exemption and 
draft, proposed, and final written exemptions respectively for new or 
retired units to the extent consistent with Secs. 72.7 and 72.8 of this 
chapter.



Sec. 72.71  Approval of state programs--general.

    (a) Each State shall submit, to the Administrator for approval, a 
proposed operating permit program meeting the requirements of this 
subpart and part 70 of this chapter.
    (b) The Administrator will act on State submissions of an operating 
permit program in accordance with the schedule and procedures set forth 
in Sec. 70.4(e) of this chapter. The Administrator will approve State 
programs that conform to the applicable requirements of this subpart and 
Sec. 70.4(b) of this chapter.

[[Page 65]]

    (c)(1) After approval of a State operating permit program, the 
Administrator will suspend, in accordance with this part and part 70 of 
this chapter, federal issuance of Acid Rain permits for Phase II for 
sources and units subject to the State program.
    (2) The Administrator will issue all Acid Rain permits for Phase I. 
However, the Administrator reserves the right to delegate the remaining 
administration of Acid Rain permits for Phase I to approved State 
operating permit programs.



Sec. 72.72  State permit program approval criteria.

    A State operating permit program shall meet the following criteria 
concerning the Acid Rain Program. Any aspect of the State program or any 
implementation of the State program that is inconsistent with these 
criteria shall be grounds for disapproval or withdrawal of approval of 
the State 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;
    (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:
    (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.
    (C) Submission to the Administrator. The State permitting authority 
shall submit a written notice of application completeness to the 
Administrator

[[Page 66]]

within 10 working days following a determination by the State permitting 
authority that the Acid Rain permit application is complete.
    (ii) Draft permit. (A) The State permitting authority shall prepare 
the draft Acid Rain permit in accordance with subpart E of this part or, 
for a combustion or process source, subpart B of part 74 of this 
chapter, or deny a draft Acid Rain permit.
    (B) The State permitting authority shall prepare a statement of 
basis in accordance with the requirements for a statement of basis under 
Sec. 72.64 of this part.
    (C) 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) Notice to Administrator. The State permitting authority shall 
submit a copy of the draft Acid Rain permit and the statement of basis 
to the Administrator and all other relevant portions of the operating 
permit that may affect the draft Acid Rain permit. This submission 
requirement will not be waived.
    (iv) 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. A 
notice shall be served on those persons required to receive notice under 
Secs. 70.7(h) and 70.8(b) of this chapter.
    (v) Proposed Permit. Following the public notice and comment period 
on a draft Acid Rain permit, the permitting authority shall incorporate 
all changes necessary and issue a proposed Acid Rain permit in 
accordance with subpart E of this part or, for combustion or process 
sources, in accordance with subpart B of part 74 of this chapter or deny 
a proposed Acid Rain permit.
    (vi) Submittal to Administrator. (A) The State permitting authority 
shall submit the proposed Acid Rain permit or denial of a proposed Acid 
Rain permit to the Administrator in accordance with Sec. 70.8(a) of this 
chapter, the provisions of which shall be treated as applying to the 
issuance or denial of a proposed Acid Rain permit.
    (B) The Administrator will review the proposed Acid Rain permit or 
denial of a proposed Acid Rain permit in accordance with Sec. 70.8(c) of 
this chapter, the provisions of which shall be treated as applying to 
the issuance or denial of a proposed Acid Rain permit.
    (vii) Acid Rain Permit Issuance. Following the Administrator's 
review of the proposed Acid Rain permit or denial of a proposed Acid 
Rain permit, the State permitting authority shall or, under Sec. 70.8(c) 
of this chapter (treated as applying to the issuance or denial of an 
Acid Rain permit), the Administrator will, incorporate any required 
changes and issue or deny the Acid Rain permit in accordance with 
subpart E of this part.
    (viii) Effective Date of Acid Rain Permit. Each source's Acid Rain 
permit issued by a State permitting authority under this section shall 
be effective for a period of 5 years.
    (ix) 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.
    (x) 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.
    (xi) Invalidation of the Acid Rain portion of an operating permit 
shall not affect the continuing validity of the rest of the operating 
permit, nor shall invalidation of any other portion of the operating 
permit affect the continuing validity of the Acid Rain portion of the 
permit.
    (xii) 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.

[[Page 67]]

    (xiii) Notwithstanding any State law providing that a permit must be 
issued by default after a specified time, no Acid Rain permit shall be 
issued until the Administrator and other States have had an opportunity 
to review a proposed Acid Rain permit as provided in this section and 
Sec. 70.8(b) of this chapter.
    (xiv) 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, parts 73, 74, 75, 76, 77 and 78 of this 
chapter, shall be conducted according to procedures established by the 
State under Sec. 70.4(b)(3)(x) 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) Under no circumstances shall a State administrative appeal or 
judicial appeal of the Acid Rain portion of an operating permit be 
allowed more than 90 days (or such shorter period as provided by the 
applicable State appeals procedures) following respectively issuance of 
the Acid Rain portion that is subject to administrative appeal or 
issuance of the final agency action subject to judicial appeal.
    (iii) The State permitting authority shall serve written notice on 
the Administrator of any State administrative or judicial appeal 
concerning as Acid Rain provision of any operating permit or denial of 
an Acid Rain portion of any operating permit within 30 days of the 
filing of the appeal.
    (iv) Any State administrative permit appeals procedures shall ensure 
that the Administrator may intervene as a matter of right in any permit 
appeal involving an Acid Rain permit provision or denial of an Acid Rain 
permit.
    (v) The State permitting authority shall serve written notice on the 
Administrator of any determination or order in a State administrative or 
judicial proceeding that interprets, modifies, voids, or otherwise 
relates to any portion of an Acid Rain permit. Following any such 
determination or order, the Administrator will have an opportunity to 
review and veto the Acid Rain permit or revoke the permit for cause in 
accordance with Sec. 70.8 of this chapter.
    (vi) A failure of the State permitting authority to issue an Acid 
Rain permit in accordance with Sec. 72.73(b)(1)(i) or, with regard to 
combustion or process sources, Sec. 74.14(c)(6) of this chapter shall be 
ground for filing an appeal.
    (vii) No appeal concerning an Acid Rain requirement shall result in 
a stay of any provision of the Acid Rain permit for which a stay is 
barred under part 78 of this chapter.
    (6) Cooperation with Utility Regulatory Authority. In considering 
any Acid Rain permit application, the State permitting authority shall 
ensure coordination with any utility regulatory authority with 
jurisdiction over the owners of the affected unit.

[[Page 68]]

    (7) New Units and Retired Units Exemptions. The State permitting 
authority shall act in accordance with Secs. 72.7 and 72.8 on any 
petition for exemption of a new unit or retired unit from requirements 
of the Acid Rain Program.
    (8) State Permit Evaluation. The State permitting authority shall 
periodically evaluate the extent to which its operating permit program 
meets the Acid Rain Program requirements and supports a cost-effective 
implementation of the program. The permit fee rates set by the State 
permitting authority shall be adequate to cover such evaluation.

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



Sec. 72.73  State issuance of Phase II permits.

    (a) State Permit Issuance. (1) A State with an operating permit 
program that has been approved by the Administrator under this part and 
part 70 of this chapter on or before July 1, 1996, shall be responsible 
for issuing Acid Rain permits for Phase II to all affected sources in 
that State.
    (2) A State that has obtained interim operating permit program 
approval (as defined in Sec. 70.4(d) of this chapter) on or before July 
1, 1996 shall be responsible for issuing Acid Rain permits for Phase II 
to all affected sources in that State.
    (3) A State that has obtained partial operating permit program 
approval (as defined in Sec. 70.4(c) of this chapter) on or before July 
1, 1996 shall be responsible for issuing Acid Rain permits for Phase II 
to all affected sources in the geographic area to which the partial 
approval applies.
    (4) 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)(i) On or before December 31, 1997, 
a State with an approved operating permit program shall issue an Acid 
Rain permit for Phase II to each affected source in the geographic area 
for which the program is approved as set forth in paragraph (a) of this 
section; provided that the designated representative of the source 
submitted a timely and complete Acid Rain permit application in 
accordance with Sec. 72.21 of this part and meets the requirements of 
this subpart and part 70 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 (b)(1)(i) 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.
    (2) Nitrogen Oxides. Not later than January 1, 1999, the State 
permitting authority shall reopen the Acid Rain permit to add the 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. Such reopening shall not affect the term of the Acid Rain 
portion of an operating permit.



Sec. 72.74  Federal issuance of Phase II permits.

    (a) The Administrator will be responsible for issuing Acid Rain 
permits for Phase II for any affected sources in a geographic area 
(including a State) that does not have an operating permit program with 
full, partial, or interim approval by the Administrator on or before 
July 1, 1996, under part 70 of this chapter. After approval of a State 
program, the Administrator will suspend, in accordance with this part 
and part 70 of this chapter, federal issuance of such permits for 
sources in the geographic area covered by the State program and the 
State shall be responsible for issuing such permits in accordance with 
Sec. 72.73 of this part.
    (b) Permit Issuance Deadline. (1)(i) On or before January 1, 1998, 
the Administrator will issue an Acid Rain permit for Phase II governing 
Acid Rain Program sulfur dioxide requirements to each affected source in 
a geographic area that, on July 1, 1996, did not have an approved 
operating permit program under part 70 of this chapter; provided that 
the designated representative for the source submitted a timely and 
complete Acid Rain permit application in accordance with Sec. 72.21 of 
this part.

[[Page 69]]

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) Notwithstanding paragraph (b)(1)(i) of this section, the 
Administrator may delegate to any State that obtains operating permit 
program approval after July 1, 1996, responsibility for permit review 
and implementation.
    (iii) 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 (b)(1) shall take effect 
by the later of January 1, 2000 or, where a permit governs a unit under 
Sec. 72.6(a)(3) of this part, 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 a timely and complete Acid Rain permit 
application for nitrogen oxides, the Administrator shall reopen the Acid 
Rain permit for Phase II to add the Acid Rain Program nitrogen oxides 
requirements. Such reopening shall not affect the term of the Acid Rain 
permit.
    (c) Permit Issuance. The Administrator will issue Acid Rain permits 
for Phase II in accordance with subparts E and F of this part and the 
regulations implementing title V of the Act.

[58 FR 3650, Jan. 11, 1993; 58 FR 40747, July 30, 1993]



                       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 with an approved operating permit 
program under part 70 of this chapter.
    (b) The provisions of this subpart shall supersede the operating 
permit revision procedures specified in part 70 of this chapter with 
regard to 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.
    (e) Any determination or interpretation by a State (including a 
State court) modifying or voiding any Acid Rain permit provision shall 
be subject to review by the Administrator in accordance with 
Sec. 70.8(c) of this chapter as applied to permit modifications, unless 
the determination or interpretation is an administrative amendment 
approved in accordance with Sec. 72.83 of this part.
    (f) The standard requirements of Sec. 72.9 of this part shall not be 
modified or voided by a permit revision.
    (g) 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 and section 407 of the Act and 
regulations implementing section 407 of the Act.
    (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.



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:

[[Page 70]]

    (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 and Sec. 70.7(e)(4)(ii) of this chapter, 
where the State is the permitting authority.
    (2) For purposes of applying paragraph (c)(1) of this section, a 
permit modification shall be treated as an Acid Rain permit application, 
to the extent consistent with this subpart.

[58 FR 3650, Jan. 11, 1993, as amended at 60 FR 17114, Apr. 4, 1995]



Sec. 72.82  Fast-track modifications.

    The following procedures shall apply to all fast-track 
modifications.
    (a) The designated representative shall serve a copy of the fast-
track modification on the Administrator, the permitting authority, and 
any person entitled to a written notice under Sec. 72.65(b)(1) (ii), 
(iii) and (iv) of this part. 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 
source is located or in a State publication designed to give general 
public notice.
    (b) The public shall have a period of 30 days, commencing on the 
date of publication of the notice, to comment on the fast-track 
modification. Comments shall be submitted in writing to the permitting 
authority and to the designated representative.
    (c) The designated representative shall submit the fast-track 
modification to the permitting authority on or before commencement of 
the public comment period.
    (d) Within 30 days of the close of the public comment period, 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 effective immediately upon issuance, in accordance 
with Sec. 70.7(a)(1)(v) of this chapter as applied to significant permit 
modifications.



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

[[Page 71]]

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 regulations implementing section 407 of the Act 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) Incorporation of changes that the Administrator has determined 
to be similar to those in paragraphs (a)(1) through (11) of this 
section.
    (b) Administrative amendments shall follow the procedures set forth 
at Sec. 70.7(d)(3) of this chapter. Where the State is the permitting 
authority, the permitting authority shall submit the revised portion of 
the permit to the Administrator within 10 working days after the date of 
final action on the request for an administrative amendment.

[58 FR 3650, Jan. 11, 1993, as amended at 60 FR 17114, Apr. 4, 1995]



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) As provided in Sec. 70.7(f) of this chapter, the permitting 
authority shall reopen an Acid Rain permit for cause, including whenever 
additional requirements become applicable to any affected unit governed 
by the permit.
    (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)(2) and 72.74(b)(2) of this part, 
the permitting authority shall reopen an Acid Rain permit to incorporate 
nitrogen oxides requirements, consistent with section 407 of the Act and 
regulations implementing section 407 of the Act.
    (d) Any reopening of an Acid Rain permit shall not affect the term 
of the permit.



                   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;

[[Page 72]]

    (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 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;
    (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.



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

[[Page 73]]

in accordance with part 75 of this chapter) before the employment of any 
improved unit efficiency measures under an approved plan:

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

where:

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

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

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

[GRAPHIC] [TIFF OMITTED] TC01SE92.000

where:

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

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

    (D) If the result of the formula for ``shift to sulfur-free 
generator'' is less than or equal to zero, then ``shift to sulfur-free 
generator'' is zero.
    (iv) ``Shifts to designated compensating units'' is the reduction in 
utilization (in mmBtu) for the calendar year 
that is accounted for by increased generation at compensating units 
designated under the reduced utilization 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 

[[Page 74]]

and the compensating unit have certified (in their respective annual 
compliance certification reports) as the amount that will be converted 
to mmBtus and used, in accordance with paragraph (a)(4) of this section, 
in calculating the adjusted utilization for the compensating unit.
    (4) ``Compensating generation provided to other units'' is the total 
amount of utilization (in mmBtu) necessary to provide the generation (if 
any) that was shifted to the unit as a designated compensating unit 
under any other reduced utilization plans that were in effect for the 
unit and for the calendar year. This term equals the heat rate, under 
paragraph (a)(3) of this section, of such unit multiplied by the sum of 
each ``shift to compensating unit'' that is attributed to the unit in 
the annual compliance certification reports submitted by the Phase I 
units under such other plans and that is certified under paragraph 
(a)(3)(iv) of this section.
    (5) Notwithstanding paragraphs (a)(3) (i), (ii), and (iii) of this 
section, where two or more Phase I units include in ``plan reductions'', 
in their annual compliance certification reports for the calendar year, 
expected kilowatt hour savings or reduction in heat rate from the same 
specific conservation or improved unit efficiency measures or increased 
utilization of the same sulfur-free generator:
    (i) The designated representatives of all such units shall submit 
with their annual reports a certification signed by all such designated 
representatives. The certification shall apportion the total kilowatt 
hour savings, reduction in heat rate, or increased utilization among 
such units.
    (ii) Each designated representative shall include in the annual 
report only the respective unit's share of the total kilowatt hour 
savings, reduction in heat rate, or increased utilization, in accordance 
with the certification under paragraph (a)(5)(i) of this section.
    (6)(i) Where a unit includes in ``plan reductions'' under paragraph 
(a)(3) of this section the increase in utilization of any sulfur-free 
generator, the designated representative of the unit shall submit, with 
the annual compliance certification report, documentation demonstrating 
that an amount of electrical energy at least equal to the ``shift to 
sulfur-free generator'' attributed to the sulfur-free generator in the 
annual report was actually acquired by the unit's dispatch system from 
the sulfur-free generator.
    (ii) Where a unit includes in ``plan reductions'' under paragraph 
(a)(3) of this section utilization of any compensating unit, the 
designated representative of the unit shall submit with the annual 
compliance certification report, documentation demonstrating that an 
amount of electrical energy at least equal to the ``shift to 
compensating unit'' attributed to the compensating unit in the annual 
report was actually acquired by the unit's dispatch system from the 
compensating unit.
    (7) Notwithstanding paragraphs (a)(3)(i), (ii), (iii), and (iv), 
(a)(4), and (a)(5) of this section, ``plan reductions'' minus 
``compensating generation provided to other units'' shall not exceed 
``baseline'' minus ``actual utilization.''
    (b) Confirmation report. (1) If a unit's annual compliance 
certification report estimates any expected kilowatt hour savings or 
improvement in heat rate from energy conservation or improved unit 
efficiency measures under a reduced utilization plan, the designated 
representative shall submit, by July 1 of the year in which the annual 
report was submitted, a confirmation report. The Administrator may 
grant, for good cause shown, an extension of the time to file the 
confirmation report. The confirmation report shall include the following 
elements in a format prescribed by the Administrator:
    (i) The verified kilowatt hour savings from each such energy 
conservation 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 measures under 
an approved reduced utilization plan.

[[Page 75]]

    (ii) The verified reduction in the heat rate achieved by each 
improved unit efficiency measure and the verified corresponding 
reduction in the unit's heat input resulting from such measure.
    (iii) For all figures 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 and 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.
    (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 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 units'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 hear input 
          reduction)  x  emissions rate bullet 2000 lbs/ton

where:

    (i) ``Verified heat input reduction'' is the total of the amounts of 
verified reduction in the units' 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.
    (5) 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 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, which equals the 
absolute value of the result of the formula for allowances credited 
under paragraph (b)(4) of this section.

[[Page 76]]

    (6) Unless paragraph (b)(3) of this section applies, the designated 
representative shall include in the confirmation report the adjusted 
amount of allowances that would have held in the unit'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 unit's heat input from energy conservation and improved efficiency 
measures, calculated as follows:

Adjusted amount of allowances=allowances held after deduction-excess 
          emissions + allowances credited-allowances deducted

where:

    (i) ``Allowances held after deductions'' is the amount of allowances 
held in the unit's compliance subaccount after deductions were made 
under Sec. 73.35(b) of this chapter based on the annual compliance 
certification report.
    (ii) ``Excess emission'' is the amount (if any) of excess emissions 
determined under Sec. 73.35(b) for the calendar year based on the annual 
compliance certification report.
    (iii) ``Allowances credited'' is the amount of allowances calculated 
under paragraph (b)(4) of this section.
    (iv) ``Allowances deducted'' is the amount of allowances calculated 
under paragraph (b)(5) of this section.
    (v) If the result of the formula for ``adjusted amount of 
allowances'' is negative, the absolute value of the result constitutes 
excess emissions of sulfur dioxide. If the result is positive, there are 
no excess emissions of sulfur dioxide.
    (7) If the amount of excess emissions of sulfur dioxide calculated 
under paragraph (b)(6) of this section differs from the amount of excess 
emissions of sulfur dioxide determined under Sec. 73.35(b) of this 
chapter based on the annual compliance certification report, then the 
designated representative shall include in the confirmation report a 
demonstration of: 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 the 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(c)(2) of this chapter and the return will be at the 
Administrator's discretion.
    (8) If the designated representative of a unit fails to submit on a 
timely basis a confirmation report (in accordance with paragraph (b) of 
this section) with regard to the estimate of expected kilowatt hour 
savings or improvement in heat rate from any energy conservation or 
improved unit efficiency measure under the reduced utilization plan, 
then the Administrator will reject such estimate and correct it to equal 
zero in the unit's annual compliance certification report that includes 
that estimate. The Administrator will deduct immediately, on a first-in, 
first-out basis under Sec. 73.35(c)(2) of this chapter, the amount of 
allowances that he or she determines is necessary to offset any increase 
in excess emissions of sulfur dioxide that results from the correction 
and require the owners and operators to pay an excess emission penalty 
in accordance with part 77 of this chapter.

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



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.

[[Page 77]]

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

[[Page 78]]

    (ii) Calculating dispatch system aggregate baseline. ``Dispatch 
system aggregate baseline'' is the sum of the baselines (as defined in 
Sec. 72.2 of this chapter) for all Phase I units in the dispatch system.
    (iii) Calculating percentage change in dispatch system sales. 
``Percentage change in dispatch system sales'' is the ``percentage 
change in dispatch system sales'' under Sec. 72.91 (a)(3)(iii)(C); 
provided that if result of the formula in Sec. 72.91(a)(3)(iii)(C) is 
greater than or equal to zero, the value shall be treated as zero only 
for purposes of paragraph (c)(2) of this section.
    (iv) Calculating unit's share. ``Unit's share'' is the unit's 
adjusted utilization divided by the sum of the adjusted utilization for 
all Phase I units within the dispatch system that have adjusted 
utilization of greater than zero and is calculated as follows:
[GRAPHIC] [TIFF OMITTED] TC01SE92.001

  
where:

(A) Uunit = the unit's adjusted utilization for the calendar year;
(B) Ui = the adjusted utilization of a Phase I unit in the dispatch 
          system for the calendar year; and
(C) m = all Phase I units in the dispatch system having an adjusted 
          utilization greater than 0 for the calendar year.

    (v) Calculating emissions rate. ``Emissions rate'' (in lbs/mmBtu) is 
the weighted average emissions rate for sulfur dioxide of all units and 
generators, within and outside the dispatch system, that contributed to 
the dispatch system's electrical output for the year, calculated as 
follows:

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

Where:

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

[[Page 79]]


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 
(c)(2)(v)(F)(1) of this section, then the power production facility has 
no non-utility generator emissions rate for

[[Page 80]]

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 governed by an approved repowering plan shall notify the 
Administrator in writing at least 60 days in advance of

[[Page 81]]

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

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).



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/MMBtu. In general, 
the shorter the averaging period, the lower the annual equivalent would 
be. Thus, the annualization of limits is established by multiplying each 
federally enforceable limit by an annualization factor that is 
determined by the averaging period and whether or not it's a scrubbed 
unit.

[[Page 82]]



  Table A-1.--SO2 Emission 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.                                                               

      

[[Page 83]]



               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 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:

                                                                        
    max. design heat input               x  1 kw-hr            x  1 MWe 
------------------------------   x   ----------------   x  -------------
              3                          3413 Btu              1000 Kw  
                                                                        

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 II.
73.11  Revision of allocations.
73.12  Rounding procedures.
73.13  Procedures for submittals.
73.14--73.15  [Reserved]
73.16  Phase I early reduction credits.
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.

[[Page 84]]

   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.
73.74  Independent power producers written guarantee.
73.75  Application for an IPP written guarantee.
73.76  Approval and exercise of the IPP written guarantee.
73.77  Relationship of the independent power producers written guarantee 
          to the direct sale subaccount.

       Subpart F--Energy Conservation and Renewable Energy Reserve

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

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

                   Subpart G--Small Diesel Refineries

73.90  Allowance allocations for small diesel refineries.

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

    Editorial Note: Part 73 was amended by revising subpart A and by 
adding subparts B through D at 58 FR 3650, Jan. 11, 1993, effective 
February 10, 1993. A document which corrected the January 11, 1993, 
document was published at 58 FR 40746, July 30, 1993, effective on the 
date of publication. Therefore, it should be noted that sections which 
reference July 30, 1993, in the source note are corrections to the 
January 11, 1993, document and are effective July 30, 1993.



                    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

[[Page 85]]

exemption), 72.8 (retired unit exemption), 72.9 (standard requirements), 
72.10 (availability of information), and 72.11 (computation of time) of 
part 72, subpart A of this chapter, shall apply to this part. The 
procedures for appeals of decisions of the Administrator under this part 
are contained in part 78 of this chapter. Sections 73.3 (Definitions) 
and 73.4 (Deadlines), which were previously published with subpart E of 
this part--``Auctions, Direct Sales, and Independent Power Producers 
Written Guarantee'', are codified at 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 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
                                                                     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

[[Page 86]]

                                                                                                                
                                    Vermilion......................  2                         9735          263
Indiana...........................  Bailly.........................  7                        12256          331
                                                                     8                        17134          463
                                    Breed..........................  1                        20280          548
                                    Cayuga.........................  1                        36581          989
                                                                     2                        37415         1011
                                    Clifty Creek...................  1                        19620          530
                                                                     2                        19289          521
                                                                     3                        19873          537
                                                                     4                        19552          528
                                                                     5                        18851          509
                                                                     6                        19844          536
                                    Elmer W. Stout.................  50                        4253          115
                                                                     60                        5229          141
                                                                     70                       25883          699
                                    F.B. Culley....................  2                         4703          127
                                                                     3                        18603          503
                                    Frank E. Ratts.................  1SG1                      9131          247
                                                                     2SG1                      9296          251
                                    Gibson.........................  1                        44288         1197
                                                                     2                        44956         1215
                                                                     3                        45033         1217
                                                                     4                        44200         1195
                                    H.T. Pritchard.................  6                         6325          171
                                    Michigan City..................  12                       25553          691
                                    Petersburg.....................  1                        18011          487
                                                                     2                        35496          959
                                    R. Gallagher...................  1                         7115          192
                                                                     2                         7980          216
                                                                     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

[[Page 87]]

                                                                                                                
Minnesota.........................  High Bridge....................  6                         4158          112
Mississippi.......................  Jack Watson....................  4                        17439          471
                                                                     5                        35734          966
Missouri..........................  Asbury.........................  1                        15764          426
                                    James River....................  5                         4722          128
                                    LaBadie........................  1                        39055         1055
                                                                     2                        36718          992
                                                                     3                        39249         1061
                                                                     4                        34994          946
                                    Montrose.......................  1                         7196          194
                                                                     2                         7984          216
                                                                     3                         9824          266
                                    New Madrid.....................  1                        27497          743
                                                                     2                        31625          855
                                    Sibley.........................  3                        15170          410
                                    Sioux..........................  1                        21976          594
                                                                     2                        23067          623
                                    Thomas Hill....................  MB1                       9980          270
                                                                     MB2                      18880          510
New Hampshire.....................  Merrimack......................  1                         9922          268
                                                                     2                        21421          579
New Jersey........................  B.L. England...................  1                         8822          238
                                                                     2                        11412          308
New York..........................  Dunkirk........................  3                        12268          332
                                                                     4                        13690          370
                                    Greenidge......................  6                         7342          198
                                    Milliken.......................  1                        10876          294
                                                                     2                        12083          327
                                    Northport......................  1                        19289          521
                                                                     2                        23476          634
                                                                     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

[[Page 88]]

                                                                                                                
                                                                     8                        13626          368
                                    W.H. Sammis....................  5                        26496          716
                                                                     6                        43773         1183
                                                                     7                        47380         1280
                                    Walter C. Beckjord.............  5                         9811          265
                                                                     6                        25235          682
Pennsylvania......................  Armstrong......................  1                        14031          379
                                                                     2                        15024          406
                                    Brunner Island.................  1                        27030          730
                                                                     2                        30282          818
                                                                     3                        52404         1416
                                    Cheswick.......................  1                        38139         1031
                                    Conemaugh......................  1                        58217         1573
                                                                     2                        64701         1749
                                    Hatfield's Ferry...............  1                        36835          995
                                                                     2                        36338          982
                                                                     3                        39210         1060
                                    Martins Creek..................  1                        12327          333
                                                                     2                        12483          337
                                    Portland.......................  1                         5784          156
                                                                     2                         9961          269
                                    Shawville......................  1                        10048          272
                                                                     2                        10048          272
                                                                     3                        13846          374
                                                                     4                        13700          370
                                    Sunbury........................  3                         8530          230
                                                                     4                        11149          301
Tennessee.........................  Allen..........................  1                        14917          403
                                                                     2                        16329          441
                                                                     3                        15258          412
                                    Cumberland.....................  1                        84419         2281
                                                                     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

[[Page 89]]

                                                                                                                
                                                                     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 E to be held in the 
future year subaccounts representing calendar years 2000 through 2009, 
except that units listed in both Table 2 and 4 will be allocated 
allowances as specified in Table 4 Column C, multiplied by .9011, 
reduced by 1.3185 times Table 2 Column B, and increased by Table 2 
Columns C and D.
    (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 I to be held in the future year subaccounts 
representing calendar years 2010 and each year thereafter, except that 
units listed in both Table 2 and 4 will be allocated allowances as 
specified in Table 4 Column F, multiplied by .8987, reduced by Table 2 
Column G, and increased by Table 2 Column H.

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    (c) Allowance allocation for units under Sec. 73.18. Upon adequate 
submittal of information under Sec. 73.18(b) and confirmation of unit 
eligibility under Sec. 73.18(c), the Administrator will allocate 
allowances to the unit account:
    (1) In the amount specified in Table 3 Column E to be held in the 
future year subaccounts representing calendar years 2000 through 2009; 
and
    (2) In the amount specified in the Table 3 Column I to be held in 
the future year subaccounts representing calendar years 2010 and each 
year thereafter.

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    (d) Allowance allocation for units under Sec. 73.19. (1) Upon 
submittal of adequate information under Sec. 73.19(b) and confirmation 
of unit eligibility under Sec. 73.19, the Administrator will allocate 
allowances to the unit account:
    (i) In the amount specified in Table 2 Column E to be held in the 
future year subaccounts representing calendar years 2000 through 2009; 
and
    (ii) In the amount specified in the Table 2 Column I to be held in 
the future year subaccounts representing calendar years 2010 and each 
year thereafter.
    (2) Units listed in Table 4 which do not submit adequate information 
under Sec. 73.19(b) or which are not eligible under Sec. 73.19 will be 
allocated allowances as calculated under Sec. 73.11.

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[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]

[[Page 144]]



Sec. 73.11  Revision of allocations.

    No later than June 1, 1998, the Administrator will allocate 
allowances to the unit accounts for each unit listed in Table 2 or 3 of 
Sec. 73.10, instead of the number of allowances specified in Tables 2, 
3, and 4, as follows:
    (a) The Administrator will allocate allowances to be held in the 
future year subaccounts representing calendar years 2000 through 2009 as 
follows:
    (1) Units eligible for allowances under Sec. 73.19(a) and that 
documentation according to Sec. 73.19(b) will have unadjusted basic 
allowances as listed in Table 2 Column A.
    (2) The Administrator will calculate unadjusted basic allowances 
(Year 2000) for existing units with approved repowering extension plans 
under Sec. 72.44 of this chapter according to the following equation, 
instead of unadjusted basic allowances listed in Table 2 Column A:
[GRAPHIC] [TIFF OMITTED] TC01SE92.053

    (3) Adjustment of basic allowances. The Administrator will adjust 
each unit's unadjusted basic allowances as listed in Table 2 Column A, 
Table 3 Column A and Table 4 Column C, and as stated in paragraphs (a) 
(1) and (2) of this section, as follows:
[GRAPHIC] [TIFF OMITTED] TC01SE92.054

    (4) Repowering adjustment. The Administrator will calculate a 
repowering 
deduction according to the following equation:
[GRAPHIC] [TIFF OMITTED] TC01SE92.055

where:

Set Aside=Sum of all repowering allowances for the year 2000 under 40 
CFR 73.21
Annual Set Aside=Set Aside/10

    (5) Special allowance reserve deduction. The Administrator will 
calculate a Special Allowance Deduction according to the following 
equation:
[GRAPHIC] [TIFF OMITTED] TC01SE92.056


[[Page 145]]


    (6) Conservation and renewable energy reserve. The Administrator 
will 
calculate the Conservation Deduction according to the following 
equation:
[GRAPHIC] [TIFF OMITTED] TC01SE92.057

    (7) Final allowance allocations. (i) (A) According to paragraphs (a) 
(1) through (6) of this section, the Administrator will revise the 
allowances allocated to each unit listed in Table 2 of Sec. 73.10 and 
will allocate to each unit's subaccount representing calendar years 2000 
through 2009 Final Revised Phase II Allowances according to the 
following equation:
[GRAPHIC] [TIFF OMITTED] TC01SE92.058

    (B) According to paragraphs (a) (1) through (6) of this section, the 
Administrator will revise the allowances allocated to each unit listed 
in Table 3 of Sec. 73.10 and will allocate to each unit's subaccount 
representing calendar years 2000 through 2009 Final Revised Phase II 
Allowances according to the following equation:
[GRAPHIC] [TIFF OMITTED] TC01SE92.059

    (C) According to paragraphs (a) (1) through (6) of this section, the 
Administrator will revise the allowances allocated to each unit listed 
in Table 4 of Sec. 73.10 (and not eligible for allocations under Table 
2) and will allocate to each unit's subaccount representing calendar 
years 2000 through 2009 Final Revised Phase II Allowances according to 
the following equation:
[GRAPHIC] [TIFF OMITTED] TC01SE92.060

    (ii) (A) If, as of January 1, 1998, both the auction and sales under 
subpart E of this part are terminated as provided for in subpart E, 
instead of allowances under paragraph (a)(7)(i) of this section, the 
Administrator will revise the allowances allocated to each unit listed 
in Table 2 of Sec. 73.10 and will allocate to each unit's subaccount 
representing calendar years 2000 through 2009 Final Revised Phase II 
Allowances according to the following equation:

[[Page 146]]

[GRAPHIC] [TIFF OMITTED] TC01SE92.061


    (B) If, as of January 1, 1998, both the auction and sales under 
subpart E of this part are terminated as provided for in subpart E, 
instead of allowances under paragraph (a)(7)(i) of this section, the 
Administrator will revise the allowances allocated to each unit listed 
in Table 3 of Sec. 73.10 and will allocate to each unit's subaccount 
representing calendar years 2000 through 2009 Final Revised Phase II 
Allowances according to the following equation:
[GRAPHIC] [TIFF OMITTED] TC01SE92.062

    (b) The Administrator will allocate allowances to be held in the 
future year subaccounts representing calendar years 2010 and each year 
thereafter as follows:
    (1) Units eligible for allowances under Sec. 73.19(a) and that 
documentation according to Sec. 73.19(b) will have unadjusted basic 
allowances as listed in Table 2 Column A.
    (2) The Administrator will calculate unadjusted basic allowances 
(Year 2010) for units with approved repowering extension plans under 
Sec. 72.44 of this chapter according to the following equation, instead 
of unadjusted basic allowances listed in Table 2 Column F:
[GRAPHIC] [TIFF OMITTED] TC01SE92.063

    (3) Adjustment of basic allowances. The Administrator will adjust 
each unit's unadjusted basic allowances as listed in Table 2 Column F, 
Table 3 Column F, and Table 4 Column F, and as stated in paragraphs (a) 
and (b) of this section, as follows:
[GRAPHIC] [TIFF OMITTED] TC01SE92.064

    (4) Repowering adjustment. The Administrator will calculate a 
repowering 
deduction according to the following equation:

[[Page 147]]

[GRAPHIC] [TIFF OMITTED] TC06JA94.000


where:
    Set Aside=Sum of all repowering allowances for the year 2000 under 
40 CFR Sec. 73.21
    Annual Set Aside=Set Aside/10

    (5) Special allowance reserve deduction. The Administrator will 
calculate a Special Allowance Deduction according to the following 
equation:
[GRAPHIC] [TIFF OMITTED] TC06JA94.001

    (6) Conservation and renewable energy reserve. The Administrator 
will cal- 
culate the Conservation Deduction according to the following equation:
[GRAPHIC] [TIFF OMITTED] TC06JA94.002

    (7) Final allowance allocations. (i) (A) According to paragraphs (b) 
(1) through (6) of this section, the Administrator will revise the 
allowances allocated to each unit listed in Table 2 of Sec. 73.10 and 
will allocate to each unit's subaccount representing calendar years 2010 
and each year thereafter according to the following equation:
[GRAPHIC] [TIFF OMITTED] TC06JA94.003

    (B) According to paragraphs (b) (1) through (6) of this section, the 
Administrator will revise the allowances allocated to each unit listed 
in Table 3 of Sec. 73.10 and will allocate to each unit's subaccount 
representing calendar years 2010 and each year thereafter according to 
the following equation:
[GRAPHIC] [TIFF OMITTED] TC06JA94.004

    (ii)(A) If, as of January 1, 1998, both the auction and sales under 
subpart E of this part are terminated as provided for in subpart E, 
instead of allowances under paragraph (b)(7)(i) of this section, the 
Administrator will revise the allowances allocated to each unit listed 
in Table 2 of Sec. 73.10 and will allocate to unit's subaccount 
representing calendar years 2010 and each year thereafter according to 
the following equation:

[[Page 148]]

[GRAPHIC] [TIFF OMITTED] TC06JA94.005


    (B) If, as of January 1, 1998, both the auction and sales under 
subpart E of this part are terminated as provided for in subpart E, 
instead of allowances under paragraph (b)(7)(i) of this section, the 
Administrator will revise the allowances allocated to each unit listed 
in Table 3 of Sec. 73.10 and will allocate to each unit's subaccount 
representing calendar years 2010 and each year thereafter according to 
the following equation:
[GRAPHIC] [TIFF OMITTED] TC06JA94.006

    (C) If, as of January 1, 1998, both the auction and sales under 
subpart E of this part are terminated as provided for in subpart E, 
instead of allowances under paragraph (a)(7)(i) of this section, the 
Administrator will revise the allowances allocated to each unit listed 
in Table 4 of Sec. 73.10 (and not eligible for allocations under Table 
2) and will allocate to each unit's subaccount representing calendar 
years 2010 and thereafter according to the following equation:
[GRAPHIC] [TIFF OMITTED] TC06JA94.007

[58 FR 15705, Mar. 23, 1993]


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) Achieving exact allowance reserves and allowance totals. (1) If 
the sum of adjusted basic allowances exceeds 8,900,000; the sum of the 
deductions for the repowering annual set aside is less than the annual 
set aside; the sum of the deductions for the Energy Conservation and 
Renewable Energy Reserve is less than 30,000 allowances per year; or the 
sum of the deductions for the special allowance reserve is less than 
250,000, then the Administrator will withdraw one allowance from each 
unit, beginning with the unit receiving the largest number of 
allowances, in descending order, until the allocated allowances balance 
with the number of allowances available.

[[Page 149]]

    (2) If the sum of adjusted basic allowances is less than 8,900,000; 
the sum of the deductions for the repowering annual set aside exceeds 
the annual set aside; the sum of the deductions for the Energy 
Conservation and Renewable Energy Reserve exceeds 30,000 allowances per 
year; or the sum of the deductions for the special allowance reserve 
exceeds 250,000, then the Administrator will distribute one allowance 
for each unit, beginning with the unit receiving the largest number of 
allowances, in descending order, until the allocated allowances balance 
with the number of allowances required.

[58 FR 15707, Mar. 23, 1993]



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. 73.16, 73.18, 73.19, and 73.20, using the appeals procedures of 
part 78 of this chapter.

[58 FR 15708, Mar. 23, 1993]
Secs. 73.14--73.15  [Reserved]



Sec. 73.16  Phase I early reduction  credits.

    (a) Unit eligibility. Units listed in Table 1 of Sec. 73.10 are 
eligible to receive allowance allocations under this section if:
    (1) The unit is authorized by the Governor of the State in which the 
unit is located to make reductions in emissions of sulfur dioxide prior 
to calendar year 1995; and
    (2) The unit is part of a utility system (which, for the purposes of 
this section only, includes all electrical generators operated by a 
utility, including those that are not fossil fuel-fired) that has 
decreased its total coal-fired generation, as a percentage of total 
system generation, by more than twenty percent between January 1, 1980, 
and December 31, 1985; and
    (3) 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] TC06JA94.008

    (b) Emissions reductions eligibility. Sulfur dioxide emissions 
reductions eligible for allowance allocations shall:
    (1) Be made no earlier than calendar year 1991 and no later than 
calendar year 1994; and
    (2) Be due to physical changes to the plant or be 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 for a unit listed in Table 1 of Sec. 73.10 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 the requirements of 
Sec. 73.13 of this part 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 emissions of sulfur 
dioxide prior to calendar year 1995;
    (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.)

[[Page 150]]

    (d) Request for allowances. (1) The designated representative for 
the requesting unit shall submit the request for allowances according to 
the procedures in 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. For 
units that have not installed and received certification of their 
SO2 continuous emission monitoring system prior to the calendar 
year(s) for which credits for reductions are requested, the designated 
representative shall submit photocopies of the units' Form EIA-767 for 
the calendar year of the requested reductions in emissions; and
    (ii) A letter signed by the designated representative: (A) 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
    (B) Certifying that all photocopies are exact duplicates.
    (2) The designated representative shall submit any request for 
allowances for years prior to 1993 no later than May 1, 1993. The 
designated representative shall submit any request for allowances for 
1993 no later than May 1, 1994. For 1994 and after, the designated 
representative shall submit any 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 eligible 
unit's 1995 future year subaccount. The following provisions shall apply 
to the allocation:
    (1) ``Prior year'' means a single calendar year selected by the 
eligible unit from 1991 to 1994 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 utility system but are not eligible for early reduction credits.
    (4) Calendar year 1990 data will be used as the basis against which 
early reduction credits are determined.
    (5) Early reduction credits will be calculated at the unit level, 
subject to the restrictions in paragraph (e)(6) of this section.
    (6) The number of credits for eligible Phase I 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] TC01SE92.065


[[Page 151]]

[GRAPHIC] [TIFF OMITTED] TC01SE92.066


    (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 (e)(6)(iii) of this section 
applies.
[GRAPHIC] [TIFF OMITTED] TC01SE92.067

    (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] TC01SE92.068


[[Page 152]]


    (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] TC01SE92.069

    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] TC01SE92.070

    (B) Calculation of the unit's early reduction credits where the 
unit's prior year 
utilization is restricted.
[GRAPHIC] [TIFF OMITTED] TC01SE92.071

    (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 (v)(B) of this section and the 
following limitation:

[[Page 153]]

[GRAPHIC] [TIFF OMITTED] TC01SE92.072


[58 FR 15708, Mar. 23, 1993]
Sec. 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 1997 actual SO2 emission rate is less than 1.2 lb/
mmBtu;
    (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) Submittal procedures. Not later than March 1, 1998, in order to 
be eligible for allowance allocations under this section, the designated 
representative for the unit must submit a photocopy of the unit's 1997 
Form EIA-767 and a letter certifying that the photocopy is a true copy.

[58 FR 15710, Mar. 23, 1993]



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-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:

[[Page 154]]

[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) Calendar year 1990 data will be used as the basis against which 
early reduction credits are determined.
    (5) Early reduction credits will be calculated at the unit level, 
subject to the restrictions in paragraph (e)(6) of this section.
    (6) The number of credits for eligible Phase II units will be 
calculated as follows:
    (i) Comparison of the prior year utilization of ERC units to the 
1990 utilization, as a percentage of system utilization. If, as 
calculated below, system-wide prior year utilization of ERC units 
exceeds systems-wide 1990 utilization of ERC units on a percentage 
basis, then paragraphs (e)(6)(ii) and (iii) of this section apply. If 
not, the ERC units are eligible to receive early reduction credits as 
calculated in paragraph (e)(6)(v)(A) of this section.

[[Page 155]]

[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

    (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.

[[Page 156]]

[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. 
[GRAPHIC] [TIFF OMITTED] TC01SE92.079


[[Page 157]]


    (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

[58 FR 15711, Mar. 23, 1993]



Sec. 73.21  Phase II repowering allowances.

    (a) Repowering allowances. In addition to allowances allocated under 
Sec. 73.11, 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 = Unit's Year 2000 Adjusted Basic 
Allowances as calculated at Sec. 73.11(a)(3)

    (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. 73.11(a) and (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:
[GRAPHIC] [TIFF OMITTED] TC01SE92.082


[[Page 158]]


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 = Unit's Year 2000 Adjusted Basic 
Allowances as calculated at Sec. 73.11(a)(3)

    (2) The Administrator will reallocate the allowances forfeited in 
paragraph (b)(1) of this section to all Table 2 and 3 units' years 2000 
through 2009 subaccounts in the following manner:
[GRAPHIC] [TIFF OMITTED] TC01SE92.083

[53 FR 15713, Mar. 23, 1993]
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 200,000 allowances annually for 
calendar years 2000 and each year thereafter to the Auction Subaccount 
of the Special Allowance Reserve.
    (3) The Administrator will allocate 50,000 allowances annually for 
calendar years 2000 and each year thereafter to the Direct Sale 
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 and 
sales 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 or 3 according to the following equations:

[[Page 159]]

[GRAPHIC] [TIFF OMITTED] TC01SE92.084


    (3) On or after June 1, 1998, 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 2000 through 2009 will 
be distributed to the designated representative of each unit listed in 
Table 2 or 3 according to the following equation:
[GRAPHIC] [TIFF OMITTED] TC01SE92.085

    (4) Until June 1, 1998, 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 2010 and thereafter will be 
distributed to the designated representative of each unit listed in 
Table 2 or 3 according to the following equations:
[GRAPHIC] [TIFF OMITTED] TC01SE92.086

    (5) On or after June 1, 1998, 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 2010 and thereafter 
will be distributed to the designated representative of each unit listed 
in Table 2 or 3 according to the following equation:

[[Page 160]]

[GRAPHIC] [TIFF OMITTED] TC01SE92.087


    (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 and sale (under subpart E of 
this part) will be reallocated to the unit's Allowance Tracking System 
Account according to the following equations:
[GRAPHIC] [TIFF OMITTED] TC01SE92.088

    (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 and sale (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] TC01SE92.089

    (4) Until June 1, 1998, 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 and sale (under subpart E of 
this part) will be reallocated to the unit's Allowance Tracking System 
Account according to the following equations:

[[Page 161]]

[GRAPHIC] [TIFF OMITTED] TC01SE92.090


    (5) On or after June 1, 1998, 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 and sale (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] TC01SE92.091

    (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]



                  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 72 of this chapter, transfers of allowances made 
pursuant to subparts C and 

[[Page 162]]

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 Administrator has established the new account.

[[Page 163]]

    (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 action of the authorized account representative, with 
all the rights, duties, and responsibilities pertaining thereto.

[[Page 164]]

    (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 or direct sale pursuant to subpart E of this part;
    (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]



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 recorded in the compliance subaccount, or its 
transfer to the unit's compliance subaccount is submitted correctly 
pursuant to subpart D for recordation in the compliance subaccount for 
the unit by not later than the allowance transfer deadline of January 30 
of the calendar year following the year for which compliance is being 
established in accordance with the requirements of subpart D of this 
part.

[[Page 165]]

    (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.
    (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 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]



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;

[[Page 166]]

    (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.
    (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.

[[Page 167]]



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) 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).



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

[[Page 168]]

a format to be specified by the Administrator, the authorized account 
representatives of the accounts subject to the allowance transfer 
request submitted for recordation of:
    (1) A decision not to record the transfer, and
    (2) The reasons for such non-recordation.
    (c) Nothing in this section shall preclude the submission of an 
allowance transfer request for recordation following notification of 
non-recordation.



   Subpart E--Auctions, Direct Sales, and Independent Power Producers 
                            Written Guarantee

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



Sec. 73.70  Auctions.

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

                Table I.--Allowance Schedule for Auctions               
------------------------------------------------------------------------
                                             Spot     Advance    Advance
             Year of purchase               auction   auction   auction*
------------------------------------------------------------------------
1993.....................................  50,000 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, and, if required pursuant to Sec. 73.72(q), an additional 
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, 
and, if required to Sec. 73.72(q), one additional 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 in whole dollars; 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

[[Page 169]]

remaining after the Auction Subaccount is exhausted. Sales of offered 
allowances, including, but not limited to, allowances offered by more 
than one offeror at the same minimum bid price, will continue in 
ascending order of minimum price, starting with the lowest, and 
descending order of remaining bids, starting with the highest, until:
    (i) All allowances are sold,
    (ii) No bids remain, or
    (iii) Prices of remaining bids do not meet minimum prices required 
in remaining offers.
    (2) In the event that there is more than one bid submitting the same 
price and the total number of allowances requested in all such bids 
exceeds the number of allowances remaining, the Administrator will award 
the remaining allowances by lottery to such bidders.
    (3) In the event that there are more offers of sale at the minimum 
price than there are bids meeting that price, allowances from all such 
offers will be sold to cover the bids, according to each such offeror's 
pro rata share of all allowances so offered.
    (4) In the event that fewer allowances remain than are requested in 
a bid, the Administrator will sell such remaining allowances to the 
bidder provided that, pursuant to Sec. 73.71(b)(4), the bid states the 
bidder's willingness to purchase fewer allowances than requested in the 
bid.
    (5) In the event that fewer than all allowances included in an offer 
for sale would be sold to remaining bids based on price, the 
Administrator will sell such allowances to the bidder(s), provided that, 
pursuant to Sec. 73.70(c)(4), the offer states the offeror's willingness 
to sell fewer allowances than were offered for sale.
    (e) Announcement of results. Following each auction, the 
Administrator will publish the names of winning bidders and their bids, 
the amounts of losing bids, and the lowest price at which allowances are 
sold. 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

[[Page 170]]

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]

    Effective Date Note: At 61 FR 28763, June 6, 1996, Sec. 73.70 was 
amended by revising table I in paragraph (a), effective August 5, 1996. 
For the convenience of the user, the superseded text is set forth as 
follows:
Sec. 73.70  Auctions.
    (a) * * *

                Table 1--Allowance Schedule for Auctions                
------------------------------------------------------------------------
                                                    Spot       Advance  
               Year of purchase                   auction      auction  
------------------------------------------------------------------------
1993..........................................     b 50,000    a 100,000
1994..........................................     b 50,000    a 100,000
1995..........................................       50,000    a 100,000
1996..........................................      150,000    a 100,000
1997..........................................      150,000    a 100,000
1998..........................................      150,000    a 100,000
1999..........................................      150,000    a 100,000
2000 and after................................      100,000    a 100,000
------------------------------------------------------------------------
a Not useable until 7 years after purchase.                             
b Not useable until 1995.                                               

                                * * * * *



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

[[Page 171]]

included in the annual allowance auctions in accordance with 
Sec. 73.70(a).

[61 FR 28763, June 6, 1996]

    Effective Date Note: At 61 FR 28763, June 6, 1996, Sec. 73.72 was 
revised, effective Aug. 5, 1996. For the convenience of the user, the 
superseded text is set forth as follows:
Sec. 73.72  Direct sales.
    (a) Allowances to be sold. The Administrator will sell allowances 
every year according to the following schedule:

             Table 1--Allowance Schedule for the Direct Sale            
------------------------------------------------------------------------
                                                               Advance  
               Year of purchase                  Spot sale       sale   
------------------------------------------------------------------------
1993..........................................                  a 25,000
1994..........................................                  a 25,000
1995..........................................                  a 25,000
1996..........................................                  a 25,000
1997..........................................                  a 25,000
1998..........................................                  a 25,000
1999..........................................                  a 25,000
2000 and after................................       25,000     a 25,000
------------------------------------------------------------------------
a Not useable until 7 years after purchase.                             

    (b) Adjustment of the direct sale schedule. The schedule listed in 
paragraph (a) of this section will be adjusted to reflect allowances 
subject to IPP written guarantees pursuant to Sec. 73.74.
    (c) Price. Allowances in the direct sale will be sold at $1,500 per 
allowance, adjusted by the Consumer Price Index (CPI). The following 
formula will be used each year to calculate the price:


                                                                                                                
                            CPI (year) - CPI (1990)                                                             
$1,500  x  <3-ln (>  1 + ----------------------------- <3-ln )>                                                 
                                   CPI (1990)                                                                   
                                                                                                                

    (d) Form and timing of the direct sale. The Administrator will begin 
accepting applications for the direct sale on June 1st of each calendar 
year and will continue to accept applications up to 10 calendar days 
prior to the allowance transfer deadline.
    (e) Who may purchase from the direct sale. Any person may apply to 
purchase allowances from the direct sale.
    (f) Amount allowed to purchase. Applicants may request to purchase 
any number of allowances up to the amount available for sale in the 
Direct Sale Subaccount.
    (g) Request to purchase allowances. Applicants shall submit the 
Direct Sale Application Form to request to purchase allowances from the 
Administrator, or shall make such request by some method of electronic 
transfer if the Administrator, following public notice, so requires or 
permits at some future time. The Direct Sale Application Form shall 
state:
    (1) The number of allowances sought;
    (2) Whether spot or advance allowances are sought;
    (3) The Allowance Tracking System account number; and
    (4) Whether the applicant is willing to purchase fewer allowances 
than the number of allowances stated in (g)(1) of this section, if the 
full amount is not available. Where the applicant holds no Allowance 
Tracking System account, a New Account/New Authorized Account 
Representative Form must accompany the application. 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.
    (h) Submission of direct sale applications. The Administrator will 
publish in the Federal Register and in the Commerce Business Daily the 
address of where to submit Direct Sale Application Forms no later than 
60 calendar days before each direct sale.
    (i) First come, first served. Applications will be approved in order 
of receipt, indicated by the date and time stamped on the applications 
upon arrival at the destination indicated pursuant to paragraph (h) of 
this section.
    (j) Partial fulfillment of requests. In the event the number of 
allowances requested for a purchase exceeds the number of allowances 
remaining in the Direct Sale Subaccount, the Administrator will approve 
the request for the number of allowances remaining, provided that, 
pursuant to paragraph (g)(4) of this section, the application states the 
applicant's willingness to purchase fewer allowances than the number 
stated in its application. In all other cases, the Administrator will 
place applicants on the waiting list pursuant to paragraph (n) of this 
section.
    (k) Notification of approval. After approving an application, the 
Administrator will notify the applicant of the amount and type of 
allowances that may be purchased, the date on which the approval was 
made, the exact price of allowances for purchase from the direct sale, 
and instructions for making payment.
    (l) Payment. Applicants shall submit 50% of the total purchase price 
by six months after the date of approval of their request to purchase. 
Pursuant to paragraph (m) of this section, the remaining 50% must be 
paid on or before the allowance transfer deadline. In the event that 
approval is granted less than six months prior to the allowance transfer 
deadline, payment shall be made on or before the allowance transfer 
deadline, pursuant to paragraph (m) of this section. The Administrator 
will terminate the approval of any request to purchase upon failure to 
pay the

[[Page 172]]

50% deposit within six months. Upon failure to submit timely payment for 
the remaining balance, the Administrator will terminate the sale and the 
deposit will be forfeited. The 50% deposit and the final payment shall 
be made by certified check or by some method of electronic transfer or 
other instrument 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.
    (m) Oversubscription payment deadline. The Administrator will assess 
the status of the allowance reservations to the Direct Sale Subaccount 
on December 1 of each year the direct sale is held. In the event that 
the direct sale is oversubscribed by December 1, the Administrator will 
require full payment for reserved allowances no later than the 
oversubscription payment deadline for those applicants whose 
applications were previously approved and for whom allowances were 
reserved. Allowances will be transferred immediately upon such payment.
    (n) Oversubscription to the direct sales program. Applications 
received after all allowances in the Direct Sale Subaccount are subject 
to approved applications shall be included on a waiting list and ranked 
in order of receipt, as indicated by the time and date stamped on the 
application upon arrival at the destination indicated pursuant to 
paragraph (h) of this section. In the event that an approved application 
is terminated pursuant to paragraph (l) of this section, applications on 
the waiting list will be approved according to the order in which they 
are ranked, subject to paragraph (i) of this section. Approved 
applicants will be notified pursuant to paragraph (k) of this section. 
If applicants without reserved allowances wish to contact those wait-
listed applicants for whom allowances have been reserved, in case such 
applicants choose not to purchase their reserved allowances, the 
Administrator will make such information available upon request. Full 
payment for allowances must be collected by the Administrator on or 
before the allowance transfer deadline.
    (o) Transfer of allowances. Allowances will be transferred to 
purchasers' Allowance Tracking System accounts from the Direct Sale 
Subaccount as soon as full payment is collected.
    (p) Transfer of proceeds. Not later than 90 days after the 
conclusion of the direct sale, the Administrator will pay a pro rata 
share of the total proceeds of the direct sale (including forfeited 
deposits) to the authorized account representatives of each unit from 
whose annual allocation allowances are withheld for the purposes of 
establishing the Direct Sale Subaccount. The Administrator will pay no 
interest on such payment. Each unit's pro rata share will be calculated 
pursuant to regulations to be promulgated under subpart B of this part.
    (q) Unsold allowances in the Direct Sale Subaccount. If allowances 
remain in the Direct Sale Subaccount after the allowance transfer 
deadline, the Administrator will transfer those allowances to the 
Auction Subaccount. All allowances remaining from the spot sale will be 
sold in the spot auction in the following year. Advance allowances 
transferred from the direct sale will be sold in an additional advance 
auction the following year, in which allowances usable for compliance in 
six years will be sold. This additional auction will be conducted before 
allowances offered by authorized account representatives are auctioned.

[56 FR 65601, Dec. 17, 1991, as amended at 58 FR 3695, Jan. 11, 1993; 58 
FR 15650, Mar. 23, 1993]



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.



Sec. 73.74  Independent power producers written guarantee.

    (a) Nature of guarantee. The written guarantee is a right to 
purchase allowances from the Direct Sale Subaccount for $1,500 (CPI 
adjusted) prior to the time in each calendar year that such allowances 
are offered for sale to others.
    (b) Issuance of a guarantee. IPP written guarantees will be issued 
for a unit

[[Page 173]]

and not to the unit's owners and may only be transferred with the unit 
itself. Each guarantee application pertains to one specific unit.
    (c) Yearly total number guaranteed. The number of allowances which 
may be subject to such written guarantees each year will be equal to the 
total number of allowances in the Direct Sales Subaccount for that year 
(50,000).
    (d) Duration of the guarantee. Applicants may request a guarantee 
for the useful life of the unit, up to 30 years, beginning in the year 
2000.
    (e) Termination of the guarantee. The Administrator will terminate a 
written guarantee if the unit for which a guarantee is issued has not 
commenced commercial operation by January 1, 2000 or within two years of 
the planned start-up date of the unit, whichever is later, or if the 
holder of the guarantee fails to make a continuing good faith effort to 
obtain allowances, including participation in the annual auctions, as 
required under section 416(c)(4) of the Act. The Administrator will also 
terminate a guarantee if the holder of the guarantee fails to notify the 
Administrator of the continued need for the guarantee pursuant to 
Sec. 73.76(e).

    Effective Date Note: At 61 FR 28763, June 6, 1996, Sec. 73.74 was 
removed, effective Aug. 5, 1996.



Sec. 73.75  Application for an IPP written guarantee.

    (a) Application requirements. Applicants shall demonstrate the 
following by filling out the Application for an IPP Written Guarantee 
for SO2 Allowances:
    (1) Certification of Qualifications. Each applicant shall certify 
that it is the owner or operator of a new independent power production 
facility and that it meets the criteria set forth in the definition of 
new independent power production facility, and, where applicable, submit 
a certified statement from a senior manager (who shall meet the 
requirements of ``certifying official'' set forth in Sec. 73.3) of its 
affiliate that it cannot supply all or any of the required allowances.
    (2) Proof of ``propose to construct'' a new unit. Each applicant 
shall demonstrate any one of the following:
    (i) That it has been selected as a winning bidder in a utility 
competitive bid solicitation;
    (ii) That it has entered into a legally binding power sales 
agreement or such agreement has been entered into on its behalf;
    (iii) That it has entered into a legally binding fuel supply 
agreement or such agreement has been entered into on its behalf;
    (iv) That it has received a site lease or proof of land acquisition;
    (v) That it has entered into a legally binding steam sales agreement 
or such agreement has been entered into on its behalf; or
    (vi) That it has submitted a complete environmental permit 
application or has received such a permit.
Each applicant shall submit the relevant document in support of the 
demonstration. If the document is longer than 10 pages, only the 
signature page(s) and the first 10 pages of the document shall be 
submitted.
    (3) Pledge to apply for financing. The applicant shall certify that 
it will apply for, or has applied for, financing for the unit after 
January 1, 1990 and before the date of the 1993 auction.
    (4) Submission of written offers at $750. The applicant shall 
certify that it has made offers to purchase some or all of the required 
allowances at $750 each from all phase I utilities, but that it received 
no unconditional acceptances within 180 days from the date on which each 
offer was made.
    (5) Other information required. The applicant shall submit the 
following information for the unit:
    (i) The proposed location (complete address);
    (ii) The proposed production capacity and fuel source;
    (iii) Sulfur dioxide emissions limitations under which the unit will 
be required to operate;
    (iv) Projected annual emissions of sulfur dioxide;
    (v) Annual allowances requested;
    (vi) The proposed date on which the unit will commence commercial 
operation; and
    (vii) The unit's expected operating lifetime.

[[Page 174]]

    (b) Application submitted after the 1993 auction. An application may 
be submitted after the date of the 1993 auctions provided that it meets 
all the requirements of paragraph (a) of this section and includes 
Supplement A of the Application For An IPP Written Guarantee For 
SO2 Allowances which requests the name of the financial entity(ies) 
to whom application for financing was made.
    (c) Submittal location. Completed applications shall be submitted 
to: U.S. Environmental Protection Agency, Acid Rain Division (ANR-445), 
401 M Street, SW., Washington, DC 20460, attn.: IPP Written Guarantee.
    (d) Certification. Certification of all requirements shall be made 
by a certifying official upon his/her verification of all information 
and documentation submitted. Changes by an applicant in the name of the 
certifying official must be made in writing to the Administrator.
    (e) Recordkeeping requirements. Applicants shall maintain and make 
available to the Administrator, at the Administrator's request, copies 
of the $750 written offers to Phase I utilities, any responses to such 
offers, and copies of documents showing the project milestones set forth 
in paragraph (a)(2) of this section that have been attained. Holders of 
written guarantees shall retain copies of their bids in the annual 
auctions and any written offers made to other allowance holders and 
shall make such documents available to the Administrator at the 
Administrator's request.

    Effective Date Note: At 61 FR 28763, June 6, 1996, Sec. 73.75 was 
removed, effective Aug. 5, 1996.



Sec. 73.76  Approval and exercise of the IPP written guarantee.

    (a) First come, first served. The Administrator will process and 
approve or disapprove, in whole or in part, applications received on or 
after the effective date of the regulations. The Administrator will 
issue guarantees pursuant to approved applications according to the 
order in which applications are received, as indicated by the date and 
time stamped on the applications upon arrival at the destination 
indicated in Sec. 73.75(c).
    (b) Oversubscription to the IPP written guarantee program. 
Applications received after all allowances in the Direct Sale Subaccount 
have become subject to written guarantees or when there is an 
insufficient number of allowances available to satisfy the amount 
requested for any year covered by the guarantee will be included on a 
waiting list and ranked in order of time and date of receipt. In the 
event that an IPP guarantee is terminated pursuant to Sec. 73.74(e), the 
Administrator will process applications on the waiting list by rank 
order and will issue guarantees pursuant to any approved application.
    (c) Deficient applications. The Administrator may, in his or her 
discretion, return applications that fail to meet the requirements set 
forth in Secs. 73.75 (a) and (b) if applicable. Revised applications 
will be processed according to the date and time of receipt of such 
revised applications.
    (d) Notification of approval. The Administrator will issue a written 
guarantee pursuant to each approved application within 30 calendar days 
of receipt, provided that there is a sufficient number of allowances 
available to satisfy the guarantee for each year covered by the 
guarantee at the time the application is processed.
    (e) Certification of continued need for the guarantee. (1) By no 
later than June 30 and December 31 of 1992 and no later than December 31 
of each year thereafter, the certifying official for a unit for which a 
guarantee has been issued shall certify, through written notification, 
to the Administrator that the unit continues to require allowances 
subject to the guarantee pursuant to Sec. 73.75.
    (2) As soon as a unit for which a guarantee has been issued is no 
longer in need of any or all of the allowances subject to the guarantee, 
the certifying official shall notify the Administrator, in writing, of 
the number of allowances that are no longer needed. Pursuant to the 
terms of the notification, the Administrator will reduce the number of 
allowances subject to the guarantee or terminate the guarantee.
    (f) Exercise of guarantee. Allowances may be purchased in each year 
for those years for which the guarantee

[[Page 175]]

has been issued provided that they are purchased for the unit for which 
the guarantee has been issued. In any year, the certifying official of a 
unit for which a guarantee is issued may purchase any number of 
allowances up to the maximum number specified in the guarantee for such 
year. Allowances purchased through guarantees will be fully 
transferable.
    (1) Notification and response. To exercise a written guarantee, the 
certifying official shall notify the Administrator of the number of 
allowances to be purchased. Such notification shall be in writing and 
signed by the certifying official pursuant to Sec. 73.75(d). The 
Administrator, following public notice, may require or permit a method 
or methods of electronic transfer of this information. The Administrator 
will respond to the written notification within 5 business days after 
receipt by sending the certifying official a statement of the exact 
price for the allowances and where to send payment. If the certifying 
official does not have an account in the Allowance Tracking System, the 
New Account/New Authorized Account Representative Form shall be 
completed and mailed with payment.
    (2) Payment. Certifying officials shall purchase allowances by 
certified check for the total amount or by some method of electronic 
transfer or other instrument, if the Administrator, following public 
notice, so requires or permits at some future time. The certified check 
shall be made payable to U.S. EPA.
    (3) Time period to exercise. Notification to exercise a guarantee 
shall be received by the Administrator no later than April 15th of the 
calendar year in which allowances are to be purchased. Payment for 
allowances shall be collected by the Administrator no later than May 
15th of that same year. If the direct sales program has been terminated 
pursuant to Sec. 73.73(b), notification and payment may occur at any 
time prior to the allowance transfer deadline for each year in which 
allowances are to be purchased.
    (g) Transfer of allowances. Allowances will be transferred into the 
unit's allowance system account as soon as full payment is collected.
    (h) Transfer of proceeds. The Administrator will pay all proceeds 
from the exercise of written guarantees pursuant to Sec. 73.72(p).

    Effective Date Note: At 61 FR 28763, June 6, 1996, Sec. 73.76 was 
removed, effective Aug. 5, 1996.



Sec. 73.77  Relationship of the independent power producers written guarantee to the direct sale subaccount.

    (a) Reserving allowances in the Direct Sale Subaccount. The 
Administrator will make available up to 50,000 yearly allowances in the 
direct sales subaccount for written guarantees. The Administrator will 
first reserve for IPP guarantees the 25,000 yearly allowances in the 
advance sale category. If more than 25,000 yearly allowances are subject 
to guarantees, the excess allowances needed will be reserved from the 
spot allowance category, up to 25,000 each year.
    (b) Adjustment of the direct sale schedule. If fewer than 25,000 
advance allowances are subject to written guarantees for any year from 
2000 through 2006, any remaining advance allowances will be sold in the 
advance sale seven years preceding that year. If all 25,000 advance 
allowances are reserved for written guarantees for 2000 through 2006, 
the direct sale will begin in the year 2000 and will consist only of 
spot sales of allowances not sold pursuant to written guarantees.
    (c) Continuation of the guarantee. Termination of the direct sale 
will not affect IPP written guarantees which will continue in effect for 
the operating life of the unit or 30 years, whichever is shorter, unless 
terminated pursuant to Sec. 73.74(e).
    (d) Guaranteed allowances not sold. If a certifying official of a 
unit for which a guarantee is issued chooses not to exercise the 
guarantee for a year in which allowances are reserved, the allowances 
will be offered for sale in the direct sale beginning on June 1 of that 
year. In the event the direct sale is terminated, any unsold allowances 
will be transferred to the Auction Subaccount pursuant to Sec. 73.72(q).

    Effective Date Note: At 61 FR 28763, June 6, 1996, Sec. 73.77 was 
removed, effective Aug. 5, 1996.

[[Page 176]]



       Subpart F--Energy Conservation and Renewable Energy Reserve

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



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

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


                                                                        
   Remaining allowances in the Reserve  x  Unit's allowances withheld   
-------------------------------------------------------------------------
                         Total amount in Reserve                        
                                                                        
                                                                        

(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.

[[Page 177]]

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

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



Sec. 73.82  Application for allowances from reserve program.

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

[[Page 178]]

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

[[Page 179]]

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


                                                                        
    (A) x (B)                                                           
-----------------                                                       
  2000 lbs./ton                                                         
                                                                        


[[Page 180]]

(Rounded to the nearest ton)

Where:

    (A)=the kilowatt hours that were not, but would otherwise have been, 
supplied by the utility during such year in the absence of such 
qualified energy conservation measures.
    (B)=0.004 1bs. of sulfur dioxide per kilowatt hour.

    (2) In the case of an application submitted on the basis of 
qualified renewable energy generation, the sulfur dioxide emissions 
tonnage deemed avoided for any calendar year shall be equal to the 
product of:


                                                                        
    (A) x (B)                                                           
-----------------                                                       
  2000 lbs./ton                                                         
                                                                        

(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

[[Page 181]]

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



Sec. 73.84  Administrator's action on applications.

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

[[Page 182]]

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



Sec. 73.85  Administrator review of the reserve program.

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

[[Page 183]]

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.

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

[[Page 184]]

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

[[Page 185]]

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

[[Page 186]]

     Milk cooler heat exchangers
     Direct expansion/ice bank milk cooling
     Low energy precision application systems
     Heat pump crop drying
1.5  Government Services Sector
1.5.1  Streetlighting
     Replace incandescent and mercury vapor lamps with high 
pressure sodium and metal halide
1.5.2  Other
     Energy efficiency improvements in motors, pumps, and 
controls for water supply and waste water treatment
     District heating and cooling measures derived for 
cogeneration that result in electricity savings

       2. Supply-side Measures Applicable for Reduced Utilization

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

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

    The following listed measures are approved as ``qualified renewable 
energy generation'' for purposes of the Conservation and Renewable 
Energy Reserve Program. Measures not appearing on the list may also be 
qualified renewable energy generation measures if they meet the 
requirements specified in Sec. 73.81.
3.1  Biomass resources
     Combustible energy-producing materials from biological 
sources which include: wood, plant residues, biological wastes, landfill 
gas, energy crops, and eligible components of municipal solid waste.
3.2  Solar resources
     Solar thermal systems and the non-fossil fuel portion of 
solar thermal hybrid systems
     Grid and non-grid connected photovoltaic systems, including 
systems added for voltage or capacity augmentation of a distribution 
grid.
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 year 1990 
for the refinery;
    (2) Photocopies of Form EIA-810 for each month of calendar year 1990 
for each refinery that is owned or controlled by the refiner which 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 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

[[Page 187]]

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

[[Page 188]]

[GRAPHIC] [TIFF OMITTED] TC01SE92.093


[58 FR 15716, Mar. 23, 1993; 58 FR 33770, June 21, 1993]



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 Calculation 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 Calculation 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.

[[Page 189]]



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 a written exemption under Sec. 72.7 or Sec. 72.8 
of this chapter is in effect and combustion or process sources that are 
not operating are not eligible to submit an opt-in permit application to 
become opt-in sources.



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 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 part 70 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.
    (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.



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.



                    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. 74.62;
    (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

[[Page 190]]

    (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).



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 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 part 70 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

[[Page 191]]

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 such lesser time approved 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

[[Page 192]]

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.



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



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

[[Page 193]]

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(c).
    (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. The withdrawal shall 
not be a defense against any violation of such requirements of the Acid 
Rain Program whether the violation occurs before or 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 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.



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

[[Page 194]]

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 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


[[Page 195]]


where,

[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:
[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

[[Page 196]]

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,
    [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)(A);
    ``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).

[[Page 197]]

    (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



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.............................................                                                      
(3) 2 x 8760/(annual fuel consumption for specified year 1                                                      
 x 10 3)                                                                                                        
lbs SO2/hour..............................................                                                      
(3) 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                                       
 combination..............................          1.00           1.00 
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                                       
 Averaging Time Not Specified.............          0.93           0.89 
------------------------------------------------------------------------

    (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.

[[Page 198]]

    (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.



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


[[Page 199]]


    (2) For combustion sources in 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:
[GRAPHIC] [TIFF OMITTED] TR04AP95.009



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,

[[Page 200]]

[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 =
    [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

[[Page 201]]

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.

    (a) 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.



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;
    (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;

[[Page 202]]

    (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 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

[[Page 203]]

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

where ``actual heat input'' and ``reduction from improved efficiency'' 
are defined as set forth in paragraph (a)(1)(i) of this section but are 
restricted to data or estimates for the ``remaining calendar quarters'', 
which are the calendar quarters that begin on or after the date the opt-
in permit becomes effective.
    (2) Average utilization. Average utilization for the calendar year 
shall be defined as the average of the annual utilization calculated as 
follows:
    (i) For the first two calendar years after the effective date of an 
opt-in permit taking effect on January 1 or for the first two calendar 
years after the effective date of a thermal energy plan governing an 
opt-in source in accordance with Sec. 74.47 of this chapter, 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


[[Page 204]]


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
[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), 
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 =

[[Page 205]]

[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;
    (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.

[[Page 206]]

    (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.
    (2) Each designated representative shall include in the opt-in 
source's confirmation report only its share of the verified reduction in 
heat input as defined under paragraph (c)(2)(i)(A) of this section for 
the calendar year under the certification under paragraph 
(c)(2)(ii)(B)(1) of this section.
    (iii) Determination of reduced utilization based on confirmation 
report. (A) If an opt-in source must submit a confirmation report as 
specified under paragraph (c)(2) of this section, the Administrator, 
upon such submittal, will adjust his or her determination of reduced 
utilization for the calendar year for the opt-in source. Such adjustment 
will include the recalculation of both annual utilization and average 
utilization, using verified reduction in heat input as defined under 
paragraph (c)(2)(i)(A) of this section for the calendar year instead of 
the previously estimated values.
    (B) Estimates confirmed. If the total, included in the confirmation 
report, of the amounts of verified reduction in the opt-in source's heat 
input equals the total estimated in the opt-in source's annual 
compliance certification report for the calendar year, then the 
designated representative shall include in the confirmation report a 
statement indicating that is true.
    (C) Underestimate. If the total, included in the confirmation 
report, of the amounts of verified reduction in the opt-in source's heat 
input is greater than the total estimated in the opt-in source's annual 
compliance certification report for the calendar year, then the 
designated representative shall include in the confirmation report the 
number of allowances to be credited to the 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

[[Page 207]]

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 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 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.

[[Page 208]]

    (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] TR04AP95.021

where,

    ``Allowances allocated'' shall be the original number of allowances 
allocated under section Sec. 74.40 for the calendar year.
    ``Tons emitted'' shall be the total tons of sulfur dioxide emitted 
by the opt-in source during the calendar year, as reported in accordance 
with subpart F of this part for combustion sources.
    ``Allowances transferred to all replacement units'' shall be the sum 
of allowances transferred to all replacement units under an approved 
thermal energy plan in accordance with Sec. 74.47 and adjusted by the 
Administrator in accordance with Sec. 74.47(d)(2).
    ``Allowances deducted for reduced utilization'' shall be the total 
number of allowances deducted for reduced utilization as calculated in 
accordance with this section including any adjustments required under 
paragraph (c)(iii)(E) of this section.



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

[[Page 209]]

    (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 begin from January 1 of the first full calendar year 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 that the thermal energy plan takes effect, 
which shall be the first year 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 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;
    (ix) The estimated total thermal energy at each replacement unit for 
the 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;
    (x) The estimated 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;
    (xi) The estimated amount of thermal energy at each replacement 
unit,

[[Page 210]]

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;
    (xii) Estimated total annual fuel input at each replacement unit 
after replacing thermal energy at the opt-in source;
    (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 July 1 of the calendar year prior 
to the first calendar year 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

[[Page 211]]

plan in accordance with Sec. 72.40(d) of this chapter shall be submitted 
no later than December 1 of the calendar year for which the termination 
is to take effect.
    (iii) If the requirements of paragraph (a)(8)(ii) of this section 
are met and upon revision of the opt-in permit of the opt-in source and 
the Acid Rain permit of each replacement unit governed by the thermal 
energy plan to terminate the plan pursuant to Sec. 72.83 of this 
chapter, the Administrator will adjust the allowances for the opt-in 
source and the replacement units to reflect the transfer back to the 
opt-in source of the allowances transferred from the opt-in source under 
the plan for the year for which the termination of the plan takes 
effect.
    (9) Renewal of thermal energy plan. The designated representative of 
an opt-in source may renew the thermal energy plan as part of its opt-in 
permit renewal in accordance with Sec. 74.19.
    (b) Calculation of transferable allowances--(1) Qualifying thermal 
energy. The amount of thermal energy credited towards the transfer of 
allowances based on the replacement of thermal energy shall equal the 
qualifying thermal energy and shall be calculated for each replacement 
unit as follows:
[GRAPHIC] [TIFF OMITTED] TR04AP95.022

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

where,

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

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

    (3) Allowances transferable from the opt-in source to each 
replacement unit. The number of allowances transferable from the opt-in 
source to each replacement unit for the replacement of thermal energy is 
calculated as follows:
[GRAPHIC] [TIFF OMITTED] TR04AP95.024

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.

[[Page 212]]

    (d) Compliance--(1) Annual compliance certification report. (i) As 
required for all opt-in sources, the designated representative of the 
opt-in source covered by a thermal energy plan must submit an opt-in 
utilization report for the calendar year as part of its annual 
compliance certification report under Sec. 74.44(c)(1).
    (ii) The designated representative of an opt-in source must submit a 
thermal energy compliance report for the calendar year as part of the 
annual compliance certification report, which must include the following 
elements in a format prescribed by the Administrator:
    (A) The name, authorized account representative identification 
number, and telephone number of the designated representative of the 
opt-in source;
    (B) The name, authorized account representative identification 
number, and telephone number of the designated representative of each 
replacement unit;
    (C) The 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.

[[Page 213]]



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



Sec. 74.49  Calculation for deducting allowances.

    (a) Allowance deduction formula. The following formula shall be used 
to determine the total number of allowances to be deducted for the 
calendar year from the allowances held in 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.



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

    (a) 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:
    (1) When the opt-in source has permanently shut down; or
    (2) When the opt-in source has been reconstructed; or
    (3) When the opt-in source becomes an affected unit under Sec. 72.6 
of this chapter; or
    (4) When the opt-in source fails to renew its opt-in permit.
    (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).



           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

[[Page 214]]

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  EPA Study.
75.8  Relative accuracy and availability analysis.

                    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 emissions (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.

            Subpart C--Operation and Maintenance Requirements

75.20  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.

             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.
75.34  Units with add-on emission controls.
75.35  Missing data procedures for CO2 data.
75.36  Missing data procedures for heat input.

                Subpart E--Alternative Monitoring Systems

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

                  Subpart F--Recordkeeping Requirements

75.50  General recordkeeping provisions.
75.51  General recordkeeping provisions for specific situations.
75.52  Certification, quality assurance and quality control record 
          provisions.
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.

                    Subpart G--Reporting Requirements

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


[[Page 215]]


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
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

    Authority: 42 U.S.C. 7601 and 7651k.

    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, 
nitrogen oxides, and carbon dioxide emissions, volumetric flow, and 
opacity data from affected units under the Acid Rain Program pursuant to 
sections 412 and 821 of the Clean Air Act, 42 U.S.C. 7401-7671q as 
amended by Public Law 101-549 (November 15, 1990) (the Act).
    (b) Scope. (1) The regulations established under this part include 
general requirements for the installation, certification, operation, and 
maintenance of continuous emission or opacity monitoring systems and 
specific requirements for the monitoring of SO2 emissions, 
volumetric flow, NOx emissions, opacity, CO2 emissions and 
SO2 emissions removal by qualifying Phase I technologies. 
Specifications for the installation and performance of continuous 
emission monitoring systems, certification tests and procedures, and 
quality assurance tests and procedures are included in appendices A and 
B to this part. Criteria for alternative monitoring systems and 
provisions to account for missing data from certified continuous 
emission monitoring systems or approved alternative monitoring systems 
are also included in the regulation.
    (2) Statistical estimation procedures for missing data are included 
in appendix C to this part. Optional protocols for estimating SO2 
mass emissions from gas-fired or oil-fired units and NOx emissions 
from gas-fired peaking or oil-fired peaking units are included in 
appendices D and E, respectively, to this part. Requirements for 
recording and recordkeeping of monitoring data and for quarterly 
electronic reporting also are specified. Procedures for conversion of 
monitoring data into units of the standard are included in appendix F to 
this part. Procedures for the monitoring and calculation of CO2 
emissions are included in appendix G of this part.

[58 FR 3701, Jan. 11, 1993; 58 FR 34126, June 23, 1993; 58 FR 40747, 
July 30, 1993]



Sec. 75.2  Applicability.

    (a) Except as provided in paragraph (b) 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.

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



Sec. 75.3  General Acid Rain Program provisions.

    The provisions of part 72, including the following, shall apply to 
this part:

[[Page 216]]

    (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 
the 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. 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, NO, CO2, opacity, and volumetric 
flow are installed and all certification tests are completed not later 
than the following dates (except as provided in paragraphs (d) through 
(h) of this section):
    (1) For a unit listed in Table 1 of Sec. 73.10(a) of this chapter, 
November 15, 1993.
    (2) For a substitution or a compensating unit that is designated 
under an approved substitution plan or reduced utilization plan pursuant 
to Sec. 72.41 or Sec. 72.43 of this chapter, or for a unit that is 
designated an early election unit under an approved 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

[[Page 217]]

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, 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 not 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 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 NO emission rate, the maximum potential flow rate, 
as defined in section 2.1 of appendix A of this part, or the maximum 
CO2 concentration used to determine the maximum potential 
concentration of SO2 in section 2.1.1.1 of appendix A of this part; 
or
    (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

[[Page 218]]

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) In accordance with Sec. 75.20, whenever the owner or operator of 
a gas-fired or oil-fired unit uses an excepted monitoring system under 
appendix D or E of this part and combusts emergency fuel as defined in 
Sec. 72.2 of this chapter, then the owner or operator shall ensure that 
a fuel flowmeter measuring emergency fuel is installed and the required 
certification tests for excepted monitoring systems are completed by no 
later than 30 unit operating days after the first date after January 1, 
1995 that the unit combusts emergency fuel. For all unit operating hours 
that the unit combusts emergency fuel after January 1, 1995 until the 
owner or operator installs a flowmeter for emergency fuel and 
successfully completes all required certification tests, the owner or 
operator shall determine and report SO2 mass emission data using 
either:
    (1) The maximum potential fuel flow rate, as described in appendix D 
of this part, and the maximum sulfur content of the fuel, as described 
in section 2.1.1.1 of appendix A of this part;
    (2) Reference methods under Sec. 75.22(b) of this part; or
    (3) Another procedure approved by the Administrator pursuant to a 
petition under Sec. 75.66.
    (h) 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.

[60 FR 17131, Apr. 4, 1995, as amended at 60 FR 26516, May 17, 1995]



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 75.67 and 
appendices A through I of 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 
75.18.
    (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

[[Page 219]]

discontinue use of the continuous emission monitoring system, any 
component thereof, the continuous opacity monitoring system, or any 
other approved emission monitoring system under this part, except under 
any one of the following circumstances:
    (1) During the period that the unit is covered by an approved 
retired unit exemption under Sec. 72.8 of this chapter that is in 
effect; or
    (2) The owner or operator is monitoring emissions from the unit with 
another certified monitoring system that provides emission 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]



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

[[Page 220]]

Gases in Natural Gas Range by Continuous Recording Calorimeter, for 
appendix F of 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 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 appendix F of 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 appendix F of 
this part.

[[Page 221]]

    (39) ASTM D5291-92, Standard Test Methods for Instrumental 
Determination of Carbon, Hydrogen, and Nitrogen in Petroleum Products 
and Lubricants, for appendix G of this part.
    (40) 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, 
Farifield, NJ 07007-2350.
    (1) ASME MFC-3M-1989 with September 1990 Errata, Measurement of 
Fluid Flow in Pipes Using Orifice, Nozzle, and Venturi, for Sec. 75.20 
and appendix D of this part.
    (2) ASME MFC-4M-1986 (Reaffirmed 1990), Measurement of Gas Flow by 
Turbine Meters, for Sec. 75.20 and appendix D of this part.
    (3) ASME-MFC-5M-1985, Measurement of Liquid Flow in Closed Conduits 
Using Transit-Time Ultrasonic Flowmeters, for Sec. 75.20 and 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 Sec. 75.20 and appendix D of 
this part.
    (5) ASME MFC-7M-1987 (Reaffirmed 1992), Measurement of Gas Flow by 
Means of Critical Flow Venturi Nozzles, for Sec. 75.20 and 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 Sec. 75.20 and 
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 
Sec. 75.20 and 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: 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 
Sec. 75.20 and appendices D and E of this part.

[58 FR 3701, Jan. 11, 1993, as amended at 60 FR 26517, May 17, 1995]



Sec. 75.7  EPA Study.

    The Agency will initiate rulemaking to adjust the equations in the 
bias test by an amount sufficient to compensate for reference method 
variance based on a study, which EPA shall complete by October 31, 1993, 
unless the Administrator determines that adjustments are technically 
unnecessary or infeasible to properly determine bias.

[58 FR 3701, Jan. 11, 1993; 58 FR 40747, July 30, 1993]



Sec. 75.8  Relative accuracy and availability analysis.

    (a) The Agency will conduct an analysis of monitoring data submitted 
to EPA under this part between November 15, 1993 and December 31, 1996 
to evaluate the appropriateness of the current performance 
specifications for relative accuracy and availability trigger conditions 
for missing data substitution for SO2 and CO2 pollutant 
concentration monitors, flow monitors, and NOX continuous emission 
monitoring systems.
    (b) Prior to July 1, 1997, the Agency will prepare a report 
evaluating quarterly report data for the period between January 1, 1994 
and December 31,

[[Page 222]]

1996 and initial certification test data. Based upon this evaluation, 
the Administrator will sign for publication in the Federal Register, 
either:
    (1) A notice that the Agency has completed its analysis and has 
determined that retaining the current performance specifications for 
relative accuracy and availability trigger conditions are appropriate; 
or
    (2) A notice that the Agency will develop a proposed rule, based on 
the results of the study, proposing alternatives to the current 
performance specifications for relative accuracy and availability 
trigger conditions.
    (c) If the Administrator signs a notice that the Agency will develop 
a proposed rule, the Administrator will:
    (1) Sign a notice of proposed rulemaking by October 31, 1997; and
    (2) Sign a notice of final rulemaking by October 31, 1998.

[60 FR 26519, May 17, 1995]



                    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

[[Page 223]]

ensure that each continuous emission monitoring system required by this 
part meets the equipment, installation, and performance specifications 
in Appendix A to this part; and is maintained according to the quality 
assurance and quality control procedures in Appendix B to this part; and 
shall record SO2 and NOx emissions in the appropriate units of 
measurement (i.e., lb/hr for SO2 and lb/mmBtu for NOx).
    (c) Heat Input 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 are acquired by

[[Page 224]]

both the pollutant concentration monitor (NOX or SO2) and the 
diluent monitor (CO2 or O2). Except for SO2 emission rate 
data in lb/mmBtu, if a valid hour of data is not obtained, the owner or 
operator shall estimate and record emission 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 a full scale exceedance, except as 
provided in sections 2.1.1.4, 2.1.2.4, and 2.1.4 of appendix A of this 
part.
    (g) Minimum Recording and Reporting Requirements. The owner or 
operator shall record and the designated representative shall report the 
hourly, daily, quarterly, and annual information collected under the 
requirements of this part as specified in subparts F and G of this part.

[58 FR 3701, Jan. 11, 1993, as amended at 60 FR 26519, May 17, 1995]



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 for each affected coal-fired unit, except as provided 
in Sec. 75.16 and in subpart E of this part. The provisions in this 
paragraph are suspended from July 17, 1995, through December 31, 1996.
    (b) Moisture correction. Where SO2 concentration is measured on 
a dry basis, the owner or operator shall either:
    (1) Install, operate, and maintain a continuous moisture monitor for 
measuring and recording the moisture content of the flue gases; or
    (2) Determine the moisture content of the flue gases continuously 
(or on an hourly basis) and correct the measured hourly volumetric flow 
rates for moisture when calculating SO2 mass emissions (in lb/hr) 
using the procedures in appendix F of this part.
    (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

[[Page 225]]

    (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 units 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 using one of the following methods:
    (1) Meet the general operating requirements in Sec. 75.10 for an 
SO2 continuous emission monitoring system and flow monitoring 
system except as provided in paragraph (e) of this section. When the 
owner or operator uses an SO2 continuous emission monitoring system 
and flow monitoring system to monitor SO2 mass emissions from an 
affected unit, the owner or operator shall comply with applicable 
monitoring provisions in paragraph (a) of this section; or
    (2) Provide other information satisfactory to the Administrator 
using the procedure specified in appendix D to this part for estimating 
hourly SO2 mass emissions.
    (e) Units with SO2 continuous emission monitoring systems 
during the combustion of gaseous fuel. On or after January 1, 1997, the 
owner or operator of a unit with an SO2 continuous emission 
monitoring system shall, during any hours in which the unit combusts 
only pipeline natural gas or gaseous fuel with a sulfur content no 
greater than natural gas, calculate SO2 emissions in accordance 
with the following procedures. Prior to January 1, 1997, the owner or 
operator of such a unit may calculate SO2 emissions in accordance 
with the following procedures.
    (1) The owner or operator of a unit with an SO2 continuous 
emission monitoring system shall, during any hours in which the unit 
combusts only pipeline natural gas, calculate SO2 emissions using 
one of the following two methods in lieu of operating and recording data 
from the SO2 continuous emission monitoring system:
    (i) By using the heat input calculated using a certified flow 
monitoring system and a certified diluent monitor, the default SO2 
emission rate for pipeline natural gas from appendix D of this part, and 
Equation F-23 in appendix F of this part and by certifying this as a 
system for monitoring SO2 mass emissions by identification in the 
monitoring plan, by tests for the data acquisition and handling system 
under Sec. 75.20(c), and by meeting all quality control and quality 
assurance requirements in appendix B of this part for a flow monitor and 
a diluent monitor; or
    (ii) By certifying an excepted monitoring system under appendix D of 
this part under Sec. 75.20, by following the procedures for determining 
SO2 emissions from combustion of gaseous fuels under appendix D of 
this part, by meeting the recordkeeping requirements of Sec. 75.55, and 
by meeting all quality control and quality assurance requirements for 
fuel flowmeters in appendix D of this part.
    (2) During any hours in which the unit combusts only gaseous fuel 
with a sulfur content no greater than natural gas other than pipeline 
natural gas, the owner or operator shall calculate SO2 mass 
emissions by certifying an excepted monitoring system under appendix D 
of this part under Sec. 75.20, by using the gas sampling and analysis 
and fuel flow procedures of appendix D of this part, by meeting the 
recordkeeping requirements of Sec. 75.55, and by meeting all quality 
control and quality assurance requirements for fuel flowmeters in 
appendix D of this part.

[[Page 226]]

    (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.
    (g) 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 or any fuel other than 
natural gas or a gaseous fuel with a sulfur content no greater than 
natural gas, except as provided in Sec. 75.16 and in subpart E of this 
part.

[58 FR 3701, Jan. 11, 1993, as amended at 60 FR 26520, 26566, May 17, 
1995]

    Effective Date Notes: 1. At 60 FR 26560, 26566, May 17, 1995, 
Sec. 75.11(a) was temporarily suspended, effective July 17, 1995 through 
December 31, 1996.

    2. At 60 FR 26560, 26566, May 17, 1995, Sec. 75.11(e) and (g) were 
temporarily added and are effective from July 17, 1995 through December 
31, 1996.



Sec. 75.12  Specific provisions for monitoring NOx emissions (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 (c) 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.
    (b) 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) and 
diluent concentration (in percent O2 or CO2) measurements 
according to the procedures in appendix F of this part.
    (c) 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.
    (d) 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]



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 Sec. 75.11 (a) 
through (e) or Sec. 75.16, except that the phrase ``SO2 continuous 
emission monitoring system'' is replaced with ``CO2 continuous 
emission monitoring system,'' the term ``maximum potential concentration 
for SO2'' is replaced with ``maximum CO2 concentration,'' and 
the phrase ``SO2 mass emissions'' is replaced with ``CO2 mass 
emissions.''
    (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

[[Page 227]]

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. 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, hourly 
corrections for the moisture content of the flue gases, using the 
methods and procedures specified in appendix F to this part. For units 
using a common stack, multiple stack, or by-pass stack, the owner or 
operator may use the provisions of Sec. 75.16, except that the phrase 
``SO2 continuous emission monitoring system'' is replaced with 
``CO2 continuous emission monitoring system,'' the term ``maximum 
potential concentration of SO'' is replaced with ``maximum CO2 
concentration,'' and the phrase ``SO2 mass emissions'' is replaced 
with ``CO2 mass emissions.''

[58 FR 3701, Jan. 11, 1993, as amended at 60 FR 26521, May 17, 1995]



Sec. 75.14  Specific provisions for  monitoring opacity.

    (a) Coal-fired units and oil-fired units. The owner or operator 
shall meet the general operating provisions in Sec. 75.10 of this part 
for a continuous opacity monitoring system for each affected coal-fired 
or oil-fired unit, except as provided in paragraphs (b), (c), and (d) of 
this section and in Sec. 75.18. Each continuous opacity monitoring 
system shall meet the design, installation, equipment, and performance 
specifications in Performance Specification 1 in appendix B to part 60 
of this chapter. Any continuous opacity monitoring system previously 
certified to meet Performance Specification 1 shall be deemed certified 
for the purposes of this part.
    (b) Unit with wet flue gas pollution control system. If the owner or 
operator can demonstrate that condensed water is present in the exhaust 
flue gas stream and would impede the accuracy of opacity measurements, 
then the owner or operator of an affected unit equipped with a wet flue 
gas pollution control system for SO2 emissions or particulates is 
exempt from the opacity monitoring requirements of this part.
    (c) Gas-fired units. The owner or operator of an affected unit that 
qualifies as gas-fired, as defined in Sec. 72.2 of this chapter, based 
on information submitted by the designated representative in the 
monitoring plan is exempt from the opacity monitoring requirements of 
this part. Whenever a unit previously categorized as a gas-fired unit is 
recategorized as another type of unit by changing its fuel mix, the 
owner or operator shall install, operate, and certify a continuous 
opacity monitoring system as required by paragraph (a) of this section 
by December 31 of the following calendar year.
    (d) Diesel-fired units and dual-fuel reciprocating engine units. The 
owner or operator of an affected diesel-fired unit or a dual-fuel 
reciprocating engine unit is exempt from the opacity monitoring 
requirements of this part.

[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

[[Page 228]]

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 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

[[Page 229]]

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

(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
          

[[Page 230]]


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 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; and combine 
emissions for the Phase I units for compliance purposes; or
    (C) Install, certify, operate, and maintain an SO2 continuous 
emission

[[Page 231]]

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; 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
    (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; and combine emissions for the Phase I 
and Phase II affected units for recordkeeping and compliance purposes; 
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

[[Page 232]]

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 Administrator may approve such demonstrated 
substitute methods for apportioning SO2 mass emissions measured in 
a common stack whenever the demonstration ensures complete and accurate 
accounting of all emissions regulated under this part.
    (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 the sum of 
the SO2 mass emissions recorded for each stack, except that where 
another unit also exhausts flue gases to one or more of the stacks, the 
owner or operator shall also comply with the applicable common stack 
requirements of this section to determine and record SO2 mass 
emissions from the units using that stack.
    (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 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 terms 
``SO2 mass emissions'' and ``emissions'' are replaced with the term 
``heat input'' and the phrase ``SO2 continuous emission monitoring 
system and flow monitoring system'' is replaced with the phrase ``a 
diluent monitor and a flow monitor''.

[[Page 233]]

    (2) Notwithstanding paragraph (e)(1) of this section, for any common 
stack where any unit utilizing the common stack has a NOX emission 
limitation pursuant to Section 407(b) of the Act, the owner or operator 
shall not combine heat input for compliance purposes and shall determine 
heat input for that unit separately.
    (3) Notwithstanding paragraph (e)(1) of this section, during the 
period prior to January 1, 2000, the owner or operator shall not combine 
heat input for units utilizing a common stack in order to determine heat 
input for each unit for purposes of Sec. 75.10.
    (4) 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.

[60 FR 26522, May 17, 1995, as amended at 61 FR 25582, May 22, 1996]



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

    (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, as provided in a 
petition submitted by the designated representative. The Administrator 
may approve such demonstrated substitute methods for apportioning 
NOX emission rate measured in a common stack whenever the 
demonstration ensures complete and accurate estimation of all emissions 
regulated under this part.
    (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

[[Page 234]]

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 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]



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

[[Page 235]]

    (2) A continuous opacity monitoring system is already installed and 
certified at the inlet of the add-on emissions controls.

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



            Subpart C--Operation and Maintenance Requirements



Sec. 75.20  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 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. 75.13 
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. 75.60 and Sec. 75.61(a)(1)(i).
    (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 applications. Upon the 
successful completion of the required certification procedures of this 
section for each continuous emission or opacity monitoring system or 
component thereof, each continuous emission or opacity monitoring system 
or component thereof shall be deemed provisionally certified for use 
under the Acid Rain Program for a period not to exceed 120 days 
following receipt by the Administrator of the complete certification 
application under paragraph (a)(4) of this section; provided that 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 for use under the Acid 
Rain Program. Data measured and recorded by a provisionally certified 
continuous emission or opacity monitoring system or component thereof, 
in accordance with the requirements of appendix B of this part, will be 
considered valid quality-assured data (retroactive to the date and time 
of successful completion of all certification tests), provided that the 
Administrator does not invalidate the provisional certification by 
issuing a notice of disapproval within 120 days of receipt of the 
complete certification application.
    (4) Certification application formal approval process. The 
Administrator will issue a written notice of approval or disapproval of 
the certification application to the owner or operator within 120 days 
of receipt of the complete certification application. In the event the 
Administrator does not issue such a written 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 application will be deemed certified for use under the 
Acid Rain Program.
    (i) Approval notice. If the certification 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 written notice of approval of the certification application 
within 120 days of receipt.
    (ii) Incomplete application notice. If the certification application 
is not complete, then the Administrator will issue a written notice of 
insufficiency. The 120-day review period shall not begin prior to 
receipt of a complete application.

[[Page 236]]

    (iii) Disapproval notice. If the certification application is 
complete but shows that any continuous emission or opacity monitoring 
system or component thereof does not meet the performance requirements 
of this part, 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 measured and recorded by 
each uncertified continuous emission or opacity monitoring system or 
component thereof shall not be considered valid quality-assured data 
from the date and time of completion of the invalid certification tests 
until the date and time that the owner or operator completes 
subsequently approved initial certification tests. The owner or operator 
shall follow the procedures for loss of certification in paragraph 
(a)(5) of this section for each continuous emission or opacity 
monitoring system or component thereof which was disapproved.
    (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) 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 of appendix A of 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, the maximum 
potential flow rate, as defined in section 2.1 of appendix A of 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 of this part to report CO2 
concentration data 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; 
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 the certified continuous 
emission monitoring system or continuous opacity monitoring system 
(which includes the automated data acquisition and handling system, and, 
where applicable, the CO2 continuous emission monitoring system), 
that significantly affects the ability of the system to measure or 
record the SO2 concentration, volumetric gas flow, SO2 mass 
emissions, NOX emission rate, CO2 concentration, or opacity, 
or to meet the requirements of Sec. 75.21 or appendix B of this part, 
the owner or operator shall recertify the continuous emission monitoring 
system, continuous opacity monitoring system, or component thereof 
according to the procedures in this paragraph. Examples of changes which 
require recertification include: replacement of the analytical method, 
including the analyzer; change in location or orientation of the 
sampling probe or site; rebuilding of the analyzer or all monitoring 
system equipment; and replacement of an existing continuous emission 
monitoring system or continuous opacity monitoring system. In addition, 
if a continuous emission monitoring system is not operating for more 
than two calendar years, then the owner or operator shall recertify the

[[Page 237]]

continuous emission monitoring system. The Administrator may determine 
whether a replacement, modification or change in a monitoring system 
significantly affects the ability of the monitoring system to measure or 
record the SO2 concentration, volumetric gas flow, SO2 mass 
emissions, NOX emission rate, CO2 concentration, or opacity. 
Furthermore, whenever the owner or operator makes a replacement, 
modification, or change to the flue gas handling system or the unit 
operation that significantly changes the flow or concentration profile 
or opacity of monitored emissions, the owner or operator shall recertify 
the continuous emission or opacity monitoring system or component 
thereof according to the procedures in this paragraph. Recertification 
is not required prior to use of a non-redundant backup continuous 
emission monitoring system in cases where all of the following 
conditions have been met: the non-redundant backup continuous emission 
monitoring system has previously been certified at the same sampling 
location; all components of the non-redundant backup continuous emission 
monitoring system have previously been certified; and component monitors 
of the non-redundant backup continuous emission monitoring system pass a 
linearity check (for pollutant concentration monitors) or a calibration 
error test (for flow monitors) prior to their use for monitoring of 
emissions or flow. In addition, changes resulting from routine or normal 
corrective maintenance and/or quality assurance activities do not 
require recertification, nor do software modifications in the automated 
data acquisition and handling system, where the modification is only for 
the purpose of generating additional or modified reports for the State 
Implementation Plan or for reporting requirements under subpart G of 
this part.
    (1) Tests required. For recertification testing, the owner or 
operator shall complete all certification tests in paragraph (c) of this 
section applicable to the monitoring system, except as approved by the 
Administrator. Such approval may be obtained by petition under 
Sec. 75.66 or may be provided in written guidance from the 
Administrator.
    (2) Notification of recertification test dates. The owner or 
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 such testing is required as a result of a 
change in the flue gas handling system, a change in location or 
orientation of the sampling probe or site, or the planned replacement of 
a continuous emission or opacity monitoring system or component thereof. 
In such cases, 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) Substitution of missing data. (i) The owner or operator shall 
substitute for missing data during the period following the replacement, 
modification, or change to the monitoring system up to the time of 
successful completion of all recertification testing according to the 
standard missing data procedures in Secs. 75.33 through 75.36, and shall 
use the standard missing data substitution procedures for all missing 
data periods following the recertification, except as provided below.
    (ii) If the replacement, modification, or change is such that the 
data collected by the prior certified monitoring system are no longer 
representative, such as after a change to the flue gas handling system 
or unit operation that requires changing the span value to be consistent 
with Section 2.1 of appendix A of this part, the owner or operator must 
also substitute the appropriate one of the following values: 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 during the period following the 
replacement, modification, or change up to the time of the successful 
completion of all recertification testing; or for a change that results 
in a significantly lower concentration or flow rate, substitute data 
using the standard missing data procedures during the period following 
the replacement, modification, or change up to the time of the 
successful completion of all recertification testing.

[[Page 238]]

The owner or operator shall then use the initial missing data procedures 
in Sec. 75.31 following provisional certification, unless otherwise 
provided by Sec. 75.34 for units with add-on emission controls.
    (4) Recertification application. The designated representative shall 
apply for recertification of a continuous emission or opacity monitoring 
system used under the Acid Rain Program according to the procedures in 
paragraph (a)(2) of this section. Each complete recertification 
application shall include the information specified in Sec. 75.63 of 
this part.
    (5) Approval/disapproval of request for recertification. The 
procedures for provisional certification in paragraph (a)(3) of this 
section shall apply. The Administrator will issue a written notice of 
approval or disapproval according to the procedures in paragraph (a)(4) 
of this section, except that the period for the Administrator's review 
provided under paragraph (a)(4) of this section shall not exceed 60 days 
following receipt of the complete recertification application by the 
Administrator. The missing data substitution procedures under paragraph 
(b)(3) of this section shall apply in the event of a loss of 
recertification.
    (c) Certification procedures. Prior to the deadline in Sec. 75.4 of 
this part, the owner or operator shall conduct 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 of this part:
    (1) For each SO2 pollutant concentration monitor and NOx 
continuous emission monitoring system:
    (i) A 7-day calibration error test, where, for the NOx 
continuous emission monitoring system, this test is performed separately 
on the NOx pollutant concentration monitor and the diluent gas 
monitor;
    (ii) A linearity check, where, for the NOx continuous emission 
monitoring system, this check is performed separately on the NOx 
pollutant concentration monitor and the diluent gas monitor;
    (iii) A relative accuracy test audit;
    (iv) A bias test; and
    (v) A cycle time test.
    (v) A cycle time/response time test.
    (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 relative accuracy test audits for the SO2 pollution 
concentration monitor and the flow monitor shall be performed 
contemporaneously.
    (4) The 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 
Sec. 75.20(c)(5).
    (5) For each CO2 pollutant concentration monitor or O2 
monitor which is part of a CO2 continuous emission monitoring 
system or is used to monitor heat input and for 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.
    (6) The owner or operator shall ensure that certification or 
recertification of a continuous opacity monitor for use under the Acid 
Rain Program is conducted according to one of the following procedures:

[[Page 239]]

    (i) Performance of the tests for certification or recertification, 
according to the requirements of Performance Specification 1 in appendix 
B to part 60 of this chapter.
    (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.
    (7) 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.
    (8) The owner or operator shall provide, or cause to be provided, 
adequate facilities for certification or recertification testing that 
include:
    (i) Sampling ports adequate for test methods applicable to such 
facility, such that:
    (A) Volumetric flow rate, pollutant concentration, and pollutant 
emission rates can be accurately determined by applicable test methods 
and procedures; and
    (B) A stack or duct free of cyclonic flow during performance tests 
is available, as demonstrated by applicable test methods and procedures.
    (ii) Basic facilities (e.g., electricity) for sampling and testing 
equipment.
    (d) Certification/recertification procedures for optional backup 
continuous emission monitoring systems--(1) Redundant backups. The owner 
or operator of an optional redundant backup continuous emission 
monitoring system 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 continuous emission monitoring system 
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 continuous emission monitoring system 
all quality assurance and quality control procedures specified in 
appendix B of this part.
    (2) Non-redundant backups. The owner or operator of an optional non-
redundant backup continuous emission monitoring system 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 for each non-redundant backup continuous emission 
monitoring system, except that: the owner or operator of a non-redundant 
backup continuous emission monitoring system may omit the 7-day 
calibration error test for certification or recertification of an 
SO2 pollutant concentration monitor, flow monitor, NOX 
pollutant concentration monitor, or diluent gas monitor, provided the 
non-redundant backup system is not used for reporting on any affected 
unit for more than 720 hours in any calendar year. In addition, the 
owner or operator shall ensure that the certified non-redundant backup 
continuous emission monitoring system passes a linearity check (for 
pollutant concentration monitors) or a calibration error test (for flow 
monitors) prior to each use for recording and reporting emissions and 
complies with the daily and quarterly quality assurance and quality 
control requirements in appendix B of this part for each day and quarter 
that the non-redundant backup monitoring system is used to report data. 
If the owner or operator does not perform semi-annual or annual relative 
accuracy test audits upon the non-redundant backup continuous emission 
monitoring system, then the owner or operator shall recertify the non-
redundant continuous emission monitoring system once every two calendar 
years, performing all certification tests applicable under this 
paragraph. However, if a non-redundant backup system is used for 
reporting data from any affected unit or common stack for more than 720 
hours in any one calendar year, then reported data after the first 720 
hours is not valid, quality-assured data unless the owner or operator 
has ensured that the non-redundant backup monitoring system has also 
passed the 7-day calibration error test, before data

[[Page 240]]

is recorded for any period in excess of 720 hours for that calendar year 
for that monitoring system.
    (3) Reference method backups. A monitoring system that is operated 
as a reference method backup system pursuant to the reference method 
requirements of Methods 2, 6C, 7E, or 3A in appendix A of part 60 of 
this chapter need not perform and pass the certification tests required 
by paragraph (c) of this section prior to its use pursuant to this 
paragraph.
    (e) Certification/recertification procedures for either peaking unit 
or by-pass stack/duct continuous emission monitoring systems. The owner 
or operator of either a peaking unit or by-pass stack/duct continuous 
emission monitoring system shall comply with all the requirements for 
certification or recertification according to the procedures specified 
in paragraphs (a), (b), and (c) of this section, except as follows: the 
owner or operator need only perform one nine-run relative accuracy test 
audit for certification or recertification of a flow monitor installed 
on the by-pass stack/duct or on the stack/duct used only by affected 
peaking unit(s). The relative accuracy test audit shall be performed 
during normal operation of the peaking unit(s) or the by-pass stack/
duct.
    (f) Certification/recertification procedures for alternative 
monitoring systems. The designated representative representing the owner 
or operator of each alternative monitoring system approved by the 
Administrator as equivalent to or better than a continuous emission 
monitoring system according to the criteria in subpart E of this part 
shall apply for certification to the Administrator prior to use of the 
system under the Acid Rain Program, and shall apply for recertification 
to the Administrator following a replacement, modification, or change 
according to the procedures in paragraph (c) of this section. The owner 
or operator of an alternative monitoring system shall comply with the 
notification and application requirements for certification or 
recertification according to the procedures specified in paragraphs (a) 
and (b) of this section.
    (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) Certification 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 of this part shall ensure that an excepted monitoring system under 
appendix D or E of 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 certification requirements of this 
paragraph.
    (1) Certification testing. The owner or operator shall use the 
following procedures for certification of an excepted monitoring system 
under appendix D or E of this part.
    (i) When 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 is used, the owner or operator shall 
provide data from a calibration test for each fuel flowmeter according 
to the appropriate calibration procedures using one of the following 
standard methods: ASME MFC-3M-1989 with September 1990 Errata, 
``Measurement of Fluid Flow in Pipes Using Orifice, Nozzle, and 
Venturi'', ASME MFC-4M-1986 (Reaffirmed 1990) ``Measurement of Gas Flow 
by Turbine Meters'', ASME MFC-5M-1985 ``Measurement of Liquid Flow in 
Closed Conduits Using Transit-Time Ultrasonic Flowmeters'', ASME MFC-6M-
1987 with June 1987 Errata, ``Measurement of Fluid Flow in Pipes Using 
Vortex Flow Meters'', ASME MFC-7M-1987 (Reaffirmed 1992), ``Measurement 
of Gas Flow by Means of Critical Flow Venturi Nozzles'', ASME MFC-9M-
1988 with December 1989 Errata, ``Measurement of Liquid Flow in Closed 
Conduits by Weighing Method'', ISO 8316: 1987(E) ``Measurement of Liquid 
Flow in Closed Conduits--Method by Collection

[[Page 241]]

of the Liquid in a Volumetric Tank'', or American Gas Association Report 
No. 3: Orifice Metering of Natural Gas and Other Related Hydrocarbon 
Fluids Part 1: General Equations and Uncertainty Guidelines (October 
1990 Edition), Part 2: Specification and Installation Requirements 
(February 1991 Edition) and Part 3: Natural Gas Applications (August 
1992 Edition), excluding the modified calculation procedures of Part 3, 
as required by appendices D and E of this part (all methods incorporated 
by reference under Sec. 75.6). The Administrator may also approve other 
procedures that use equipment traceable to National Institute of 
Standards of Technology (NIST) standards. The designated representative 
shall document the procedure and the equipment used in the monitoring 
plan for the unit and in a petition submitted in accordance with 
Sec. 75.66(c).
    (ii) For the automated data acquisition and handling system used 
under either the optional SO2 mass emissions estimation procedure 
in appendix D of this part or the optional NOX emissions estimation 
protocol in appendix E of this part, the owner or operator shall perform 
tests designed to verify:
    (A) The proper computation of hourly averages for pollutant 
concentrations, fuel flow rates, emission rates, heat input, and 
pollutant mass emissions; and
    (B) Proper computation and application of the missing data 
substitution procedures in appendix D or E of this part.
    (iii) When the optional NOX emissions protocol in appendix E is 
used, the owner or operator shall complete all initial performance 
testing under section 2.1 of appendix E.
    (2) Certification testing notification. The designated 
representative shall provide initial certification testing notification 
and periodic retesting notification for an excepted monitoring system 
under appendix E of this part as specified in Sec. 75.61. The designated 
representative shall submit recertification testing notification as 
specified in Sec. 75.61 for quality assurance/quality control-related 
NOX emission rate testing under section 2.3 of appendix E of this 
part for an excepted monitoring system under appendix E of this part. 
Certification testing notification or periodic retesting notification is 
not required for testing of a fuel flowmeter or testing for an excepted 
monitoring system under appendix D of this part.
    (3) Monitoring plan. The designated representative shall submit an 
initial monitoring plan in accordance with Sec. 75.62(a).
    (4) Certification application. The designated representative shall 
submit a certification application in accordance with Secs. 75.60 and 
75.63.
    (5) Provisional approval of certification applications. Upon the 
successful completion of the required certification procedures for each 
excepted monitoring system under appendix D or E of this part, each 
excepted monitoring system under appendix D or E of 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 
certification application formal approval process in paragraph (a)(4) of 
this section shall apply. Data measured and recorded by a provisionally 
certified excepted monitoring system under appendix D or E of this part, 
will be considered quality-assured data from the date and time of 
completion of the final certification test, provided that the 
Administrator does not revoke the provisional certification by issuing a 
notice of disapproval within 120 days of receipt of the complete 
certification application in accordance with the provisions in paragraph 
(a)(4) of this section.

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



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 under the Acid Rain Program according to 
the quality assurance and quality control procedures in appendix B of 
this part. The provisions in this paragraph are suspended from July 17, 
1995 through December 31, 1996.

[[Page 242]]

    (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) [Reserved]
    (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 paragraph (a)(1)(iv) of 
Sec. 75.20, under appendix B of 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 emissions or heat input, nor for 
calculations of monitor data availability.
    (1) Audit decertification. Whenever both: an audit (including audits 
required under appendix B of this part) of a continuous emission or 
opacity monitoring system or component thereof, including the data 
acquisition and handling system, and a review of the initial 
certification application or recertification application, reveal that 
any continuous emission or opacity monitoring system or component should 
not have been certified because it did not meet a particular performance 
specification or other requirement of this part both at the time of the 
certification 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. By issuing the notice of 
disapproval, the certification status is revoked, prospectively, by the 
Administrator. The data measured and recorded by each continuous 
emission or opacity monitoring system shall not be considered valid 
quality-assured data from the date of issuance of the notification of 
the revoked certification status until the date and time that the owner 
or operator completes subsequently approved certification tests. The 
owner or operator shall follow the procedures for loss of certification 
in Sec. 75.20(a)(5) for initial certification or Sec. 75.20(b)(3) for 
recertification to replace, prospectively, all of the invalid, non-
quality-assured data for each disapproved continuous emission or opacity 
monitoring system.
    (2) Out-of-control period. Whenever a continuous emission monitoring 
system or continuous opacity monitoring system fails a periodic quality 
assurance audit, an audit under Sec. 75.20(a)(1)(iv), a field audit from 
EPA personnel or other audit, the system is out-of-control. The owner or 
operator shall follow the procedures for out-of-control periods in 
Sec. 75.24.
    (f) Continuous emission monitoring systems. The owner or operator of 
an affected unit shall operate, calibrate, and maintain each primary and 
redundant backup continuous emission monitoring system used under the 
Acid Rain Program according to the quality assurance and quality control 
procedures in appendix B of this part. The owner or operator of an 
affected unit shall ensure that each non-redundant backup continuous 
emission monitoring system used under the Acid Rain Program complies 
with the daily and quarterly quality assurance and quality control 
procedures in appendix B of this part for each day and quarter that the 
system is used to report data. 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, instead of the procedures specified in 
appendix B of this part. Notwithstanding the provisions of appendix B of 
this part, the owner or operator of a unit with an SO2 continuous 
emission monitoring system is not required to perform daily or quarterly 
assessments under appendix B of this part on any day or in any calendar 
quarter during which the unit combusts only natural gas or a gaseous 
fuel with a sulfur content no greater than natural gas. In addition, any 
calendar quarter during which the unit combusts only natural gas or a 
gaseous fuel with a sulfur content no greater than

[[Page 243]]

natural gas shall be excluded in determining the calendar quarter, 
bypass operating quarter, or unit operating quarter when the next 
relative accuracy test audit must be performed for the SO2 
continuous emission monitoring system, provided that a relative accuracy 
test audit is performed on that system at least once every two calendar 
years. The owner or operator of a unit using a certified flow monitor 
and a certified diluent monitor and Equation F-23 to calculate SO2 
emissions shall meet all quality control and quality assurance 
requirements in appendix B of this part for the flow monitor and the 
diluent monitor.

[58 FR 3701, Jan. 11, 1993, as amended at 60 FR 26527, 26566, May 17, 
1995; 61 FR 25582, May 22, 1996]

    Effective Date Notes: 1. At 60 FR 26560, 26566, May 17, 1995, 
Sec. 75.21(a) was temporarily suspended, effective July 17, 1995 through 
December 31, 1996.

    2. At 60 FR 26560, 26566, May 17, 1995, Sec. 75.21(f) was 
temporarily added, effective July 17, 1995 through December 31, 1996.



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.
    (1) Methods 1 or 1A are the reference methods for selection of 
sampling site and sample traverses.
    (2) Methods 2, 2A, 2C, or 2D 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 is the reference method for the determination of 
moisture in the stack.
    (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 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 of this part.
    (c) (1) Performance tests shall be conducted and data reduced in 
accordance with the test methods and procedures of this part unless the 
Administrator:
    (i) Specifies or approves, in specific cases, the use of a reference 
method with minor changes in methodology;
    (ii) Approves the use of an equivalent method; or
    (iii) Approves shorter sampling times and smaller sample volumes 
when necessitated by process variables or other factors.
    (2) Nothing in this paragraph shall be construed to abrogate the 
Administrator's authority to require testing under Section 114 of the 
Act.

[58 FR 3701, Jan. 11, 1993, as amended at 60 FR 26528, May 17, 1995]



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]

[[Page 244]]



Sec. 75.24  Out-of-control periods.

    (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, 
volumetric flow monitor, or NOX continuous emission monitoring 
system is biased low (i.e., the arithmetic mean of the differences 
between the reference method value and the monitor or monitoring system 
measurements in a relative accuracy test audit exceed the bias statistic 
in section 7 of appendix A to this part), the owner or operator shall 
adjust the monitor or continuous emission monitoring system to eliminate 
the cause of bias such that it passes the bias test or calculate and use 
the bias adjustment factor as specified in section 2.3.3 of appendix B 
to this part and in accordance with Sec. 75.7.
    (e) The owner or operator shall determine if a continuous opacity 
monitoring system is out-of-control and shall take appropriate 
corrective actions according to the procedures specified for State 
Implementation Plans, pursuant to appendix M of part 51 of this chapter. 
The owner or operator shall comply with the monitor data availability 
requirements of the State. If the State has no monitor data availability 
requirements for continuous opacity monitoring systems, then the owner 
or operator shall comply with the monitor data availability requirements 
as stated in the data capture provisions of appendix M, part 51 of this 
chapter.

[58 FR 3701, Jan. 11, 1993, as amended at 60 FR 26528, May 17, 1995]



             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

[[Page 245]]

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 and recorded for an affected unit by a 
certified NOX 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 of this part) has not been measured and 
recorded for an affected unit by a certified CO2 continuous 
emission monitoring system, 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 or CO2 (or O2) 
concentration, flow, or NOX emission rate data recorded from either 
a certified redundant or non-redundant backup continuous emission 
monitor or a backup reference method monitoring system when the 
certified primary monitor is not operating or out-of-control. A 
redundant or non-redundant backup continuous emission monitoring system 
must have been certified according to the procedures in Sec. 75.20 prior 
to the missing data period. Non-redundant backup continuous emission 
monitoring system must pass a linearity check (for pollutant 
concentration monitors) or a calibration error test (for flow monitors) 
prior to each period of use of the certified backup monitor for 
recording and reporting emissions. Use of a certified backup monitoring 
system or backup reference method monitoring system is optional and at 
the discretion of the owner or operator.
    (c) When the certified primary monitor is not operating or out-of-
control, then data recorded for an affected unit from a certified backup 
continuous emission monitor or backup reference method monitoring system 
are used, as if such data were from the certified primary monitor, to 
calculate monitor data availability in Sec. 75.32, and to provide the 
quality-assured data used in the missing data procedures in Secs. 75.31 
and 75.33, such as the ``hour after'' value.
    (d) On or after January 1, 1997, the owner or operator shall comply 
with the provisions of this paragraph. Prior to January 1, 1997, the 
owner or operator may comply with the provisions of this paragraph (d) 
if also complying with the provisions of Sec. 75.11(e).
    (1) Whenever a unit with an SO2 continuous emission monitoring 
system combusts only pipeline natural gas and the owner or operator is 
using the procedures in section 7 of appendix F of this part to 
determine SO2 mass emissions pursuant to Sec. 75.11(e), the owner 
or operator shall 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 continuous emission monitoring 
system combusts gas with a sulfur content no greater than natural gas or 
pipeline natural gas and the owner or operator is using the gas sampling 
and analysis and fuel flow procedures in appendix D of this part, to 
determine SO2 mass emissions pursuant to Sec. 75.11(e), the owner 
or operator shall substitute for missing data using the missing data 
procedures in appendix D of this part.
    (3) The owner or operator shall not use historical data from an 
SO2 pollutant concentration monitor to account for SO2 
emissions due to combustion of gas during missing data periods. In 
addition, the owner or operator shall not include hours when the unit 
combusts only natural gas (or a gaseous fuel with sulfur content no 
greater than that of natural gas) in the availability calculations in 
Sec. 75.32, nor in the calculations of substitute data using the 
procedures of either Sec. 75.31 or Sec. 75.33. For the purpose of the 
missing data and availability procedures for SO2 pollutant 
concentration monitors in Secs. 75.31 through 75.33 only, all hours 
during which the unit combusts only natural gas, or a

[[Page 246]]

gaseous fuel with a sulfur content no greater than natural gas, shall be 
excluded from the definition of ``monitor operating hour,'' ``quality-
assured monitor operating hour,'' ``unit operating hour,'' and ``unit 
operating day.''
    (e) On or after January 1, 1997, the owner or operator shall comply 
with the provisions of this paragraph. Prior to January 1, 1997, the 
owner or operator may comply with the provisions of this paragraph.
    (1) For monitoring of emissions at a unit with multiple stacks or a 
bypass stack, include only those hours when emissions are passing 
through the stack or duct in the definitions of ``unit operating hour'' 
and ``quality-assured monitor operating hour'' for purposes of applying 
the missing data and availability procedures in Secs. 75.31 through 
75.36 to the monitoring system on that stack or duct.
    (2) If the proportion of flow going to each stack from a unit with 
multiple stacks or the proportion of flow going to a bypass stack has 
changed during the previous 2,160 hours when emissions passed through 
that stack, then record the maximum flow rate recorded by the flow 
monitoring system at the corresponding load range during the previous 
2,160 hours of quality-assured monitor data when emissions passed 
through that stack, instead of the value calculated using the missing 
data substitution procedures in Sec. 75.31 or Sec. 75.33.

[60 FR 26528, 26566, May 17, 1995]

    Effective Date Note: At 60 FR 26560, 26566, May 17, 1995, 
Sec. 75.30(d) and (e) were temporarily added and are effective from July 
17, 1995 through December 31, 1996.



Sec. 75.31  Initial missing data procedures.

    (a) During the first 720 quality-assured monitor operating hours 
following initial certification (i.e., following the date and time of 
completion of successful certification tests), of the SO2 and 
CO2 (or O2) pollutant concentration monitor and during the 
first 2,160 quality-assured monitor operating hours following initial 
certification of the flow monitor and NOX continuous emission 
monitoring system(s), 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 or CO2 (or O2) concentration data. For each 
hour of missing SO2 or CO2 concentration data (including 
CO2 data converted from O2 data using the procedures in 
appendix F of this part) or O2 concentration data used to calculate 
heat input, 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, 
the average of the hourly SO2 or CO2 (or O2) 
concentrations recorded for an affected unit by a certified monitor for 
the unit operating hour immediately before and the unit operating hour 
immediately after the missing data period for each hour of missing data.
    (2) Whenever no prior quality-assured SO2 or CO2 (or 
O2) concentration data exist, the owner or operator shall 
substitute the maximum potential concentration for SO2 or CO2 
(or minimum O2 concentration, for determination of heat input), as 
specified in section 2.1 of appendix A of this part, for each hour of 
missing data.
    (c) Volumetric flow and NOx emission rate data. For each hour 
of missing volumetric flow or NOx emission rate data;
    (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, the average hourly flow 
rate (or NOx emission rate) recorded for the affected unit by a 
certified flow monitor (or a certified NOx continuous emission 
monitoring system). The flow rate (or NOx emission rate) shall be 
calculated from the corresponding load range as determined using the 
procedure in appendix C of this part.
    (2) Whenever no prior quality-assured flow or NOx emission rate 
data exist for the corresponding load range, the owner or operator shall 
substitute the average hourly flow rate or the average

[[Page 247]]

hourly NOx emission rate at the next higher level load range for 
which quality-assured data is available, for each hour of missing data.
    (3) Whenever no prior quality-assured flow or NOX emission rate 
data exist for the corresponding load range, or any higher load range, 
the owner or operator shall calculate and substitute the maximum 
potential flow rate or shall substitute the maximum potential NOX 
emission rate, as specified in Sec. 72.2 of this chapter and section 2.1 
of appendix A, for each hour of missing data.

[58 FR 3701, Jan. 11, 1993, as amended at 60 FR 26529, May 17, 1995]



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

    (a) Following initial certification, upon completion of the first 
720 quality-assured monitor operating hours of the SO2 or CO2 
(or O2) pollutant concentration monitor or the first 2,160 quality-
assured monitor operating hours of the flow monitor or NOX 
continuous emission 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 
and CO2 (or O2) pollutant concentration monitor, the flow 
monitor, the NOX continuous emission monitoring system as follows:
    (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] TC01SE92.098

    (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] TC01SE92.099

    (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 backup monitor, a certified 
portable 
monitor, and a reference method for that unit, and from an approved 
alternative monitoring system under subpart E of this part when 
calculating percent monitor data availability using Equation 8 or 9. The 
provisions in 

[[Page 248]]

this paragraph (a)(3) are suspended from July 17, 1995, through December 
31, 1996.
    (4) 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, a reference method for that unit, and from an 
approved alternative monitoring system under subpart E of this part when 
calculating percent monitor data availability using Equation 8 or 9. The 
owner or operator shall exclude hours when a unit combusted only natural 
gas (or gaseous fuel with the same sulfur content as natural gas) from 
calculations of percent monitor data availability for SO2 pollutant 
concentration monitors, as provided in Sec. 75.30(d). No hours from more 
than three years (26,280 clock hours) earlier shall be used in Equation 
8 or 9. When three years from certification have elapsed, replace the 
words ``since certification'' or ``during previous 8,760 unit operating 
hours'' with ``in the previous three years'' and replace ``8,760'' with 
``total unit operating hours in the previous three years.''
    (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]

    Effective Date Notes: 1. At 60 FR 26560, May 17, 1995, 
Sec. 75.32(a)(3) was temporarily suspended, effective July 17, 1995 
through December 31, 1996.

    2. At 60 FR 26560, May 17, 1995, Sec. 75.32(a)(4) was temporarily 
added and is effective from July 17, 1995 through December 31, 1996.



Sec. 75.33  Standard missing data procedures.

    (a) Following initial certification 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 or NOx continuous emission 
monitoring system, the owner or operator shall provide substitute data 
required under this subpart according to the procedures in paragraphs 
(b) and (c) of this section and depicted in Table 1 (SOx) and Table 
2 (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.

                                  Table 1.--Missing Data Procedure for SO2 CEMS                                 
----------------------------------------------------------------------------------------------------------------
                 Trigger conditions                                      Calculation routines                   
----------------------------------------------------------------------------------------------------------------
                                  Duration (N) of                                                               
    Availability (percent)         outage (hours)                 Method                   Lookback period      
----------------------------------------------------------------------------------------------------------------
95 or more...................  N24.......  Average......................  HB/HA.                     
                               N>24.................  Max. of average..............  HB/HA.                     
                               .....................  Max. of 90th percentile......  720 operating hours *.     
90 or more, but below 95.....  N8........  Average......................  HB/HA.                     
                               N>8..................  Max. of average..............  HB/HA.                     
                               .....................  Max. of 95th percentile......  720 operating hours *.     
Below 90.....................  N >0.................  Maximum value \1\............  720 operating hours *.     
----------------------------------------------------------------------------------------------------------------
HB/HA=hour before and hour after the outage.                                                                    
* =Quality-assured, monitor operating hours.                                                                    
\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.                                                                                 



                             Table 2.--Missing Data Procedure for NOx and Flow CEMS                             
----------------------------------------------------------------------------------------------------------------
               Trigger conditions                                      Calculation routines                     
----------------------------------------------------------------------------------------------------------------
                                Duration (N) of                                                           Load  
    Availability (percent)       outage (hours)             Method                Lookback period        ranges 
----------------------------------------------------------------------------------------------------------------
95 or more...................  N  24.  Average..................  2160 operating hours*...  Yes.     
                               N > 24...........  Max of average...........  HB/HA...................  No.      
                                 ...............  Max of 90th percentile...  2160 operating hours*...  Yes.     

[[Page 249]]

                                                                                                                
90 or more, but below 95.....   N  8.  Average..................  2160 operating hours*...  Yes.     
                               N > 8............  Max of Average...........   HB/HA..................  No.      
                                 ...............  Max of 95th percentile...  2160 operating hours*...  Yes.     
Below 90.....................  N > 0............  Maximum Value1...........  2160 operating hours*...  Yes.     
----------------------------------------------------------------------------------------------------------------
HB/HA = hour before and hour after the outage.                                                                  
* = Quality-assured, monitor operating hours.                                                                   
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.                                                                                              

    (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 less than 90.0 
percent, the owner or operator shall substitute for each hour of 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.
    (c) Volumetric flow and NOx emission rate data. For each hour 
of missing volumetric flow or NOx emission rate data:
    (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 the average hourly flow or NOx emission rate recorded by 
a flow monitor or NOx continuous emission monitoring system during 
the previous 2,160 quality-assured monitor operating hours at the 
corresponding unit load range recorded for each missing hour, as 
determined using the procedure in appendix C to this part.

[[Page 250]]

    (ii) For a missing data period greater than 24 hours, substitute the 
greater of:
    (A) The 90th percentile hourly flow or NOx emission rate 
recorded by a flow monitor or NOx continuous emission monitoring 
system at the corresponding unit load range recorded for each missing 
hour during the previous 2,160 quality-assured monitor operating hours, 
as determined using the procedure in appendix C to this part; or
    (B) The average of the hourly flow or NOx emission rate 
recorded by a flow monitor or NOx continuous emission monitoring 
system for the hour before and the hour after the missing data period.
    (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 the average hourly flow or NOx emission rate recorded by 
a flow monitor or NOx continuous emission monitoring system at the 
corresponding unit load range recorded for the missing hour during the 
previous 2,160 quality-assured monitor operating hours, as determined 
using the procedure in appendix C to this part.
    (ii) For a missing data period greater than 8 hours, substitute the 
greater of:
    (A) The 95th percentile hourly flow or NOx emission rate 
recorded by a flow monitor or NOx continuous emission monitoring 
system at the corresponding unit load range recorded for the missing 
hour during the previous 2,160 quality-assured monitor operating hours, 
as determined using the procedure in appendix C to this part; or
    (B) The average of the hourly flow or NOx emission rate 
recorded by a flow monitor or NOx continuous emission monitoring 
system for the hour before and the hour after the missing data period.
    (3) Whenever the monitor data availability is less than 90.0 
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 by substituting the maximum hourly flow or 
NOx emission rate recorded by the flow monitor or NOx 
continuous emission monitoring system at the corresponding unit load 
range recorded for the missing hour during the previous 2,160 quality-
assured monitor operating hours, as determined using the procedure in 
section 2 of appendix C to this part.
    (4) Whenever no prior quality-assured flow or NOx emission rate 
data exist for the corresponding load range, the owner or operator shall 
substitute the maximum hourly flow rate or the maximum hourly NOx 
emission rate at the next higher level load range for which quality-
assured data is available for each hour of missing data.
    (5) Whenever no prior quality-assured flow or NOX emission rate 
data exist for either the corresponding load range or a higher load 
range, the owner or operator shall substitute the maximum potential 
NOX emission rate or the maximum potential flow rate, as defined in 
section 2.1 of appendix A of this part.

[58 FR 3701, Jan. 11, 1993, as amended at 60 FR 26529, May 17, 1995; 61 
FR 25582, May 22, 1996]



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 at least one of the 
following options:
    (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 for substituting data for each hour where the add-on emission 
controls are operating within the proper operation range specified in 
the monitoring plan for the unit. The designated representative shall 
report the range of add-on emission control operating parameters that 
indicate proper operation in the unit's monitoring plan and the owner or 
operator shall 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

[[Page 251]]

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) In addition, 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 monitoring plan) 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 and NOX emission rate data in accordance 
with the requirements of paragraphs (b) and (c) of this section, and 
appendix C of this part. The owner or operator shall record the data 
required in appendix C of this part, pursuant to Sec. 75.51(b) until 
January 1, 1996, or pursuant to Sec. 75.55(b).
    (b) For an affected unit equipped with add-on SO2 emission 
controls, the designated representative may petition the Administrator 
to approve a parametric monitoring procedure, as described in appendix C 
of this part, for calculating substitute SO2 concentration data for 
missing data periods. The owner or operator shall use the procedures in 
Sec. 75.31, Sec. 75.33, or Sec. 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 monitoring 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 Sec. 75.33 for providing substitute data for missing 
NOX emission rate data prior to receiving the Administrator's 
approval for a parametric monitoring procedure.
    (1) Where monitor data availability for a NOX continuous 
emission monitoring system is 90.0 percent or more, the owner or 
operator may calculate substitute data using an approved parametric 
monitoring procedure.
    (2) Where monitor data availability for a NOX continuous 
emission monitoring system is less than 90.0 percent, the owner or 
operator shall calculate substitute data using the procedure in 
Sec. 75.34(a) (1) or (2), even if the Administrator has approved a 
parametric monitoring procedure.
    (d) 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 missing 
data. The owner or operator shall provide these records to the 
Administrator or to the EPA Regional Office upon request. Whenever such 
records are not provided or such records do not demonstrate that 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 monitoring plan 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

[[Page 252]]

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]



Sec. 75.35  Missing data procedures for CO2 data.

    (a) On or after January 1, 1996, the owner or operator of a unit 
with a CO2 continuous emission monitoring system shall substitute 
for missing CO2 concentration data using the procedures of this 
section. Prior to January 1, 1996, the owner or operator of a unit with 
a CO2 continuous emission monitoring system may substitute for 
missing CO2 concentration data using the procedures of this 
section.
    (b) During the first 720 quality-assured monitor operating hours 
following initial certification (i.e., following the date and time of 
completion of successful certification tests), of the CO2 
continuous emission monitoring system, the owner or operator shall 
provide substitute data required under this subpart according to the 
procedures in paragraph (b) of Sec. 75.31.
    (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 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.

[60 FR 26529, May 17, 1995]



Sec. 75.36  Missing data procedures for heat input.

    (a) On or after January 1, 1996, the owner or operator of a unit 
monitoring heat input with a CO2 or O2 pollutant concentration 
monitor and a flow monitoring system shall substitute for missing heat 
input data using the procedures of this section. Prior to January 1, 
1996, the owner or operator of a unit monitoring heat input with a 
CO2 or O2 pollutant concentration monitor and a flow 
monitoring system may substitute for missing heat input data using the 
procedures of this section.
    (b) During the first 720 quality-assured monitor operating hours 
following initial certification (i.e., following the date and time of 
completion of successful certification tests), of the CO2 or 
O2 pollutant concentration monitor

[[Page 253]]

and during the first 2,160 quality-assured monitoring operating hours 
following initial certification of the flow monitor, the owner or 
operator shall provide substitute data for heat input calculated under 
section 5.2 of appendix F of this part by substituting the CO2 or 
O2 concentration measured or substituted according to paragraph (b) 
of Sec. 75.31, and by substituting the flow rate measured or substituted 
according to Sec. 75.31.
    (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 
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) For a unit that has no diluent monitor certified during the 
period between the certification deadline in Sec. 75.4(a) for flow 
monitoring systems and the certification deadline in Sec. 75.4(a) for 
NOX and CO2 continuous emission monitoring systems, the owner 
or operator shall calculate heat input using the procedures in section 
5.5 of appendix F of this part until quality-assured data are available 
from both a flow monitor and a diluent monitor.

[60 FR 26530, May 17, 1995]



                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

[[Page 254]]

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 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.

[[Page 255]]

    (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:

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 

[[Page 256]]

(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
    [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 

[[Page 257]]

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:
[GRAPHIC] [TIFF OMITTED] TC01SE92.109

where.

[[Page 258]]

[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 
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)

[[Page 259]]

[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.



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 

[[Page 260]]

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.
    (iii) Hourly test data for the continuous emissions monitoring 
system at each required operating level and fuel type.
    (iv) Arithmetic mean of the alternative monitoring system 
measurement values, as specified in Equation 24 in Sec. 75.41(c) of this 
part, of the continuous emission monitoring system values, as specified 
on Equation 25 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 
emissions monitoring system, as specified in Equation 22 in 
Sec. 75.41(c) of this part.
    (ix) F-statistic, as specified in Equation 23 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 26 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.
    (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]

[[Page 261]]



                  Subpart F--Recordkeeping Requirements



Sec. 75.50   General recordkeeping provisions.

    (a) Recordkeeping requirements for affected sources. The provisions 
of this section shall remain in effect prior to January 1, 1996. The 
owner or operator shall meet the requirements of either Secs. 75.50 or 
75.54 prior to January 1, 1996. On or after January 1, 1996, the owner 
or operator shall meet the requirements of Sec. 75.54 only. The owner or 
operator of any affected source subject to the requirements of this part 
shall maintain for each affected unit (or for each group of affected or 
nonaffected units utilizing a common stack and common monitoring systems 
pursuant to Sec. 75.16 through Sec. 75.18 of this part (referred to 
hereafter as ``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. This file shall contain the following information:
    (1) The data and information required in paragraphs (b) through (f) 
of this section;
    (2) The component data and information used to calculate values 
required in paragraphs (b) through (f) of this section;
    (3) The current monitoring plan as specified in Sec. 75.53 of this 
part; and
    (4) The quality control plan as described in Appendix B of this 
part.
    (b) Operating parameter record provisions. The owner or operator 
shall record hourly the following information on unit operating time, 
heat input, and load for each affected unit, including individual 
affected units utilizing a common stack except as provided in paragraph 
(b)(6) of this section for when units combust gas:
    (1) Date and hour;
    (2) Unit operating time (rounded to nearest hour);
    (3) Total integrated hourly gross unit load (rounded to nearest 
MWge) (or steam load in lb/hr at stated temperature and pressure, 
rounded to the nearest   lb/hr, if elected in the monitoring plan);
    (4) Operating load range corresponding to total integrated gross 
load of 1-10, except for units using a common stack, which may use the 
number of unit load ranges up to 20, specified in the monitoring plan 
for the common stack;
    (5) Total heat input (mmBtu, rounded to the nearest tenth); and
    (6) For when units combust gas, the owner or operator may record 
total heat input (mmBtu, rounded to the nearest tenth) daily.
    (c) SO2 emission record provisions. The owner or operator shall 
record hourly the information required by this paragraph for each 
affected unit or group of units using a common stack and common 
monitoring systems, except 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 the 
certified primary monitor, certified back-up or certified portable 
monitor, or other approved method of emissions determination:
    (i) Monitor-channel 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) of this part;
    (v) Percent monitor data availability (recorded to the nearest tenth 
of a percent) calculated pursuant to Sec. 75.32 of this part; and
    (vi) Method of determination for hourly average SO2 
concentration using Codes 1-13 in Table 3 of this section.
    (2) For flow as measured and reported from the certified primary 
monitor, certified back-up or certified portable monitor or other 
approved method of emissions determination:
    (i) Monitor-channel 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);

[[Page 262]]

    (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) of this part;
    (v) Hourly average moisture content of flue gases (volume fraction) 
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 of this part; and
    (vii) Method of determination for hourly average flow rate using 
Codes 1-13 in Table 3.
    (3) For SO2 mass emissions as measured and reported from the 
certified primary monitoring system, certified back-up or certified 
portable monitoring systems, or other approved method of emissions 
determination:
    (i) Date and hour;
    (ii) Hourly average SO2 mass emissions (lb/hr, rounded to the 
nearest tenth);
    (iii) Hourly average 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) Unique three-digit code identifying 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 3.--Codes for Method of Emissions and Flow Determination     
------------------------------------------------------------------------
 Code        Hourly emissions/flow measurement or estimation method     
------------------------------------------------------------------------
1....  Certified primary emission/flow monitoring system.               
2....  Certified back-up or certified portable emission/flow monitoring 
        system.                                                         
3....  Approved alternative monitoring system.                          
4....  Reference Method:                                                
       SO2: Method 6, 6A, 6B, or 6C.                                    
       Flow: Method 2, 2A, 2C, or 2D.                                   
       NOx: Method 7, 7A, 7C, 7D, or 7E.                                
       CO2 or O2: Method 3, 3A or 3B.                                   
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, flow, or NOx emission  
        rate for the hour before and the hour following a missing data  
        period.                                                         
7....  Average hourly SO2 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...  Average hourly flow rate or NOx emission rate in corresponding   
        load range.                                                     
12...  Maximum potential concentration of SO2 maximum potential flow    
        rate, or NOx emission rate corresponding to maximum potential   
        concentration of NOx and minimum O2 or maximum CO2              
        concentration, as determined using section 2.1 of appendix A of 
        this part.                                                      
13...  Other data (specify method).                                     
------------------------------------------------------------------------


    (d) NOx emission record provisions. The owner or operator shall 
record hourly the information required by this paragraph for each 
affected unit, 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 or certified portable monitor, or 
other approved method of emissions determination:
    (1) Monitor-channel 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);
    (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) of this part;
    (7) Percent monitoring system data availability (recorded to the 
nearest tenth of a percent), calculated pursuant to Sec. 75.32 of this 
part;
    (8) Method of determination for hourly average NOx emission 
rate using Codes 1-13 in Table 3; and
    (9) Unique three-digit code identifying emissions formula used to 
derive hourly average NOx emission rate, as provided for in 
Sec. 75.53.

[[Page 263]]

    (e) CO2 emission 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 (or an O2 continuous emission monitor 
and flow monitor as specified in appendix F), then the owner or operator 
shall record hourly the following information for CO2 mass 
emissions, as measured and reported from the certified primary monitor, 
certified back-up or certified portable monitor, or other approved 
method of emissions determination:
    (i) Monitor-channel identification code as provided for in 
Sec. 75.53;
    (ii) Date and hour;
    (iii) Hourly average CO2 (or O2) concentration (in 
percent, rounded to the nearest tenth);
    (iv) Hourly average volumetric flow rate (scfh, rounded to the 
nearest scf);
    (v) Hourly average 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 of this part;
    (vii) Method of determination for hourly average CO2 mass 
emissions using Codes 1-13 in Table 3; and
    (viii) Unique three-digit emissions formula used to derive hourly 
average CO2 mass emissions, as provided for in Sec. 75.53.
    (2) As an alternative to Sec. 75.50(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 record provisions. The owner or operator shall record 
every six minutes (or other averaging period specified by the State or 
local air pollution control agency) the information required by this 
paragraph 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) Monitor-channel identification code;
    (2) Date, hour, and minute;
    (3) Average opacity of emissions (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 pursuant to Sec. 75.32 of this part.

[58 FR 3701, Jan. 11, 1993, as amended at 58 FR 34126, June 23, 1993; 58 
FR 40749, July 30, 1993; 61 FR 25582, May 22, 1996]



Sec. 75.51  General recordkeeping provisions for specific situations.

    (a) Specific SO2 emission record provisions for units with 
qualifying Phase I technology. In addition to the SO2 emissions 
information required in Sec. 75.50(c) of this part, 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.

[[Page 264]]

    (1) For units with post-combustion emission controls:
    (i) Monitor-channel 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 inlet SO2 concentration (ppm, rounded to 
the nearest tenth) adjusted for bias, if bias adjustment factor required 
(see Sec. 75.24(d) of this part);
    (v) Hourly average outlet SO2 emission rate (lb/mmBtu, rounded 
to nearest hundredth);
    (vi) Hourly average outlet SO2 concentration (ppm, rounded to 
the nearest tenth) adjusted for bias, if bias adjustment factor required 
(see Sec. 75.24(d) of this part);
    (vii) 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
    (viii) Emissions formula used to derive hourly average inlet and 
outlet SO2 emission 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) Monitor-channel 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 appendix F to 
this part; 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 
addition to the SO2 and NOx emissions data to be recorded 
under Sec. 75.50, the owner or operator of an affected unit with add-on 
emission controls, where the owner or operator is using the approved 
site-specific parametric monitoring procedures for calculation of 
substitute data in accordance with Sec. 75.34, shall also record for 
each hour during each missing data period the applicable information in 
this paragraph (b):
    (1) For units with add-on SO2 emission controls, for each hour 
of missing SO2 concentration or volumetric flow data:
    (i) The information required in Sec. 75.50(b) of this part 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) Feedrate of makeup slurry to each operating scrubber module 
(gal/min);
    (v) Average 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 outlet temperatures across each operating scrubber module;
    (viii) For a unit with a dry flue gas desulfurization system, the 
slurry feed rate (gal/min) to the atomizer nozzle; and
    (ix) Method of determination of SO2 concentration and 
volumetric flow, using Codes 1-13 in Table 3 of Sec. 75.50 of this part.
    (2) For units with add-on NOx emission controls, 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 
(rounded to nearest tenth of a percent);
    (iv) CO concentration of flue gas at stack outlet (ppm, rounded to 
the nearest tenth);

[[Page 265]]

    (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).
    (c) Specific SO2 emission record provisions for gas-fired or 
oil-fired units using optional protocol in appendix D to this part. In 
lieu of recording the information in Sec. 75.50(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 to this 
part for estimating SO2 mass emissions.
    (1) When the unit is combusting oil:
    (i) Date and hour;
    (ii) Hourly flow rate of oil with the units in which oil flow is 
recorded, (gal/hr, lb/hr, or bbl/hr, rounded to the nearest tenth);
    (iii) Sulfur content of daily oil sample, rounded to nearest tenth 
of a percent;
    (iv) Method of oil sampling (flow proportional, continuous drip, or 
manual);
    (v) Mass of oil combusted each hour (lb/hr, rounded to the nearest 
tenth); and
    (vi) Hourly SO2 mass emissions (lb/hr, rounded to the nearest 
tenth).
    (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) When the unit is combusting natural gas:
    (i) Date and hour;
    (ii) Daily heat input from natural gas according to procedures in 
appendix F to this part (mmBtu, 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 daily gas sample, (rounded to the nearest 0.1 
grains/100 scf) and the volume of gas combusted per day, in 100 scf; or
    (B) SO2 emission rate from NADB (in lb/mmBtu).
    (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. 75.50(d), the owner or operator shall record the 
applicable information in this paragraph for each affected gas-fired 
peaking unit or oil-fired peaking unit for which the owner or operator 
is using the optional protocol in appendix E to this part for estimating 
NOx emission rate.
    (1) When the unit is combusting oil:
    (i) Date and hour;
    (ii) Average hourly fuel flow of oil with the units in which oil 
flow is recorded (gal/hour or bbl/hour);
    (iii) NOx emission rate F-factor for oil combusted according to 
procedure in appendix E to this part; and
    (iv) Average hourly NOx emission rate (lb/mmBtu, rounded to 
nearest tenth).
    (2) When the unit is combusting natural gas:
    (i) Date and hour;
    (ii) Average daily fuel flow of natural gas (million cubic ft);
    (iii) NOx emission rate F-factor for gas combusted according to 
procedure in appendix E to this part; and
    (iv) Average daily NOx emission rate (lb/mmBtu, rounded to 
nearest tenth).

[58 FR 3701, Jan. 11, 1993, as amended at 58 FR 40749, July 30, 1993]



Sec. 75.52  Certification, quality assurance and quality control record provisions.

    (a) The owner or operator shall record the applicable information in 
this section for each certified monitor or certified monitoring system 
(including certified backup or certified portable 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) Monitor-channel identification code;
    (ii) Instrument span;
    (iii) Date and hour;

[[Page 266]]

    (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);
    (vii) Number of out-of-control hours, if any, following test; 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;
    (ii) Number of out-of-control hours, if any, following test; and
    (iii) 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) Monitor-channel 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);
    (vii) Number of out-of-control hours, if any, following test; and
    (viii) 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;
    (ii) Number of out-of-control hours, if any, following test; and
    (iii) 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) Monitor-channel 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, of 
the reference method values, and of their differences, as specified in 
Equation   A-7 in appendix A to this part.
    (B) Standard deviation, as specified in Equation A-8 in appendix A 
to this part.
    (C) Confidence coefficient, as specified in Equation A-9 in appendix 
A to this part.
    (D) Relative accuracy test results, as specified in Equation A-10 in 
appendix A to this part. (For the 3-level flow

[[Page 267]]

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 integrated gross unit load, rounded to the 
nearest MWe.)
    (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) Number of out-of-control hours, if any, following test.
    (vi) Description of any adjustment, corrective action, or 
maintenance following test.
    (6) 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.
    (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.
    (b) [Reserved]

[58 FR 3701, Jan. 11, 1993, as amended at 58 FR 40749, July 30, 1993]



Sec. 75.53  Monitoring plan.

    (a) General provisions. The owner or operator of an affected unit 
shall prepare and maintain a monitoring plan. Except as provided in 
paragraph (d) of this section, a monitoring plan shall contain 
sufficient information on the continuous emission or opacity monitoring 
systems or excepted monitoring systems under appendix D or E of 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, either in the certified continuous emission 
monitoring system or continuous opacity monitoring system or excepted 
monitoring systems under appendix D or E of this part, including a 
change in the automated data acquisition and handling system or in the 
flue gas handling system, that requires recertification, 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. 75.13 through 75.17 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.
    (4) Monitoring component table. Identification and description of 
each monitoring component (including each

[[Page 268]]

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), maximum potential flow rate, maximum potential NOX 
emission rate, span value, and full-scale range for each SO2, 
NOX, CO2, O2, or flow component

[[Page 269]]

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 or for units with add-on emission 
controls:
    (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.
    (4) For each unit with add-on emission controls:
    (i) A list of operating parameters for the add-on emission controls, 
including parameters from the list in Sec. 75.55 appropriate to the 
particular installation; and
    (ii) The range of each operating parameter in the list that 
indicates the add-on emission controls are properly operating.

[58 FR 3701, Jan. 11, 1993, as amended at 60 FR 26532, 26568, May 17, 
1995]



Sec. 75.54  General recordkeeping provisions.

    (a) Recordkeeping requirements for affected sources. On or after 
January 1, 1996, the owner or operator shall meet the requirements of 
this section. 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. 75.13 
through 75.18, or utilizing a common pipe header and common fuel 
flowmeter, pursuant to section 2.1.2 of appendix D of this part. The 
file shall contain the following information:
    (1) The data and information required in paragraphs (b) through (f) 
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

[[Page 270]]

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, 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:

[[Page 271]]

    (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);
    (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) CO2 emission 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);

[[Page 272]]

    (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.

[60 FR 26533, May 17, 1995]



Sec. 75.55  General recordkeeping provisions for specific situations.

    (a) Specific SO2 emission 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

[[Page 273]]

    (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(b) 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 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 3 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 3 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.

[[Page 274]]

    (3) For units with add-on SO2 or NOX emission controls 
following the provisions of Sec. 75.34(a) (1) or (2), for each hour of 
missing data record:
    (i) Parametric data which demonstrate the proper operation of the 
add-on emission controls, as described in the monitoring plan for the 
unit (to be maintained on site, and to be submitted upon request from 
the Administrator or by an EPA Regional office);
    (ii) A flag indicating that the add-on emission controls are 
operating with all parameters within the ranges specified in the 
monitoring plan 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);
    (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

[[Page 275]]

    (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
    (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. In accordance with the provisions in 
Sec. 75.11(e), the owner or operator of a unit with an SO2 
continuous emission monitoring system may record the information in 
paragraph (c)(3) of this

[[Page 276]]

section in lieu of the information in Secs. 75.54(c)(1) and 75.54(c)(3), 
for those hours when only pipeline natural gas or a gaseous fuel with a 
sulfur content no greater than natural gas is combusted.
    (f) The owner or operator shall meet the requirements of this 
section on or after January 1, 1996.

[60 FR 26535, 26568, May 17, 1995]

    Effective Date Note: At 60 FR 26560, 26569, May 17, 1995, Sec. 75.55 
was amended by temporarily adding paragraph (e), effective July 17, 1995 
through December 31, 1996.



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

    (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;
    (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,

[[Page 277]]

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 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.
    (6) For each SO2, NOX, CO2, or O2 pollutant 
concentration monitor, NOx-diluent continuous emission monitoring 
system, or SO2-diluent continuous emission monitoring system, the 
owner or operator shall record the following information for the cycle 
time test:
    (i) Component/system identification code;
    (ii) Date;
    (iii) Start and end times;
    (iv) Upscale and downscale cycle times for each component;
    (v) Stable start monitor value;
    (vi) Stable end monitor value;
    (vii) Reference value of calibration gas(es);
    (viii) Calibration gas level; and
    (ix) Cycle time result for the entire system.
    (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 H2O;
    (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

[[Page 278]]

    (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);
    (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);

[[Page 279]]

    (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 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) The owner or operator shall meet the requirements of this 
section on or after January 1, 1996.

[60 FR 26536, 26568, May 17, 1995]

    Effective Date Note: At 60 FR 26560, 26569, May 17, 1995, Sec. 75.56 
was amended by temporarily adding paragraph (a)(6), effective July 17, 
1995 through December 31, 1996.



                    Subpart G--Reporting Requirements



Sec. 75.60  General provisions.

    (a) The designated representative for any affected unit subject to 
the requirements of this part shall comply with all reporting 
requirements in this section and with the signatory requirements of 
Sec. 72.21 of this chapter for all submissions.
    (b) Submissions. The designated representative shall submit all 
reports and petitions (except as provided in Sec. 75.61) as follows:
    (1) All initial certification or recertification testing 
notifications, initial certification or recertification applications, 
monitoring plans, petitions for alternative monitoring systems, 
notifications, electronic quarterly reports, and other communications 
required by this subpart shall be submitted to the Administrator.
    (2) Copies of initial certification or recertification testing 
notifications, certification or recertification applications and 
monitoring plans shall be submitted to the appropriate Regional office 
of the U.S. Environmental Protection Agency and appropriate State or 
local air pollution control agency.
    (c) Confidentiality of data. The following provisions shall govern 
the confidentiality of information submitted under this part.
    (1) All emission data reported in quarterly reports under Sec. 75.64 
shall remain public information.
    (2) For information submitted under this part other than emission 
data submitted in quarterly reports, the designated representative must 
assert a claim of confidentiality at the time of submission for any 
information he or she wishes to have treated as confidential business 
information (CBI) under subpart B of part 2 of this chapter. Failure to 
assert a claim of confidentiality at the time of submission may result 
in disclosure of the information by EPA without further notice to the 
designated representative.
    (3) Any claim of confidentiality for information submitted in 
quarterly reports under Sec. 75.64 must include substantiation of the 
claim. Failure to provide substantiation may result in

[[Page 280]]

disclosure of the information by EPA without further notice.
    (4) As provided under subpart B of part 2 of this chapter, EPA may 
review information submitted to determine whether it is entitled to 
confidential treatment even when confidentiality claims are initially 
received. The EPA will contact the designated representative as part of 
such a review process.

[58 FR 3701, Jan. 11, 1993, as amended at 60 FR 26538, May 17, 1995]



Sec. 75.61  Notifications.

    (a) Submission. The designated representative for an affected unit 
(or owner or operator, as specified) shall submit notice to the 
Administrator, to the appropriate EPA Regional Office, and to the 
applicable State air pollution control agency for the following 
purposes, as required by this part.
    (1) Initial certification and recertification test notifications. 
The owner or operator or designated representative for an affected unit 
shall submit written notification of initial certification tests, 
recertification tests, and revised test dates as specified in Sec. 75.20 
for continuous emission monitoring systems, for alternative monitoring 
systems under subpart E of this part, or for excepted monitoring systems 
under appendix E of this part, except as provided in paragraph (a)(4) of 
this section and except for testing only of the data acquisition and 
handling system.
    (i) Notification of initial certification testing. Initial 
certification test notifications shall be submitted not later than 45 
days prior to the first scheduled day of initial certification testing. 
Testing may be performed on a date other than that already provided in a 
notice under this subparagraph as long as notice of the new date is 
provided either in writing or by telephone or other means at least 7 
days prior to the original scheduled test date or the revised test date, 
whichever is earlier.
    (ii) Notification of certification retesting and recertification 
testing. For retesting following a loss of certification under 
Sec. 75.20(a)(5) or for recertification under Sec. 75.20(b), notice of 
testing shall be submitted either in writing or by telephone at least 7 
days prior to the first scheduled day of testing; except that in 
emergency situations when testing is required following an 
uncontrollable failure of equipment that results in lost data, notice 
shall be sufficient if provided within 2 business days following the 
date when testing is scheduled. Testing may be performed on a date other 
than that already provided in a notice under this subparagraph as long 
as notice of the new date is provided by telephone or other means at 
least 2 business days prior to the original scheduled test date or the 
revised test date, whichever is earlier.
    (iii) Repeat of testing without notice. Notwithstanding the above 
notice requirements, the owner or operator may elect to repeat a 
certification test immediately, without advance notification, whenever 
the owner or operator has determined during the certification testing 
that a test was failed or that a second test is necessary in order to 
attain a reduced relative accuracy test frequency.
    (2) New unit, newly affected unit, new stack, or new flue gas 
desulfurization system operation notification. The designated 
representative for an affected unit shall submit written notification: 
For a new unit or a newly affected unit, of the planned date when a new 
unit or newly affected unit will commence commercial operation or, for 
new stack or flue gas desulfurization system, of the planned date when a 
new stack or flue gas desulfurization system will be completed and 
emissions will first exit to the atmosphere.
    (i) Notification of the planned date shall be submitted not later 
than 45 days prior to the date the unit commences commercial operation, 
or not later than 45 days prior to the date when a new stack or flue gas 
desulfurization system exhausts emissions to the atmosphere.
    (ii) If the date when the unit commences commercial operation or the 
date when the new stack or flue gas desulfurization system exhausts 
emissions to the atmosphere, whichever is applicable, changes from the 
planned date, a notification of the actual date shall be submitted not 
later than 7 days following: The date the unit commences commercial 
operation or, the date when a new stack or flue gas desulfurization 
system exhausts emissions to the atmosphere.

[[Page 281]]

    (3) Unit shutdown and recommencement of commercial operation. The 
designated representative for an affected unit that will be shutdown on 
the relevant compliance date in Sec. 75.4(a) and that is relying on the 
provisions in Sec. 75.4(d) to postpone certification testing shall 
submit notification of unit shutdown and recommencement of commercial 
operation as follows:
    (i) For planned unit shutdowns, written notification of the planned 
shutdown date and planned date of recommencement of commercial operation 
shall be submitted 45 calendar days prior to the deadline in 
Sec. 75.4(a). For unit shutdowns that are not planned 45 days prior to 
the deadline in Sec. 75.4(a), written notification of the planned 
shutdown date and planned date of recommencement of commercial operation 
shall be submitted no later than 7 days after the date the owner or 
operator is able to schedule the shutdown date and date of 
recommencement of commercial operation. If the actual shutdown date or 
the actual date of recommencement of commercial operation differs from 
the planned date, written notice of the actual date shall be submitted 
no later than 7 days following the actual date of shutdown or of 
recommencement of commercial operation, as applicable;
    (ii) For unplanned unit shutdowns, written notification of actual 
shutdown date and the expected date of recommencement of commercial 
operation shall be submitted no later than 7 days after the shutdown. If 
the actual date of recommencement of commercial operation differs from 
the expected date, written notice of the actual date shall be submitted 
no later than 7 days following the actual date of recommencement of 
commercial operation.
    (4) Use of backup fuels for appendix E procedures. The designated 
representative for an affected oil-fired or gas-fired peaking unit that 
is using an excepted monitoring system under appendix E of this part and 
that is relying on the provisions in Sec. 75.4(f) to postpone testing of 
a fuel shall submit written notification of that fact no later than 45 
days prior to the deadline in Sec. 75.4(a). The designated 
representative shall also submit a notification that such a fuel has 
been combusted no later than 7 days after the first date of combustion 
of any fuel for which testing has not been performed under appendix E 
after the deadline in Sec. 75.4(a). Such notice shall also include 
notice that testing under Appendix E either was performed during the 
initial combustion or notice of the date that testing will be performed.
    (5) [Reserved]
    (6) Notice of combustion of emergency fuel under appendix D or E. 
The designated representative of an oil-fired unit or gas-fired unit 
using appendix D or E of this part shall provide notice of the 
combustion of emergency fuel according to the following:
    (i) For an affected oil-fired or gas-fired unit that is using an 
excepted monitoring system under appendix D or E of this part, where the 
owner or operator is postponing installation or testing of a fuel 
flowmeter for emergency fuel under Sec. 75.4(g), the designated 
representative shall submit written notification of postponement of 
installation or testing no later than 45 days prior to the deadline in 
Sec. 75.4(a). The designated representative shall also submit a 
notification that emergency fuel has been combusted no later than 7 days 
after the first date of combustion of the emergency fuel after the 
deadline in Sec. 75.4(a).
    (ii) The designated representative of a unit that has received 
approval of a petition under Sec. 75.66 for exemption from one or more 
of the requirements of appendix E of this part for certification of an 
excepted monitoring system under appendix E of this part for a unit 
combusting emergency fuel shall submit written notice of each period of 
combustion of the emergency fuel with the next quarterly report 
submitted under Sec. 75.64 for each calendar quarter in which emergency 
fuel is combusted, including notice specifying the exact dates and hours 
during which the emergency fuel was combusted.
    (b) The owner or operator or designated representative shall submit 
notification of certification tests and recertification tests for 
continuous opacity monitoring systems, as specified in Sec. 75.20(c)(6) 
to the State or local air pollution control agency.

[[Page 282]]

    (c) If the Administrator determines that notification substantially 
similar to that required in this section is required by any other State 
or local agency, the owner or operator or designated representative may 
send the Administrator a copy of that notification to satisfy the 
requirements of this section, provided the ORISPL unit identification 
number(s) is denoted.

[60 FR 26538, May 17, 1995, as amended at 61 FR 25582, May 22, 1996]



Sec. 75.62  Monitoring plan.

    (a) Submission. The designated representative for an affected unit 
shall submit the monitoring plan to the Administrator no later than 45 
days prior to the first scheduled certification test, other than testing 
of a fuel flowmeter or an excepted monitoring system under appendix D of 
this part. The designated representative shall submit the monitoring 
plan for a Phase II unit using an excepted monitoring system under 
appendix D of this part to the Administrator no later than November 15, 
1994.
    (b) Contents. Monitoring plans shall contain the information 
specified in Sec. 75.53 of this part.
    (c) Format. Each monitoring plan shall be submitted in a format 
specified by the Administrator, including information in electronic 
format and on paper.

[58 FR 3701, Jan. 11, 1993, as amended at 60 FR 26539, May 17, 1995]



Sec. 75.63  Initial certification or recertification application.

    (a) Submission. The designated representative for an affected unit 
or a combustion source seeking to enter the Opt-in Program in accordance 
with part 74 of this chapter shall submit the application to the 
Administrator within 45 days after completing all initial certification 
tests or recertification tests.
    (b) Contents. Each application for initial certification or 
recertification shall contain the following information:
    (1) A copy of the monitoring plan (or any modifications to the 
monitoring plan) for the unit, or units, or combustion sources seeking 
to enter the Opt-in Program in accordance with part 74 of this chapter, 
if not previously submitted.
    (2) The results of the test(s) required by Sec. 75.20, including the 
type of test conducted, testing date, and field data sheets required by 
Sec. 75.52 (or Sec. 75.56, no later than January 1, 1996), and including 
the results of any failed tests that had been repeated pursuant to the 
requirements in Sec. 75.20.
    (3) Results of the tests for verification of the accuracy of 
emissions and volumetric flow calculations performed by the automated 
data acquisition and handling system, including a summary of equations 
used to convert component data to units of the standard and to calculate 
substitute data for missing data periods, including sample calculations.
    (c) Format. Each certification application shall be submitted in a 
format to be specified by the Administrator, including test results in 
electronic format and field data sheets required by Sec. 75.52 (or 
Sec. 75.56, no later than January 1, 1996) on paper where the 
information required under Sec. 75.56(a)(7) shall be submitted on paper.

[60 FR 26539, May 17, 1995]



Sec. 75.64  Quarterly reports.

    (a) Electronic submission. The designated representative for an 
affected unit shall electronically report the data and information in 
paragraphs (a), (b), and (c) of this section to the Administrator 
quarterly, beginning with the data from the later of: the last (partial) 
calendar quarter of 1993 (where the calendar quarter data begins at 
November 15, 1993); or the calendar quarter corresponding to the 
relevant deadline for certification in Sec. 75.4(a), (b), or (c). For 
any provisionally-certified monitoring system, some or all of the 
quarterly data may be invalidated, if the Administrator subsequently 
issues a notice of disapproval within 120 days of receipt of the 
complete initial certification application or within 60 days of receipt 
of the complete recertification application for the monitoring system. 
Each electronic report must be submitted to the Administrator within 30 
days following the end of each calendar quarter and shall

[[Page 283]]

include for each affected unit (or group of units using a common stack):
    (1) The information and hourly data required in Secs. 75.50 through 
75.52 (or Secs. 75.54 through 75.56), no later than the quarterly report 
due April 30, 1996), excluding:
    (i) Descriptions of adjustments, corrective action, and maintenance;
    (ii) Information which is incompatible with electronic reporting 
(e.g., field data sheets, lab analyses, quality control plan);
    (iii) Opacity data listed in Sec. 75.50(f) or Sec. 75.54(f);
    (iv) For units with SO2 or NOX add-on emission controls 
that do not elect to use the approved site-specific parametric 
monitoring procedures for calculation of substitute data, the 
information in Sec. 75.55(b)(3); and
    (v) The information recorded under Sec. 75.56(a)(7) for the period 
prior to January 1, 1996.
    (2) Tons (rounded to the nearest tenth) of SO2 emitted during 
the quarter and cumulative SO2 emissions for calendar year.
    (3) Average NOx emission rate (lb/mmBtu, rounded to the nearest 
hundredth) during the quarter and cumulative NOx emission rate for 
calendar year.
    (4) Tons of CO2 emitted during quarter and cumulative CO2 
emissions for calendar year.
    (5) Total heat input (mmBtu) for quarter and cumulative heat input 
for calendar year.
    (6) If the affected unit is using a qualifying Phase I technology, 
then the quarterly report shall include the information required in 
paragraph (e) of this section.
    (b) The designated representative shall affirm that the component/
system identification codes and formulas in the quarterly electronic 
reports, submitted to the Administrator pursuant to Sec. 75.53, 
represent current operating conditions.
    (c) Compliance certification. The designated representative shall 
submit a certification in support of each quarterly emissions monitoring 
report based on reasonable inquiry of those persons with primary 
responsibility for ensuring that all of the unit's emissions are 
correctly and fully monitored. The certification shall indicate whether 
the monitoring data submitted were recorded in accordance with the 
applicable requirements of this part including the quality control and 
quality assurance procedures and specifications of this part and its 
appendices, and any such requirements, procedures and specifications of 
an applicable excepted or approved alternative monitoring method. In the 
event of any missing data periods, the certification must describe the 
measures taken to cure the causes for the missing data periods. For a 
unit with add-on emission controls, the designated representative shall 
also include a certification for all hours where data are substituted 
following the provisions of Sec. 75.34(a)(1), that the add-on emission 
controls were operating within the range of parameters listed in the 
monitoring plan, and that the substitute values recorded during the 
quarter do not systematically underestimate SO2 or NOX 
emissions, pursuant to Sec. 75.34.
    (d) Electronic format. Each quarterly report shall be submitted in a 
format to be specified by the Administrator, including both electronic 
submission of data and paper submission of compliance certifications.
    (e) Phase I qualifying technology reports. In addition to reporting 
the information in paragraphs (a), (b), and (c) of this section, the 
designated representative for an 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 shall also submit reports documenting the 
measured percent SO2 emissions removal to the Administrator on a 
quarterly basis, beginning the first quarter of 1997 and continuing 
through the fourth quarter of 1999. Each report shall include all 
measurements and calculations necessary to substantiate that the 
qualifying technology achieves the overall percentage reduction in 
SO2 emissions.

[58 FR 3701, Jan. 11, 1993, as amended at 60 FR 26540, 26569, May 17, 
1995]



Sec. 75.65  Opacity reports.

    The owner or operator or designated representative shall report 
excess emissions of opacity recorded under

[[Page 284]]

Sec. Sec. 75.50(f) or 75.54(f) to the applicable State or local air 
pollution control agency, in a format specified by the applicable State 
or local air pollution control agency.

[60 FR 26540, May 17, 1995]



Sec. 75.66  Petitions to the Administrator.

    (a) General. The designated representative for an affected unit 
subject to the requirements of this part may submit petitions to the 
Administrator. Any petitions shall be submitted in accordance with the 
requirements of this section. The designated representative shall comply 
with the signatory requirements of Sec. 72.21 of this chapter for each 
submission.
    (b) Alternative flow monitoring method petition. In cases where no 
location exists for installation of a flow monitor in either the stack 
or the ducts serving an affected unit that satisfies the minimum 
physical siting criteria in appendix A of this part or where 
installation of a flow monitor in either the stack or duct is 
demonstrated to the satisfaction of the Administrator to be technically 
infeasible, the designated representative for the affected unit may 
petition the Administrator for an alternative method for monitoring 
volumetric flow. The petition shall, at a minimum, contain the following 
information:
    (1) Identification of the affected unit(s);
    (2) Description of why the minimum siting criteria cannot be met 
within the existing ductwork or stack(s). This description shall include 
diagrams of the existing ductwork or stack, as well as documentation of 
any attempts to locate a flow monitor; and
    (3) Description of proposed alternative method for monitoring flow.
    (c) Alternative to standards incorporated by reference. The 
designated representative for an affected unit may apply to the 
Administrator for an alternative to any standard incorporated by 
reference and prescribed in this part. The designated representative 
shall include the following information in an application:
    (1) A description of why the prescribed standard is not being used;
    (2) A description and diagram(s) of any equipment and procedures 
used in the proposed alternative;
    (3) Information demonstrating that the proposed alternative produces 
data acceptable for use in the Acid Rain Program, including accuracy and 
precision statements, NIST traceability certificates or protocols, or 
other supporting data, as applicable to the proposed alternative.
    (d) Alternative monitoring system petitions. The designated 
representative for an affected unit may submit a petition to the 
Administrator for approval and certification of an alternative 
monitoring system or component according to the procedure in subpart E 
of this part. Each petition shall contain the information and data 
specified in subpart E, including the information specified in 
Sec. 75.48, in a format to be specified by the Administrator.
    (e) Parametric monitoring procedure petitions. The designated 
representative for an affected unit may submit a petition to the 
Administrator, where each petition shall contain the information 
specified in Sec. 75.51(b) (or Sec. 75.55(b), no later than January 1, 
1996) for use of a parametric monitoring method. The Administrator will 
either:
    (1) Publish a notice in the Federal Register indicating receipt of a 
parametric monitoring procedure petition;, or
    (2) Notify interested parties of receipt of a parametric monitoring 
petition.
    (f) Missing data petitions for units with add-on emission controls. 
The designated representative for an affected unit may submit a petition 
to the Administrator for the use of the maximum controlled emission 
rate, which the Administrator will approve if the petition adequately 
demonstrates that all the requirements in Sec. 75.34(a)(2) are 
satisfied. Each petition shall contain the information listed below for 
the time period (or data gap) during which the affected unit experienced 
the monitor outage that would otherwise result in the substitution of an 
uncontrolled maximum value under the standard missing data procedures 
contained in subpart D of this part:
    (1) Data demonstrating that the affected unit's monitor data 
availability

[[Page 285]]

for the time period under petition was less than 90.0 percent;
    (2) Data demonstrating that the add-on emission controls were 
operating properly during the time period under petition (i.e., within 
the range of operating parameters for the add-on emission controls in 
the monitoring plan for the unit);
    (3) A list of the average hourly values for the previous 720 
quality-assured monitor operating hours, highlighting both the maximum 
recorded value and the value corresponding to the maximum controlled 
emission rate; and
    (4) An explanation and information on operation of the add-on 
emission controls demonstrating that the selected historical SO2 
concentration or NOX emission rate does not underestimate the 
SO2 concentration or NOX emission rate during the missing data 
period.
    (g) Petitions for emissions or heat input apportionments. The 
designated representative of an affected unit shall provide information 
to describe a method for emissions or heat input apportionment under 
Secs. 75.13, 75.16, 75.17, or appendix D of this part. This petition may 
be submitted as part of the monitoring plan. Such a petition shall 
contain, at a minimum, the following information:
    (1) A description of the units, including their fuel type, their 
boiler type, and their categorization as Phase I units, substitution 
units, compensating units, Phase II units, new units, or non-affected 
units;
    (2) A formula describing how the emissions or heat input are to be 
apportioned to which units;
    (3) A description of the methods and parameters used to apportion 
the emissions or heat input; and
    (4) Any other information necessary to demonstrate that the 
apportionment method accurately measures emissions or heat input and 
does not underestimate emissions or heat input from affected units.
    (h) Partial recertification petition. The designated representative 
of an affected unit may provide information and petition the 
Administrator to specify which of the certification tests required by 
Sec. 75.20 apply for partial recertification of the affected unit. Such 
a petition shall include the following information:
    (1) Identification of the monitoring system(s) being changed;
    (2) A description of the changes being made to the system;
    (3) An explanation of why the changes are being made; and
    (4) A description of the possible effect upon the monitoring 
system's ability to measure, record, and report emissions.
    (i) Any other petitions to the Administrator under this part. The 
designated representative for an affected unit shall include sufficient 
information for the evaluation of any other petition submitted to the 
Administrator under this part.

[58 FR 3701, Jan. 11, 1993,as amended at 60 FR 26540, 26569, May 17, 
1995]



Sec. 75.67  Retired units petitions.

    (a) For units that will be permanently retired prior to January 1, 
1995, if the designated representative submits a complete petition, as 
required in Sec. 72.8 of this chapter, to the Administrator prior to the 
deadline in Sec. 75.4 by which the continuous emission or opacity 
monitoring systems must complete the required certification tests, the 
Administrator will issue an exemption from the requirements of this 
part, including the requirement to install and certify continuous 
emission monitoring systems.
    (b) For combustion sources seeking to enter the Opt-in Program in 
accordance with part 74 of this chapter that will be permanently retired 
and governed upon entry into the Opt-in Program by a thermal energy plan 
in accordance with Sec. 74.47 of this chapter, an exemption from the 
requirements of this part, including the requirement to install and 
certify a continuous emissions monitoring system, may be obtained from 
the Administrator if the designated representative submits to the 
Administrator a petition for such an exemption prior to the deadline in 
Sec. 75.4 by which the continuous emission or opacity monitoring systems 
must complete the required certification tests.

[60 FR 17131, Apr. 4, 1995, as amended at 60 FR 26541, May 17, 1995]

[[Page 286]]



        Appendix A to Part 75--Specifications and Test Procedures

                1. Installation and Measurement Location

      1.1  Pollutant Concentration and CO2 or O2 Monitors

    Following the procedures in section 3.1 of Performance Specification 
2 in Appendix B to part 60 of this chapter, install the pollutant 
concentration monitor or monitoring system at a location where the 
pollutant concentration and emission rate measurements are directly 
representative of the total emissions from the affected unit. Select a 
representative measurement point or path for the monitor probe(s) (or 
for the path from the transmitter to the receiver) such that the 
SO2 pollutant concentration monitor or NOx continuous emission 
monitoring system (NOx pollutant concentration monitor and diluent 
gas monitor) will pass the relative accuracy test (see section 6 of this 
Appendix).
    It is recommended that monitor measurements be made at locations 
where the exhaust gas temperature is above the dew-point temperature. If 
the cause of failure to meet the relative accuracy tests is determined 
to be the measurement location, relocate the monitor probe(s).

  1.1.1  Point Pollutant Concentration and CO2 or O2 Monitors

    Locate the measurement point (1) within the centroidal area of the 
stack or duct cross section, or (2) no less than 1.0 meter from the 
stack or duct wall.

1.1.2  Path Pollutant Concentration and CO2 or O2 Gas Monitors

    Locate the measurement path (1) totally within the inner area 
bounded by a line 1.0 meter from the stack or duct wall, or (2) such 
that at least 70.0 percent of the path is within the inner 50.0 percent 
of the stack or duct cross-sectional area, or (3) such that the path is 
centrally located within any part of the centroidal area.

                           1.2  Flow Monitors

    Install the flow monitor in a location that provides representative 
volumetric flow over all operating conditions. Such a location is one 
that provides an average velocity of the flue gas flow over the stack or 
duct cross section, provides a representative SO2 emission rate (in 
lb/hr), and is representative of the pollutant concentration monitor 
location. Where the moisture content of the flue gas affects volumetric 
flow measurements, use the procedures in both Reference Methods 1 and 4 
of Appendix A to part 60 of this chapter to establish a proper location 
for the flow monitor. The EPA recommends (but does not require) 
performing a flow profile study following the procedures in 40 CFR part 
60, appendix A, Method, 1, section 2.5 or 2.4 for each of the three 
operating or load levels indicated in section 6.5.2 of this appendix to 
determine the acceptability of the potential flow monitor location and 
to determine the number and location of flow sampling points required to 
obtain a representative flow value. The procedure in 40 CFR part 60, 
Appendix A, Test Method 1, section 2.5 may be used even if the flow 
measurement location is greater than or equal to 2 equivalent stack or 
duct diameters downstream or greater than or equal to \1/2\ duct 
diameter upstream from a flow disturbance. If a flow profile study shows 
that cyclonic (or swirling) or stratified flow conditions exist at the 
potential flow monitor location that are likely to prevent the monitor 
from meeting the performance specifications of this part, then EPA 
recommends either (1) selecting another location where there is no 
cyclonic (or swirling) or stratified flow condition, or (2) eliminating 
the cyclonic (or swirling) or stratified flow condition by straightening 
the flow, e.g., by installing straightening vanes. EPA also recommends 
selecting flow monitor locations to minimize the effects of 
condensation, coating, erosion, or other conditions that could adversely 
affect flow monitor performance.

                1.2.1  Acceptability of Monitor Location

    The installation of a flow monitor is acceptable if either (1) the 
location satisfies the minimum siting criteria of Method 1 in Appendix A 
to part 60 of this chapter (i.e., the location is greater than or equal 
to eight stack or duct diameters downstream and two diameters upstream 
from a flow disturbance; or, if necessary, two stack or duct diameters 
downstream and one-half stack or duct diameter upstream from a flow 
disturbance), or (2) the results of a flow profile study, if performed, 
are acceptable (i.e., there are no cyclonic (or swirling) or stratified 
flow conditions), and the flow monitor also satisfies the performance 
specifications of this part. If the flow monitor is installed in a 
location that does not satisfy these physical criteria, but nevertheless 
the monitor achieves the performance specifications of this part, then 
the location is acceptable, notwithstanding the requirements of this 
section.

                 1.2.2  Alternative Monitoring Location

    Whenever the designated representative successfully demonstrates 
that modifications to the exhaust duct or stack (such as installation of 
straightening vanes, modifications of ductwork, and the like) are 
necessary for the flow monitor to meet the performance specifications, 
the Administrator may approve an interim alternative flow monitoring 
methodology and an extension to

[[Page 287]]

the required certification date for the flow monitor.
    Whenever the owner or operator successfully demonstrates that 
modifications to the exhaust duct or stack (such as installation of 
straightening vanes, modifications of ductwork, and the like) are 
necessary for the flow monitor to meet the performance specifications, 
the Administrator may approve an interim alternative flow monitoring 
methodology and an extension to the required certification date for the 
flow monitor.
    Where no location exists that satisfies the physical siting criteria 
in section 1.2.1, where the results of flow profile studies performed at 
two or more alternative flow monitor locations are unacceptable, or 
where installation of a flow monitor in either the stack or the ducts is 
demonstrated to be technically infeasible, the owner or operator may 
petition the Administrator for an alternative method for monitoring 
flow.

                       2. Equipment Specifications

                          2.1  Instrument Span

    In implementing sections 2.1.1 through 2.1.4 of this appendix, to 
the extent practicable, measure at a range such that the majority of 
readings obtained during normal operation are between 25 and 75 percent 
of full-scale range of the instrument.

            2.1.1  SO2 Pollutant Concentration Monitors

    Determine, as indicated below, the span value for an SO2 
pollutant concentration monitor so that all expected concentrations can 
be accurately measured and recorded.

                2.1.1.1   Maximum Potential Concentration

    The monitor must be capable of accurately measuring up to 125 
percent of the maximum potential concentration (MPC) as calculated using 
Equation A-1a or A-1b. Calculate the maximum potential concentration by 
using Equation A-1a or A-1b and the maximum percent sulfur and minimum 
gross calorific value (GCV) for the highest sulfur fuel to be burned, 
using daily fuel sample data if they are available. If an SO2 CEMS 
is already installed, the owner or operator may determine an MPC based 
upon the maximum concentration observed during the previous 30 unit 
operating days when using the type of fuel to be burned. For initial 
certification, base the maximum percent sulfur and minimum GCV on the 
results of all available fuel sampling and analysis data from the 
previous 12 months (where such data exists). If the unit has not been 
operated during that period, use the maximum sulfur content and minimum 
GCV from the fuel contract for fuel that will be combusted by the unit. 
Whenever the fuel supply changes such that these maximum sulfur and 
minimum GCV values may change significantly, base the maximum percent 
sulfur and minimum GCV on the new fuel with the highest sulfur content. 
Use the one of the two following methods that results in a higher MPC: 
(1) results of samples representative of the new fuel supply, or (2) 
maximum sulfur and minimum GCV from the fuel contract for fuel that will 
be combusted by the unit. Whenever performing fuel sampling to determine 
the MPC, use ASTM Methods ASTM D3177-89, ``Standard Test Methods for 
Total Sulfur in the Analysis Sample of Coal and Coke,'' ASTM D4239-85, 
``Standard Test Methods for Sulfur in the Analysis Sample of Coal and 
Coke Using High Temperature Tube Furnace Combustion Methods,'' ASTM 
D4294-90, ``Standard Test Method for Sulfur in Petroleum Products by 
Energy-Dispersive X-Ray Fluorescence Spectroscopy,'' ASTM D1552-90, 
``Standard Test Method for Sulfur in Petroleum Products (High 
Temperature Method),'' ASTM D129-91, ``Standard Test Method for Sulfur 
in Petroleum Products (General Bomb Method),'' or ASTM D2622-92, 
``Standard Test Method for Sulfur in Petroleum Products by X-Ray 
Spectrometry'' for sulfur content of solid or liquid fuels, or ASTM 
D3176-89, ``Standard Practice for Ultimate Analysis of Coal and Coke'', 
ASTM D240-87 (Reapproved 1991), ``Standard Test Method for Heat of 
Combustion of Liquid Hydrocarbon Fuels by Bomb Calorimeter'', or ASTM 
D2015-91, ``Standard Test Method for Gross Calorific Value of Coal and 
Coke by the Adiabatic Bomb Calorimeter'' for GCV (incorporated by 
reference under Sec. 75.6). Multiply the maximum potential concentration 
by 125 percent, and round up the resultant concentration to the nearest 
multiple of 100 ppm to determine the span value. The span value will be 
used to determine the concentrations of the calibration gases. Include 
the full-scale range setting and calculations of the span and MPC in the 
monitoring plan for the unit. Select the full-scale range of the 
instrument to be consistent with section 2.1 of this appendix, and to be 
greater than or equal to the span value. This selected monitor range 
with a span rounded up from 125 percent of the maximum potential 
concentration will be the ``high-scale'' of the SO2 pollutant 
concentration monitor.

[[Page 288]]

[GRAPHIC] [TIFF OMITTED] TR17MY95.005


    Where,
MPC=Maximum potential concentration (ppm, wet basis). (To convert to dry 
          basis, divide the MPC by 0.9.)
%S=Maximum sulfur content of fuel to be fired, wet basis, weight 
          percent, as determined by ASTM D3177-89, ASTM D4239-85, ASTM 
          D4294-90, ASTM D1552-90, ASTM D129-91, or ASTM D2622-92 for 
          solid or liquid fuels (incorporated by reference under 
          Sec. 75.6).
GCV=Minimum gross calorific value of the fuel lot consistent with the 
          sulfur analysis (Btu/lb), as determined using ASTM D3176-89, 
          ASTM D240-87 (Reapproved 1991), or ASTM D2015-91 (incorporated 
          by reference under Sec. 75.6).
%O2w=Minimum oxygen concentration, percent wet basis, under normal 
          operating conditions.
%CO2w=Maximum carbon dioxide concentration, percent wet basis, 
          under normal operating conditions.
11.32 x 10\6\=Oxygen-based conversion factor in (Btu/lb)(ppm)/%.
6.93 x 10\6\=Carbon dioxide-based conversion factor in (Btu/lb)(ppm)/%

    Note: All percent values to be inserted in the equations of this 
section are to be expressed as a percentage, not a fractional value, 
e.g., 3, not .03.

                 2.1.1.2  Maximum Expected Concentration

    If the majority of SO2 concentration values are predicted to be 
less than 25 percent of the full-scale range of the instrument selected 
under section 2.1.1.1 of this appendix, (e.g., where an SO2 add-on 
emission control is used or where fuel with different sulfur contents 
are blended), use an additional (lower) measurement range. For this 
second range, use Equation A-2 to calculate the maximum expected 
concentration (MEC) for units with emission controls. For units blending 
fuels, calculate the MEC using a best estimate of the highest sulfur 
content and lowest gross calorific value expected for the blend and 
inserting these values into Equation A-1. If an SO2 CEMS is already 
installed, the owner or operator may calculate an MEC based upon the 
maximum concentration measured by the CEMS over a thirty-day period, 
provided that there have been no full-scale exceedances since the range 
was last selected. Multiply the maximum expected concentration by 125 
percent, and round up the resultant concentration to the nearest 
multiple of 10 ppm to determine the span value for the additional 
(lower) range. The span value of this additional range will also be used 
to determine concentrations of the calibration gases for this additional 
range. Report the full-scale range setting and calculations of the MEC 
and span in the monitoring plan for the unit. Select the full-scale 
range of the instrument of this additional (lower) range to be 
consistent with section 2.1 of this appendix, and to be greater than or 
equal to the lower range span value. This selected monitor range with a 
span rounded up from 125 percent of the MEC will be the ``low-scale'' of 
the SO2 pollutant concentration monitor. Units using a low-scale 
range must also be capable of accurately measuring the anticipated 
concentrations up to and including 125 percent of the maximum potential 
concentration. If an existing State, local, or Federal requirement for 
span of an SO2 pollutant concentration monitor requires a span 
other than that required in this section, but less than that required 
for the high-scale by this appendix, the State, local or Federal span 
value may be approved, where a satisfactory explanation is included in 
the monitoring plan.

MEC=MPC[(100-RE)/100]    (Eq. A-2)
Where:

MEC=Maximum expected concentration (ppm).
MPC=Maximum potential concentration (ppm), as determined by Eq. A-1a or 
          A-1b.
RE = Expected average design removal efficiency of control equipment 
          (%).

                     2.1.1.3  Auto-ranging Monitors

    For monitors that can continuously and automatically adjust their 
range of measurement, the monitor must be capable at any time of 
accurately measuring up to 125 percent of the maximum potential 
concentration, as calculated using Equation A-1a or A-1b. Define the 
span value(s) for an auto-

[[Page 289]]

ranging monitor as 125 percent of the maximum potential concentration 
and 125 percent of the maximum expected concentration if a second span 
is determined to be necessary under section 2.1.1.2 of this appendix. 
Determine concentrations of the calibration gases based upon the span 
value(s).

                       2.1.1.4 Adjustment of Span

    Wherever the SO2 concentration exceeds the maximum potential 
concentration but does not exceed the full-scale range during more than 
one clock-hour and the monitor can measure and record the SO2 
concentration accurately, it may be reported for use in the Acid Rain 
Program. If the concentration exceeds the monitor's ability to measure 
and record values accurately during a clock hour, and the full-scale 
exceedance is not during an out-of-control period, report the full-scale 
value as the SO2 concentration for that clock hour. If full-scale 
exceedances occur during more than one clock hour since the last 
adjustment of the full-scale range setting, adjust the full-scale range 
setting to prevent future exceedances.
    Whenever the fuel supply or emission controls change such that the 
maximum expected or potential concentration may change significantly, 
adjust the span and range setting to assure the continued proper 
operation of the monitoring system. Determine the adjusted span using 
the procedures in sections 2.1.1.1 or 2.1.1.2 of this appendix. Select 
the full scale range of the instrument to be greater than or equal to 
the new span value and to be consistent with the guidelines of section 
2.1 of this appendix. Record and report the new full-scale range 
setting, calculations of the span, MPC, and MEC (if appropriate), and 
the adjusted span value, in an updated monitoring plan. In addition, 
record and report the adjusted span as part of the records for the daily 
calibration error test and linearity check specified by appendix B of 
this part. Whenever the span value is adjusted, use calibration gas 
concentrations based on the most recent adjusted span value. Perform a 
linearity check according to section 6.2 of this appendix whenever 
making a change to the monitor span or range. Recertification under 
Sec. 75.20(b) is required whenever a significant change in the monitor's 
range also requires an internal modification to the monitor (e.g., a 
change of measurement cell length).

             2.1.2 NOX Pollutant Concentration Monitors

    Determine, as indicated below, the span value(s) for the NOX 
pollutant concentration monitor so that all expected NOX 
concentrations can be determined and recorded accurately including both 
the maximum expected and potential concentration.

                 2.1.2.1 Maximum Potential Concentration

    The monitor must be capable of accurately measuring up to 125 
percent of the maximum potential concentration (MPC) as determined below 
in this section. Use 800 ppm for coal-fired and 400 ppm for oil- or gas-
fired units as the maximum potential concentration of NOx, unless a more 
representative MPC is determined by one of the following methods (If an 
MPC of 1600 ppm for coal-fired units or 480 ppm for oil- or gas-fired 
units was previously selected under this part, that value may still be 
used.): (1) NOX emission test results, (2) historical CEM data over 
the previous 30 unit operating days; or (3) specific values based on 
boiler-type and fuel combusted, listed in Table 2-1 or Table 2-2 if 
other data under (1) or (2) were not available. Multiply the MPC by 125 
percent and round up to the nearest multiple of 100 ppm to determine the 
span value. The span value will be used to determine the concentrations 
of the calibration gases.
    Report the full-scale range setting, and calculations of the MPC, 
maximum potential NOX emission rate, and span in the monitoring 
plan for the unit. Select the full-scale range of the instrument to be 
consistent with section 2.1 of this appendix, and to be greater than or 
equal to the span value. This selected monitor range with a span rounded 
up from 125 percent of the maximum potential concentration will be the 
``high-scale'' of the NOX pollutant concentration monitor.
    If NOX emission testing is used to determine the maximum 
potential NOX concentration, use the following guidelines: Use 
Method 7E from appendix A of part 60 of this chapter to measure total 
NOX concentration. Operate the unit, or group of units sharing a 
common stack, at the minimum safe and stable load, the normal load, and 
the maximum load. If the normal load and maximum load are identical, an 
intermediate level need not be tested. Operate at the highest excess 
O2 level expected under normal operating conditions. Make at least 
three runs with three traverse points of at least 20 minutes duration at 
each operating condition. Select the highest NOX concentration from 
all measured values as the maximum potential concentration for NOx. If 
historical CEM data are used to determine the MPC, the data must 
represent various operating conditions, including the minimum safe and 
stable load, normal load, and maximum load. Calculate the MPC and span 
using the highest hourly NOX concentration in ppm. If no test data 
or historical CEM data are available, use Table 2-1 or Table 2-2 to 
estimate the maximum potential concentration based upon boiler type and 
fuel used.

[[Page 290]]



                      Table 2-1.--Maximum Potential Concentration for NOX--Coal-Fired Units                     
----------------------------------------------------------------------------------------------------------------
                   Unit type                              Maximum potential concentration for NOX (ppm)         
----------------------------------------------------------------------------------------------------------------
Tangentially-fired dry bottom and fluidized bed  460                                                            
Wall-fired dry bottom, turbo-fired dry bottom,   675                                                            
 stokers.                                                                                                       
Roof-fired (vertically-fired) dry bottom, cell   975                                                            
 burners, arch-fired.                                                                                           
Cyclone, wall-fired wet bottom, wet bottom       1200                                                           
 turbo-fired.                                                                                                   
Others.........................................  As approved by the Administrator.                              
----------------------------------------------------------------------------------------------------------------


                  Table 2-2.--Maximum Potential Concentration For NOX--Gas- And Oil-Fired Units                 
----------------------------------------------------------------------------------------------------------------
                   Unit type                              Maximum potential concentration for NOX (ppm)         
----------------------------------------------------------------------------------------------------------------
Tangentially-fired dry bottom..................  380                                                            
Wall-fired dry bottom..........................  600                                                            
Roof-fired (vertically-fired) dry bottom, arch-  550                                                            
 fired.                                                                                                         
Existing combustion turbine or combined cycle    200                                                            
 turbine.                                                                                                       
New stationary gas turbine/combustion turbine..  50                                                             
Others.........................................  As approved by the Administrator.                              
----------------------------------------------------------------------------------------------------------------

                 2.1.2.2 Maximum Expected Concentration

    If the majority of NOX concentrations are expected to be less 
than 25 percent of the full-scale range of the instrument selected under 
section 2.1.2.1 of this appendix (e.g., where a NOX add-on emission 
control is used) use a ``low-scale'' measurement range. For units with 
add-on emission controls, determine the maximum expected concentration 
(MEC) of NOX using Equation A-2, inserting the maximum potential 
concentration, as determined using the procedures in section 2.1.2.1 of 
this appendix. Where Equation A-2 is not appropriate, set the MEC, 
either (1) by measuring the NOX concentration using the testing 
procedures in section 2.1.2.1 of this appendix, or (2) by using 
historical CEM data over the previous 30 unit operating days. Other 
methods for determining the MEC may be accepted if they are 
satisfactorily explained in the monitoring plan. If an existing State, 
local, or Federal requirement for span of an NOX pollutant 
concentration monitor requires a span other than that required in this 
section, but less than that required for the high scale by this 
appendix, the State, local, or Federal span value may be approved, where 
a satisfactory explanation is included in the monitoring plan. Calculate 
the span for the additional (lower) range by multiplying the maximum 
expected concentration by 125 percent and by rounding up the resultant 
concentration to the nearest multiple of 10 ppm. The span value of this 
additional (lower) range will also be used to determine the 
concentrations of the calibration gases. Include the full-scale range 
setting and calculations of the MEC and span in the monitoring plan for 
the unit. Select the full-scale range of the instrument to be consistent 
with section 2.1 of this appendix, and to be greater or equal to the 
lower range span value. This selected monitor range with a span rounded 
up from 125 percent of the maximum expected concentration is the ``low-
scale'' of NOX pollutant concentration monitors. NOX pollutant 
concentration monitors on affected units with NOX emission 
controls, or on other units with monitors using a low-scale range, must 
also be capable of accurately measuring up to 125 percent of the maximum 
potential concentration. For dual-span NOX pollutant concentration 
monitors, determine the concentration of calibration gases based on both 
span values.

                     2.1.2.3  Auto-ranging monitors

    For monitors that can continuously and automatically adjust their 
range of measurement, the monitor must be capable at any time of 
accurately measuring up to 125 percent of the maximum potential 
concentration as defined in section 2.1.2.1 of this appendix. Define the 
span value(s) for an auto-ranging monitor as 125 percent of the maximum 
potential concentration and 125 percent of the maximum expected 
concentration if a second span is determined to be necessary under 
section 2.1.2.2 of this appendix. Determine concentrations of the 
calibration gases based upon the span value(s).

                       2.1.2.4 Adjustment of Span

    Wherever the actual NOX concentration exceeds the maximum 
potential concentration but does not exceed the full-scale range for 
more than one clock-hour and the monitor can measure and record the 
NOX concentration values accurately, the NOX concentration 
values may be reported for use in the Acid Rain Program. If the 
concentration exceeds the monitor's ability to measure and record values 
accurately during a clock hour, and the full-scale exceedance is not 
during an out-of-control period, report the full-scale value as the 
NOX concentration for that clock hour. If full-scale exceedances 
occur during more than one clock hour since the last adjustment of the 
full-scale range

[[Page 291]]

setting, adjust the full-scale range setting to prevent future 
exceedances.
    Whenever the fuel supply, emission controls, or other process 
parameters change such that the maximum expected concentration or the 
maximum potential concentration may change significantly, adjust the 
NOX pollutant concentration span and monitor range to assure the 
continued accuracy of the monitoring system. Determine the adjusted span 
value using the procedures in sections 2.1.2.1 or 2.1.2.2 of this 
appendix. Select the new full scale range of the instrument to be 
greater than or equal to the adjusted span value and to be consistent 
with the guidelines of section 2.1 of this appendix. Record and report 
the new full-scale range setting, calculations of the span value, MPC, 
and MEC (if appropriate), maximum potential NOX emission rate and 
the adjusted span value in an updated monitoring plan for the unit. In 
addition, record and report the adjusted span as part of the records for 
the daily calibration error test and linearity check required by 
appendix B of this part. Whenever the span value is adjusted, use 
calibration gas concentrations based on the most recent adjusted span 
value. Perform a linearity check according to section 6.2 of this 
appendix whenever making a change to the monitor span or range. 
Recertification under Sec. 75.20(b) is required whenever a significant 
change is made in the monitor's range that requires an internal 
modification to the monitor (e.g., a change of measurement cell length).

                   2.1.3 CO2 and O2 Monitors

    Define the ``high scale'' span value as 20 percent O2 or 20 
percent CO2. All O2 and CO2 analyzers must have ``high-
scale'' measurement capability. Select the full-scale range of the 
instrument to be consistent with section 2.1 of this appendix, and to be 
greater than or equal to the span value. If the O2 or CO2 
concentrations are expected to be consistently low, a ``low scale'' 
measurement range may be used for increased accuracy, provided that it 
is consistent with section 2.1 of this appendix. Include a span value 
for the low-scale range in the monitoring plan. Select the calibration 
gas concentrations as percentages of the span value.

                           2.1.4 Flow Monitors

    Select the full-scale range of the flow monitor so that it is 
consistent with section 2.1 of this appendix, and can accurately measure 
all potential volumetric flow rates at the flow monitor installation 
site. For this purpose, determine the span value of the flow monitor 
using the following procedure. Calculate the maximum potential velocity 
(MPV) using Equation A-3a or A-3b or determine the MPV or maximum 
potential flow rate (MPF) in scfh (wet basis) from velocity traverse 
testing. If using test values, use the highest velocity measured at or 
near the maximum unit operating load. Calculate the MPV in units of wet 
standard fpm. Then, if necessary, convert the MPV to equivalent units of 
flow rate (e.g., scfh or kscfh) or differential pressure (inches of 
water), consistent with the measurement units used for the daily 
calibration error test to calculate the span value. Multiply the MPV (in 
equivalent units) by 125 percent, and round up the result to no less 
than 2 significant figures. Report the full-scale range setting, and 
calculations of the span value, MPV and MPF in the monitoring plan for 
the unit.
[GRAPHIC] [TIFF OMITTED] TR17MY95.006

Where:

MPV=maximum potential velocity (fpm, standard wet basis),
Fd=dry-basis F factor (dscf/mmBtu) from Table 1, Appendix F of this 
          part,
Fc=carbon-based F factor (scfCO2/mmBtu) from Table 1, Appendix F of this 
          part,
Hf=maximum heat input (mmBtu/minute) for all units, combined, exhausting 
          to the stack or duct where the flow monitor is located,
A=inside cross sectional area (ft2) of the flue at the flow monitor 
          location,

[[Page 292]]

%O2d=maximum oxygen concentration, percent dry basis, under normal 
          operating conditions,
%CO2d=minimum carbon dioxide concentration, percent dry basis, under 
          normal operating conditions,
%H2O = maximum percent flue gas moisture content under normal 
          operating conditions.

    If the volumetric flow rate exceeds the maximum potential flow 
calculated from the maximum potential velocity but does not exceed the 
full scale range during more than one clock hour and the flow monitor 
can accurately measure and record values, the flow rate may be reported 
for use in the Acid Rain Program. If the volumetric flow rate exceeds 
the monitor's ability to measure and record values accurately during a 
clock hour, and the full-scale exceedance is not during an out-of-
control period, report the full-scale value as the flow rate for that 
clock hour. If full-scale exceedance occurs during more than one hour 
since the last adjustment of the full-scale range setting, adjust the 
full-scale range setting to prevent future exceedances. If the fuel 
supply, process parameters or other conditions change such that the 
maximum potential velocity may change significantly, adjust the range to 
assure the continued accuracy of the flow monitor. Calculate an adjusted 
span using the procedures in this section. Select the full-scale range 
of the instrument to be greater than or equal to the adjusted span 
value. Record and report the new full-scale range setting, calculations 
of the span value, MPV, and MPF, and the adjusted span value in an 
updated monitoring plan for the unit. Record and report the adjusted 
span and reference values as parts of the records for the calibration 
error test required by appendix B of this part. Whenever the span value 
is adjusted, use reference values for the calibration error test based 
on the most recent adjusted span value.
    Perform a calibration error test according to section 2.1.2 of this 
appendix whenever making a change to the flow monitor span or range. 
Recertification under Sec. 75.20(b) is required whenever making a 
significant change in the flow monitor's range that requires an internal 
modification to the monitor.

                 2.2  Design for Quality Control Testing

     2.2.1  Pollutant Concentration and CO2 or O2 Monitors

    Design and equip each pollutant concentration and CO2 or 
O2 monitor with a calibration gas injection port that allows a 
check of the entire measurement system when calibration gases are 
introduced. For extractive and dilution type monitors, all monitoring 
components exposed to the sample gas, (e.g., sample lines, filters, 
scrubbers, conditioners, and as much of the probe as practicable) are 
included in the measurement system. For in situ type monitors, the 
calibration must check against the injected gas for the performance of 
all active electronic and optical components (e.g. transmitter, 
receiver, analyzer).
    Design and equip each pollutant concentration or CO2 or O2 
monitor to allow daily determinations of calibration error (positive or 
negative) at the zero- and high-level concentrations specified in 
Section 5.2 of this Appendix.

                          2.2.2  Flow Monitors

    Design all flow monitors to meet the applicable performance 
specifications.

                     2.2.2.1  Calibration Error Test

    Design and equip each flow monitor to allow for a daily calibration 
error test consisting of at least two reference values: (1) Zero to 20 
percent of span or an equivalent reference value (e.g., pressure pulse 
or electronic signal) and (2) 50 to 70 percent of span. Flow monitor 
response, both before and after any adjustment, must be capable of being 
recorded by the data acquisition and handling system. Design each flow 
monitor to allow a daily calibration error test of (1) the entire flow 
monitoring system, from and including the probe tip (or equivalent) 
through and including the data acquisition and handling system, or (2) 
the flow monitoring system from and including the transducer through and 
including the data acquisition and handling system.

                       2.2.2.2  Interference Check

    Design and equip each flow monitor with a means to ensure that the 
moisture expected to occur at the monitoring location does not interfere 
with the proper functioning of the flow monitoring system. Design and 
equip each flow monitor with a means to detect, on at least a daily 
basis, pluggage of each sample line and sensing port, and malfunction of 
each resistance temperature detector (RTD), transceiver or equivalent.
    Design and equip each differential pressure flow monitor to provide 
(1) an automatic, periodic back purging (simultaneously on both sides of 
the probe) or equivalent method of sufficient force and frequency to 
keep the probe and lines sufficiently free of obstructions on at least a 
daily basis to prevent velocity sensing interference, and (2) a means 
for detecting leaks in the system on at least a quarterly basis (manual 
check is acceptable).
    Design and equip each thermal flow monitor with a means to ensure on 
at least a daily basis that the probe remains sufficiently clean to 
prevent velocity sensing interference.

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    Design and equip each ultrasonic flow monitor with a means to ensure 
on at least a daily basis that the transceivers remain sufficiently 
clean (e.g., backpurging system) to prevent velocity sensing 
interference.

                      3. Performance Specifications

                         3.1  Calibration Error

    The initial calibration error performance specification of SO2 
and NOx pollutant concentration monitors shall not deviate from the 
reference value of the calibration gas by more than 2.5 percent based 
upon the span of the instrument, as calculated using Eq. A-5 of this 
appendix. Alternatively, where the span value is less than 200 ppm, 
calibration error test results are also acceptable if the absolute value 
of the difference between the monitor response value and the reference 
value, | R-A| in Equation A-5 of this appendix, is less than or equal to 
5 ppm. The calibration error of CO2 or O2 monitors shall not 
deviate from the reference value of the zero- or high-level calibration 
gas by more than 0.5 percent O2 or CO2 as calculated using the 
term | R-A | in the numerator of Eq. A-5 of this appendix. The 
calibration error of flow monitors shall not exceed 3.0 percent based 
upon the span of the instrument as calculated using Eq. A-6 of this 
appendix.

                          3.2  Linearity Check

    For SO2 and NOx pollutant concentration monitors, the 
error in linearity for each calibration gas concentration (low-, mid-, 
and high-levels) shall not exceed or deviate from the reference value by 
more than 5.0 percent (as calculated using Equation A-4 of this 
appendix). Linearity check results are also acceptable if the absolute 
value of the difference between the average of the monitor response 
values and the average of the reference values, | R-A | in Equation A-4 
of this appendix, is less than or equal to 5 ppm. For CO2 or 
O2 monitors:
    (1) The error in linearity for each calibration gas concentration 
(low-, mid-, and high-levels) shall not exceed or deviate from the 
reference value by more than 5.0 percent as calculated using Equation A-
4 of this appendix; or
    (2) The absolute value of the difference between the average of the 
monitor response values and the average of the reference values, | R-A| 
in Equation A-4 of this appendix, shall be less than or equal to 0.5 
percent CO2 or O2, whichever is less restrictive.

                         3.3  Relative Accuracy

                  3.3.1  Relative Accuracy for SO2

    The relative accuracy for SO2 pollutant concentration monitors 
and for SO2-diluent continuous emission monitoring systems used by 
units with a qualifying Phase I technology for the period during which 
the units are required to monitor SO2 emission removal efficiency, 
from January 1, 1997 through December 31, 1999, shall not exceed 10.0 
percent except as provided below in this section.
    For affected units where the average of the monitor measurements of 
SO2 concentration during the relative accuracy test audit is less 
than or equal to 250.0 ppm (or for SO2-diluent monitors, less than 
or equal to 0.5 lb/mmBTU), the mean value of the monitor measurements 
shall not exceed 15.0 ppm of the reference method mean value 
(or, for SO2-diluent monitors, not to exceed 0.03 lb/
mmBTU for the period during which the units are required to monitor 
SO2 emission removal efficiency, from January 1, 1997 through 
December 31, 1999) wherever the relative accuracy specification of 10.0 
percent is not achieved.

                  3.3.2  Relative Accuracy for NOx

    The relative accuracy for NOx continuous emission monitoring 
systems shall not exceed 10.0 percent.
    For affected units where the average of the monitoring system 
measurements of NOx emission rate during the relative accuracy test 
audit is less than or equal to 0.20 lb/mmBtu, the mean value of the 
NOx continuous emission monitoring system measurements shall not 
exceed 0.02 lb/mmBtu of the reference method mean value 
wherever the relative accuracy specification of 10.0 percent is not 
achieved.

      3.3.3  Relative Accuracy for CO2 and O2 Pollutant 
                         Concentration Monitors

    The relative accuracy for CO2 and O2 monitors shall not 
exceed 10.0 percent. The relative accuracy test results are also 
acceptable if the mean difference of the CO2 or O2 monitor 
measurements and the corresponding reference method measurement, 
calculated using Equation A-7 of this appendix, is within 1.0 percent 
CO2 or O2.

                    3.3.4  Relative Accuracy for Flow

    Except as provided below in this section, the relative accuracy for 
flow monitors, where volumetric gas flow is measured in scfh, shall not 
exceed 15.0 percent through December 31, 1999. Beginning on January 1, 
2000 (except as provided below in this section), the relative accuracy 
of flow monitors shall not exceed 10.0 percent.
    For affected units where the average of the flow monitor 
measurements of gas velocity during one or more operating levels of the 
relative accuracy test audit is less than or equal to 10.0 fps, the mean 
value of the flow monitor velocity measurements shall not exceed 
2.0 fps of the reference method mean value in fps wherever 
the relative accuracy specification above is not achieved.

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       3.3.5  Combined SO2/Flow Monitoring System [Reserved]

                                3.4  Bias

3.4.1  SO2 Pollutant Concentration Monitors and NOx Continuous 
                      Emission Monitoring Systems.

    SO2 pollutant concentration monitors and NOx continuous 
emission monitoring systems shall not be biased low as determined by the 
test procedure in section 7.6 of this appendix. The bias specification 
applies to all SO2 pollutant concentration monitors, including 
those measuring an average SO2 concentration of 250.0 ppm or less, 
and to all NOx continuous emission monitoring systems, including 
those measuring an average NOx emission rate of 0.20 lb/mmBtu or 
less

                          3.4.2  Flow Monitors

    Flow monitors shall not be biased low as determined by the test 
procedure in section 7.6 of this appendix. The bias specification 
applies to all flow monitors including those measuring an average gas 
velocity of 10.0 fps or less.

                             3.5  Cycle Time

    The cycle time for pollutant concentration monitors, and continuous 
emission monitoring systems shall not exceed 15 min.

                4. Data Acquisition and Handling Systems

    Automated data acquisition and handling systems shall: (1) Read and 
record the full range of pollutant concentrations and volumetric flow 
from zero through span; and (2) provide a continuous, permanent record 
of all measurements and required information as an ASCII flat file 
capable of transmission via an IBM-compatible personal computer diskette 
or other electronic media. These systems also shall have the capability 
of interpreting and converting the individual output signals from an 
SO2 pollutant concentration monitor, a flow monitor, and a NOx 
continuous emission monitoring system to produce a continuous readout of 
pollutant mass emission rates in the units of the standard. Where 
CO2 emissions are measured with a continuous emission monitoring 
system, the data acquisition and handling system shall also produce a 
readout of CO2 mass emissions in tons.
    Data acquisition and handling systems shall also compute and record 
monitor calibration error; any bias adjustments to pollutant 
concentration, flow rate, or NOx emission rate data; and all 
missing data procedure statistics specified in subpart D of this part.
    For an excepted monitoring system under appendix D or E of this 
part, data acquisition and handling systems shall:
    (1) Read and record the full range of fuel flowrate through the 
upper range value;
    (2) Calculate and record intermediate values necessary to obtain 
emissions, such as mass fuel flowrate and heat input rate;
    (3) Calculate and record emissions in units of the standard (lb/hr 
of SO2, lb/mmBtu of NOX);
    (4) Predict and record NOX emission rate using the heat input 
rate and the NOX/heat input correlation developed under appendix E 
of this part;
    (5) Calculate and record all missing data substitution values 
specified in appendix D or E of this part; and
    (6) Provide a continuous, permanent record of all measurements and 
required information as an ASCII flat file capable of transmission via 
an IBM-compatible personal computer diskette or other electronic media.

                           5. Calibration Gas

                          5.1  Reference Gases

    For the purposes of part 75, calibration gases include the 
following.

                   5.1.1  Standard Reference Materials

    These calibration gases may be obtained from the National Institute 
of Standards and Technology (NIST) at the following address: Quince 
Orchard and Cloppers Road, Gaithersburg, Maryland 20899.

                5.1.2  NIST Traceable Reference Materials

    Contact the Quality Assurance Division (MD 77), Environmental 
Monitoring System Laboratory, U.S. Environmental Protection Agency, 
Research Triangle Park, North Carolina 27711 or the Organic Analytical 
Research Division of NIST at the above address for Standard Reference 
Materials for a list of vendors and cylinder gases.

                5.1.3  EPA Traceability Protocol 1 Gases

    Protocol 1 gases must be vendor-certified to be within 2.0 percent 
of the concentration specified on the cylinder label (tag value).

                      5.1.4  Research Gas Mixtures

    Contact the Quality Assurance Division (MD 77), Environmental 
Monitoring System Laboratory, U.S. Environmental Protection Agency, 
Research Triangle Park, North Carolina 27711 or the Organic Analytical 
Research Division of NIST at the above address for Standard Reference 
Materials for a list of vendors and cylinder gases.

                        5.1.5  Zero Air Material

    Use zero air material for calibrating at zero-level concentrations 
only. Zero air material shall be certified by the gas vendor or 
instrument manufacturer or vendor not to contain concentrations of 
SO2 or NOX above

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0.1 ppm or CO2 above 400 ppm, and not to contain concentrations of 
other gases that will interfere with instrument readings or cause the 
instrument to read concentrations of SO2, NOX, or CO2.

         5.1.6  NIST/EPA-approved Certified Reference Materials

    Existing certified reference materials as previously certified under 
EPA's former certified reference material program may be used for the 
remainder of the cylinder's shelf life.

                           5.2  Concentrations

    Four concentration levels are required as follows.

                     5.2.1  Zero-level Concentration

    0 to 20 percent of span, including span for high scale or both low- 
and high-scale for SO2 and NOx pollutant concentration 
monitors, as appropriate.

                     5.2.2  Low-level Concentration

    20 to 30 percent of span, including span for high scale or both low- 
and high-scale for SO2 and NOx pollutant concentration 
monitors, as appropriate.

                     5.2.3  Mid-level Concentration

    50 to 60 percent of span, including span for high scale or both low- 
and high-scale for SO2 and NOx pollutant concentration 
monitors, as appropriate.

                     5.2.4  High-level Concentration

    80 to 100 percent of span, including span for high scale or both 
low- and high-scale for SO2 and NOx pollutant concentration 
monitors, as appropriate.

                  6. Certification Tests and Procedures

                        6.1  Pretest Preparation

    Install the components of the continuous emission monitoring system 
(i.e., pollutant concentration monitors, CO2 or O2 monitor, 
and flow monitor) as specified in sections 1, 2, and 3 of this appendix, 
and prepare each system component and the combined system for operation 
in accordance with the manufacturer's written instructions. Operate the 
unit(s) during each period when measurements are made. Units may be 
tested on non-consecutive days. To the extent practicable, test the DAHS 
software prior to testing the monitoring hardware.

                          6.2  Linearity Check

    Measure the linearity of each pollutant concentration monitor and 
CO2 or O2 monitor according to the following procedures.
    Challenge each pollutant concentration or CO2 or O2 
monitor with NIST/EPA-approved certified reference material, NIST 
traceable reference material, standard reference material, or Protocol 1 
calibration gases certified to be within 2 percent of the concentration 
specified on the label at the low-, mid-, or high-level concentrations 
specified in section 5.2 of this appendix. For units using emission 
controls and other units using a maximum expected concentration value to 
determine calibration gases, perform a linearity check on both the low- 
and high-scales.
    Introduce the calibration gas at the gas injection port, as 
specified in section 2.2.1 of this appendix. Operate each monitor at its 
normal operating temperature and conditions. For extractive and dilution 
type monitors, pass the calibration gas through all filters, scrubbers, 
conditioners, and other monitor components used during normal sampling 
and through as much of the sampling probe as is practical. For in situ 
type monitors, perform calibration checking all active electronic and 
optical components, including the transmitter, receiver, and analyzer.
    Repeat the procedure for SO2 and NOx pollutant 
concentration monitors using the low-scale for units equipped with 
emission controls with dual span monitors. Challenge the monitor three 
times with each reference gas. Do not use the same gas twice in 
succession. Record the monitor response from the data acquisition and 
handling system (see example data sheet in Figure 1). For each 
concentration, use the average of the responses to determine the error 
in linearity using Equation A-4 in this appendix.
    Linearity checks are acceptable for monitor or monitoring system 
certification if none of the test results exceed the applicable 
performance specifications in section 3.2 of this appendix.

                    6.3  7-Day Calibration Error Test

6.3.1  7-day Calibration Error Test for Pollutant Concentration Monitors 
                    and CO2 and O2 Monitors

    Measure the calibration error of each pollutant concentration 
monitor and CO2 or O2 monitor once each day for 7 consecutive 
operating days according to the following procedures. (In the event that 
extended unit outages occur after the commencement of the test, the 7 
consecutive operating days need not be 7 consecutive calendar days.) 
Units using dual span monitors must perform the calibration error test 
on both high- and low-scales of the pollutant concentration monitor.

    Do not make manual adjustments to the monitor settings during the 7-
day test. If automatic adjustments are made, conduct the calibration 
error test in a way that the magnitude of the adjustments can be 
determined and recorded.
    The calibration error tests should, to the extent practicable, be 
approximately 24

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hours apart (unless the 7-day test is performed over non-consecutive 
days). Perform calibration error tests at two concentrations: (1) Zero-
level and (2) high-level, as specified in section 5.2 of this appendix. 
In addition, repeat the procedure for SO2 and NOx pollutant 
concentration monitors using the low-scale for units equipped with 
emission controls or other units with dual span monitors. Use only NIST 
Traceable Reference Material (NTRM), standard reference material, 
Protocol 1 calibration gases certified by the vendor to be within 2 
percent of the label value, or where applicable, zero ambient air 
material as defined in Sec. 72.2 of this part.
    Introduce the calibration gas at the gas injection port, as 
specified in section 2.2.1 of this appendix. Operate each monitor in its 
normal sampling mode. For extractive and dilution type monitors, pass 
the audit gas through all filters, scrubbers, conditioners, and other 
monitor components used during normal sampling and through as much of 
the sampling probe as is practical. For in situ type monitors, perform 
calibration checking all active electronic and optical components, 
including the transmitter, receiver, and analyzer. Challenge the 
pollutant concentration monitors and CO2 or O2 monitors once 
with each gas. Record the monitor response from the data acquisition and 
handling system. Using Equation A-5 of this appendix, determine the 
calibration error at each concentration once each day (at 24-hour 
intervals) for 7 consecutive days according to the procedures given in 
this section.
    Calibration error tests are acceptable for monitor or monitoring 
system certification if none of these daily calibration error test 
results exceed the applicable performance specifications in section 3.1 
of this appendix. The provisions in this section are suspended from July 
17, 1995 through December 31, 1996.

          6.3.2  7-Day Calibration Error Test for Flow Monitors

    Measure the calibration error of each flow monitor according to the 
following procedures.
    Introduce the reference signal corresponding to the values specified 
in section 2.2.2.1 of this appendix to the probe tip (or equivalent), or 
to the transducer. During the 7-day certification test period, conduct 
the calibration error test once each day while the unit is operating (as 
close to 24-hour intervals as practicable). In the event that extended 
unit outages occur after the commencement of the test, the 7 consecutive 
operating days need not be 7 consecutive calendar days. Record the flow 
monitor responses by means of the data acquisition and handling system. 
Calculate the calibration error using Equation A-6 of this appendix.
    Do not perform any corrective maintenance, repair, replacement or 
manual adjustment upon the flow monitor during the 7-day certification 
test period other than that required in the monitor operation and 
maintenance manual. If the flow monitor operates within the calibration 
error performance specification, (i.e., less than or equal to 3 percent 
error each day and requiring no corrective maintenance, repair, 
replacement or manual adjustment during the 7-day test period) the flow 
monitor passes the calibration error test portion of the certification 
test. Wherever automatic adjustments are made, record the magnitude of 
the adjustments. Record all maintenance and required adjustments. Record 
output readings from the data acquisition and handling system before and 
after all adjustments. The provisions in this section are suspended from 
July 17, 1995 through December 31, 1996.

 6.3.3  Pollutant Concentration Monitor and CO2 or O2 Monitor 
                      7-day Calibration Error Test

    Measure the calibration error of each pollutant concentration 
monitor and CO2 or O2 monitor while the unit is operating once 
each day for 7 consecutive operating days according to the following 
procedures. (In the event that extended unit outages occur after the 
commencement of the test, the 7 consecutive unit operating days need not 
be 7 consecutive calendar days.) Units using dual span monitors must 
perform the calibration error test on both high- and low-scales of the 
pollutant concentration monitor.
    Do not make manual adjustments to the monitor settings until after 
taking measurements at both zero and high concentration levels for that 
day during the 7-day test. If automatic adjustments are made, conduct 
the calibration error test in a way that the magnitude of the 
adjustments can be determined and recorded. Record and report test 
results for each day using the unadjusted concentration or flow rate 
measured in the calibration error test prior to making any manual 
adjustment or resetting the calibration.
    The calibration error tests should be approximately 24 hours apart 
(unless the 7-day test is performed over non-consecutive days). Perform 
calibration error tests at two concentrations: (1) Zero-level and (2) 
high-level, as specified in section 5.2 of this appendix. In addition, 
repeat the procedure for SO2 and NOX pollutant concentration 
monitors using the low-scale for units equipped with emission controls 
or other units with dual span monitors. Use only NIST traceable 
reference material, standard reference material, NIST/EPA-approved 
certified reference material, research gas material, Protocol 1 
calibration gases certified by the vendor to be within 2 percent of the 
label value or zero air material for the zero level only.
    Introduce the calibration gas at the gas injection port, as 
specified in section 2.2.1 of

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this appendix. Operate each monitor in its normal sampling mode. For 
extractive and dilution type monitors, pass the audit gas through all 
filters, scrubbers, conditioners, and other monitor components used 
during normal sampling and through as much of the sampling probe as is 
practical. For in situ type monitors, perform calibration checking all 
active electronic and optical components, including the transmitter, 
receiver, and analyzer. Challenge the pollutant concentration monitors 
and CO2 or O2 monitors once with each gas. Record the monitor 
response from the data acquisition and handling system. Using Equation 
A-5 of this appendix, determine the calibration error at each 
concentration once each day (at 24-hour intervals) for 7 consecutive 
days according to the procedures given in this section.
    Calibration error tests are acceptable for monitor or monitoring 
system certification if none of these daily calibration error test 
results exceed the applicable performance specifications in section 3.1 
of this appendix.

            6.3.4  Flow Monitor 7-day Calibration Error Test

    Measure the calibration error of each flow monitor according to the 
following procedures.
    Introduce the reference signal corresponding to the values specified 
in section 2.2.2.1 of this appendix to the probe tip (or equivalent), or 
to the transducer. During the 7-day certification test period, conduct 
the calibration error test while the unit is operating once each unit 
operating day (as close to 24-hour intervals as practicable). In the 
event that extended unit outages occur after the commencement of the 
test, the 7 consecutive operating days need not be 7 consecutive 
calendar days. Record the flow monitor responses by means of the data 
acquisition and handling system. Calculate the calibration error using 
Equation A-6 of this appendix.
    Do not perform any corrective maintenance, repair, or replacement 
upon the flow monitor during the 7-day certification test period other 
than that required in the quality assurance/quality control (QA/QC) plan 
required by appendix B of this part. Do not make adjustments between the 
zero and high reference level measurements on any day during the 7-day 
test. If the flow monitor operates within the calibration error 
performance specification (i.e., less than or equal to 3 percent error 
each day and requiring no corrective maintenance, repair, or replacement 
during the 7-day test period) the flow monitor passes the calibration 
error test portion of the certification test. Record all maintenance 
activities and the magnitude of any adjustments. Record output readings 
from the data acquisition and handling system before and after all 
adjustments. Record and report all calibration error test results using 
the unadjusted flow rate measured in the calibration error test prior to 
resetting the calibration. Record all adjustments made during the seven 
day period at the time the adjustment is made and report them in the 
certification application.

                   6.4  Cycle Time/Response Time Test

    Perform cycle time/response time tests for each pollutant 
concentration monitor, and continuous emission monitoring system 
according to the following procedures. Use a low-level and a high-level 
calibration gas (as defined in section 5.2 of this appendix) 
alternately. While the monitor or monitoring system is measuring and 
recording the concentration or emission rate, inject either a low-level 
concentration or a high-level concentration calibration gas into the 
injection port. Continue injecting the gas until a stable response is 
reached. Record the amount of time required for the monitor or 
monitoring system to complete 95.0 percent of the concentration or 
emission rate stepchange using data acquisition and handling system 
output. Then repeat the procedure with the other gas. For monitors or 
monitoring systems that perform a series of operations (such as purge, 
sample, and analyze), time the injections of the calibration gases so 
they will produce the longest possible response time. (Note: for the 
NOx continuous emission monitoring system test and SO2-diluent 
continuous emission monitoring system test, it will be necessary to 
simultaneously inject calibration gases into the pollutant and diluent 
monitors, in order to measure the step change in the lb/mmBtu emission 
rate.)
    Cycle time/response time test results are acceptable for monitoring 
or monitoring system certification if none of the response times exceed 
15 min. The provisions in this section 6.4 are suspended from July 17, 
1995 through December 31, 1996.

                         6.4.1  Cycle Time Test

    Perform cycle time tests for each pollutant concentration monitor, 
and continuous emission monitoring system while the unit is operating 
according to the following procedures.
    Use a zero-level and a high-level calibration gas (as defined in 
section 5.2 of this appendix) alternately. To determine the upscale 
elapsed time, inject a zero-level concentration calibration gas into the 
probe tip (or injection port leading to the calibration cell, for in 
situ systems with no probe). Record the stable starting monitor value 
and start time. Next, allow the monitor to measure the concentration of 
flue gas emissions until the response stabilizes. Determine the upscale 
elapsed time as the time at which 95.0 percent of the step change is 
achieved between the stable starting gas value and the stable ending 
monitor value. Record the

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stable ending monitor value, the end time, and the upscale elapsed time 
for the monitor using data acquisition and handling system output. Then 
repeat the procedure, starting by injecting the high-level gas 
concentration to determine the downscale elapsed time, which is the time 
at which 95.0 percent of the step change is achieved between the stable 
starting gas value and the stable ending monitor value. End the 
downscale test by measuring the concentration of flue gas emissions. 
Record the stable starting and ending monitor values, the start and end 
times, and the downscale elapsed time for the monitor using data 
acquisition and handling system output. A stable value is equivalent to 
a reading with a change of less than 1 percent of the span value for 30 
seconds, or a reading with a change of less than 5 percent from the 
measured average concentration over 5 minutes.
    For monitors or monitoring systems that perform a series of 
operations (such as purge, sample, and analyze), time the injections of 
the calibration gases so they will produce the longest possible cycle 
time. Record the span, the zero and high gas concentrations, the start 
and end times, the stable starting and ending monitor values, and the 
upscale and downscale elapsed times. Report the slower of the two 
elapsed times as the cycle time for the analyzer. (See Figure 5 at the 
end of this appendix.) For the NOX continuous emission monitoring 
system test and SO2-diluent continuous emission monitoring system 
test, record and report the longer cycle time of the two component 
analyzers as the system cycle time.
    For time-shared systems, this procedure must be done for all probe 
locations that will be polled within the same 15-minute period during 
monitoring system operations. For cycle time results for a time-shared 
system, add together the longest cycle time obtained from each location. 
Report the sum of the cycle time at each location plus the time required 
for all purge cycles (as determined by the CEMS manufacturer) for each 
location as the cycle time for each and all of those systems. For 
monitors with dual ranges, perform the test on the range giving the 
longest cycle time.
    Cycle time test results are acceptable for monitor or monitoring 
system certification if none of the cycle times exceed 15 minutes.

                  6.5  Relative Accuracy and Bias Tests

    Perform relative accuracy test audits for each CO2 and SO2 
pollutant concentration monitor, each O2 monitor used to calculate 
heat input or CO2 concentration, each SO2-diluent continuous 
emission monitoring system (lb/mmBtu) used by units with a qualifying 
Phase I technology for the period during which the units are required to 
monitor SO2 emission removal efficiency, from January 1, 1997 
through December 31, 1999, flow monitor, and NOX continuous 
emission monitoring system. For monitors or monitoring systems with dual 
ranges, perform the relative accuracy test on one range measuring 
emissions in the stack at the time of testing. Record monitor or 
monitoring system output from the data acquisition and handling system. 
Perform concurrent relative accuracy test audits for each SO2 
pollutant concentration monitor and flow monitor, at least once a year 
(see section 2.3.1 of appendix B of this part), during the flow monitor 
test at the normal operating level specified in section 6.5.2 of this 
appendix. Concurrent relative accuracy test audits may be performed by 
conducting simultaneous SO2 and flow relative accuracy test audit 
runs, or by alternating an SO2 relative accuracy test audit run 
with a flow relative accuracy test audit run until all relative accuracy 
test audit runs are completed. Where two or more probes are in the same 
proximity, care should be taken to prevent probes from interfering with 
each other's sampling. For each SO2 pollutant concentration 
monitor, each flow monitor, and each NOX continuous emission 
monitoring system, calculate bias, as well as relative accuracy, with 
data from the relative accuracy test audits.
    Complete each relative accuracy test audit within a 7-day period 
while the unit (or units, if more than one unit exhausts into the flue) 
is combusting the fuel that is normal for that unit. When relative 
accuracy test audits are performed on continuous emission monitoring 
systems or component(s) on bypass stacks/ducts, use the fuel normally 
combusted by the unit (or units, if more than one unit exhausts into the 
flue) when emissions exhaust through the bypass stack/ducts. Do not 
perform corrective maintenance, repairs, replacements or adjustments 
during the relative accuracy test audit other than as required in the 
operation and maintenance manual.

 6.5.1  SO2, O2 and CO2 Pollutant Concentration Monitors 
and SO2-Diluent and NOX Continuous Emission Monitoring Systems

    Perform relative accuracy test audits for each SO2, O2 or 
CO2 pollutant concentration monitor or NOX continuous emission 
monitoring system or SO2-diluent continuous emission monitoring 
system (lb/mmBtu) used by units with a qualifying Phase I technology for 
the period during which the units are required to monitor SO2 
emission removal efficiency, from January 1, 1997 through December 31, 
1999, at a normal operating level for the unit (or combined units, if 
common stack).

                          6.5.2  Flow Monitors

    Except for flow monitors on bypass stacks/ducts and peaking units, 
perform relative accuracy test audits for each flow monitor at

[[Page 299]]

three different exhaust gas velocities, expressed in terms of percent of 
flow monitor span, or different operating or load levels. For a common 
stack/duct, the three different exhaust gas velocities may be obtained 
from frequently used unit/load combinations for units exhausting to the 
common stack. Select the operating levels as follows: (1) A frequently 
used low operating level selected within the range between the minimum 
safe and stable operating level and 50 percent load, (2) a frequently 
used high operating level selected within the range between 80 percent 
of the maximum operating level and the maximum operating level, and (3) 
the normal operating level. If the normal operating level is within 10.0 
percent of the maximum operating level of either (1) or (2) above, use a 
level that is evenly spaced between the low and high operating levels 
used. The maximum operating level shall be equal to the nameplate 
capacity less any physical or regulatory limitations or other deratings. 
Calculate flow monitor relative accuracy at each of the three operating 
levels. If a flow monitor fails the relative accuracy test on any of the 
three levels of a three-level relative accuracy test audit, the three-
level relative accuracy test audit must be repeated. For flow monitors 
on bypass stacks/ducts and peaking units, the flow monitor relative 
accuracy test audit is required only at the normal operating level.

            6.5.3  CO2 Pollutant Concentration Monitors

    Perform relative accuracy test audits for each CO2 monitor 
(measuring in percent CO2) at a normal operating level for the unit 
(or combined units, if common stack).

                           6.5.4  Calculations

    Using the data from the relative accuracy test audits, calculate 
relative accuracy and bias in accordance with the procedures and 
equations specified in section 7 of this appendix.

              6.5.5  Reference Method Measurement Location

    Select a location for reference method measurements that is (1) 
accessible; (2) in the same proximity as the monitor or monitoring 
system location; and (3) meets the requirements of Performance 
Specification 2 in appendix B of part 60 of this chapter for SO2 
and NOX continuous emission monitoring systems, Performance 
Specification 3 in appendix B of part 60 of this chapter for CO2 or 
O2 monitors, or Method 1 (or 1A) in appendix A of part 60 of this 
chapter for volumetric flow, except as otherwise indicated in this 
section or as approved by the Administrator.

            6.5.6  Reference Method Traverse Point Selection

    Select traverse points that (1) ensure acquisition of representative 
samples of pollutant and diluent concentrations, moisture content, 
temperature, and flue gas flow rate over the flue cross section; and (2) 
meet the requirements of Performance Specification 2 in appendix B of 
part 60 of this chapter (for SO2 and NOX), Performance 
Specification 3 in appendix B of part 60 of this chapter (for O2 
and CO2), Method 1 (or 1A) (for volumetric flow), Method 3 (for 
molecular weight), and Method 4 (for moisture determination) in appendix 
A of part 60 of this chapter.

                        6.5.7  Sampling Strategy

    Conduct the reference method tests so they will yield results 
representative of the pollutant concentration, emission rate, moisture, 
temperature, and flue gas flow rate from the unit and can be correlated 
with the pollutant concentration monitor, CO2 or O2 monitor, 
flow monitor, and SO2 or NOX continuous emission monitoring 
system measurements. Conduct the diluent (O2 or CO2) 
measurements and any moisture measurements that may be needed 
simultaneously with the pollutant concentration and flue gas flow rate 
measurements. If an O2 monitor is used as a CO2 continuous 
emission monitoring system, but not as a diluent monitor, measure 
CO2 with the reference method. To properly correlate individual 
SO2 and CO2 pollutant concentration monitor data, O2 
monitor data, SO2 or NOX continuous emission monitoring system 
data (in lb/mmBtu), and volumetric flow rate data with the reference 
method data, mark the beginning and end of each reference method test 
run (including the exact time of day) on the individual chart 
recorder(s) or other permanent recording device(s).

     6.5.8  Correlation of Reference Method and Continuous Emission 
                            Monitoring System

    Confirm that the monitor or monitoring system and reference method 
test results are on consistent moisture, pressure, temperature, and 
diluent concentration basis (e.g., since the flow monitor measures flow 
rate on a wet basis, Method 2 test results must also be on a wet basis). 
Compare flow-monitor and reference method results on a scfh basis. Also, 
consider the response times of the pollutant concentration monitor, the 
continuous emission monitoring system, and the flow monitoring system to 
ensure comparison of simultaneous measurements.
    For each relative accuracy test audit run, compare the measurements 
obtained from the monitor or continuous emission monitoring system (in 
ppm, percent CO2, lb/mmBtu, or other units) against the 
corresponding reference method values. Tabulate the paired

[[Page 300]]

data in a table such as the one shown in Figure 2.

                 6.5.9  Number of Reference Method Tests

    Perform a minimum of nine sets of paired monitor (or monitoring 
system) and reference method test data for every required (i.e., 
certification, semiannual, or annual) relative accuracy or bias test 
audit. For the certification and annual quality assurance relative 
accuracy test audits for flow monitors, perform a minimum of nine sets 
at each of the three operating levels specified in section 6.5.2 of this 
appendix. Conduct each set within a period of 30 to 60 minutes.

    Note: The tester may choose to perform more than nine sets of 
reference method tests. If this option is chosen, the tester may reject 
a maximum of three sets of the test results as long as the total number 
of test results used to determine the relative accuracy or bias is 
greater than or equal to nine. Report all data, including the rejected 
data, and reference method test results.

                        6.5.10  Reference Methods

    The following methods from appendix A to part 60 of this chapter or 
their approved alternatives are the reference methods for performing 
relative accuracy test audits: Method 1 or 1A for siting; Method 2 (or 
2A, 2C, or 2D) for velocity; Methods 3, 3A, or 3B for O2 or 
CO2; Method 4 for moisture; Methods 6, 6A, or 6C for SO2; 
Methods 7, 7A, 7C, 7D, 7E for NOX, excluding the exception in 
section 5.1.2 of Method 7E. When using Method 7E for measuring NOX 
concentration, total NOX, both NO and NO2, must be measured.

                             7. Calculations

                          7.1  Linearity Check

    Analyze the linearity data for pollutant concentration and CO2 
or O2 monitors as follows. Calculate the percentage error in 
linearity based upon the reference value at the low-level, mid-level, 
and high-level concentrations specified in section 6.2 of this appendix. 
Perform this calculation once during the certification test. Use the 
following equation to calculate the error in linearity for each 
reference value.
[GRAPHIC] [TIFF OMITTED] TC01SE92.114

  
(Eq. A-4)
where,
    LE=Percentage Linearity error, based upon the reference value.
    R=Reference value of Low-, mid-, or high-level calibration gas 
introduced into the monitoring system.
    A=Average of the monitoring system responses.

                         7.2  Calibration Error

           7.2.1  Pollutant Concentration and Diluent Monitors

    For each reference value, calculate the percentage calibration error 
based upon instrument span for daily calibration error tests using the 
following equation:
[GRAPHIC] [TIFF OMITTED] TC01SE92.115

  ......................................................................
(Eq. A-5)
where,
    CE=Percentage Calibration error based upon span of the instrument.
    R=Reference value of zero- or high-level calibration gas introduced 
into the monitoring system.
    A=Actual monitoring system response to the calibration gas.
    S=Span of the instrument, as specified in Section 2 of this 
appendix.

                  7.2.2  Flow Monitor Calibration Error

    For each reference value, calculate the percentage calibration error 
based upon span using the following equation:
[GRAPHIC] [TIFF OMITTED] TR17MY95.007

where:

CE=Calibration error;
R=Low or high level reference value specified in section 2.2.2.1 of this 
          appendix;
A=Actual flow monitor response to the reference value; and
S=Flow monitor span or equivalent reference value (e.g., pressure pulse 
          or electronic signal).

[[Page 301]]

7.3  Relative Accuracy for SO2 and CO2 Pollutant Concentration 
 Monitors, SO2-Diluent Continuous Emission Monitoring Systems, and 
                              Flow Monitors

    Analyze the relative accuracy test audit data from the reference 
method tests for SO2 and CO2 pollutant concentration monitors, 
SO2-diluent continuous emission monitoring systems (lb/mmBtu) used 
by units with a qualifying Phase I technology for the period during 
which the units are required to monitor SO2 emission removal 
efficiency, from January 1, 1997 through December 31, 1999, and flow 
monitors using the following procedures. Summarize the results on a data 
sheet. An example is shown in Figure 2. Calculate the mean of the 
monitor or monitoring system measurement values. Calculate the mean of 
the reference method values. Using data from the automated data 
acquisition and handling system, calculate the arithmetic differences 
between the reference method and monitor measurement data sets. Then 
calculate the arithmetic mean of the difference, the standard deviation, 
the confidence coefficient, and the monitor or monitoring system 
relative accuracy using the following procedures and equations.

                         7.3.1  Arithmetic Mean

    Calculate the arithmetic mean of the differences, d, of a data set 
as follows.
[GRAPHIC] [TIFF OMITTED] TC01SE92.116

  
(Eq. A-7)
where,
    n=Number of data points.

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

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

    When calculating the arithmetic mean of the difference of a flow 
monitor data set, be sure to correct the monitor measurements for 
moisture if applicable.

                        7.3.2  Standard Deviation

    Calculate the standard deviation, Sd, of a data set as follows:
    [GRAPHIC] [TIFF OMITTED] TC01SE92.117
    
  
(Eq. A-8)

                      7.3.3  Confidence Coefficient

    Calculate the confidence coefficient (one-tailed), cc, of a data set 
as follows.
[GRAPHIC] [TIFF OMITTED] TC01SE92.118

  
(eq. A-9)
where,
    t0.025=t value (see Table 7-1).

                           Table 7-1 t-Values                           
------------------------------------------------------------------------
                n-1                   t0.025  n-1  t0.025   n-1   t0.025
------------------------------------------------------------------------
1..................................   12.706   12   2.179     23   2.069
2..................................    4.303   13   2.160     24   2.064
3..................................    3.182   14   2.145     25   2.060
4..................................    2.776   15   2.131     26   2.056
5..................................    2.571   16   2.120     27   2.052
6..................................    2.447   17   2.110     28   2.048
7..................................    2.365   18   2.101     29   2.045
8..................................    2.306   19   2.093     30   2.042
9..................................    2.262   20   2.086     40   2.021
10.................................    2.228   21   2.080     60   2.000
11.................................    2.201   22   2.074    >60   1.960
------------------------------------------------------------------------


                        7.3.4  Relative Accuracy

    Calculate the relative accuracy of a data set using the following 
equation.
[GRAPHIC] [TIFF OMITTED] TC01SE92.119

  
(Eq. A-10)
where,
    RM=Arithmetic mean of the reference method values.
    |d|=The absolute value of the mean difference between the reference 
method values and the corresponding continuous emission monitoring 
system values.
    |cc|=The absolute value of the confidence coefficient.

[[Page 302]]

   7.4  Relative Accuracy for NOx Continuous Emission Monitoring 
                                 Systems

    Analyze the relative accuracy test audit data from the reference 
method tests for NOx continuous emissions monitoring system as 
follows.

                         7.4.1 Data Preparation

    If CNOx, the NOx concentration, is in ppm, multiply it by 
1.194  x  10-7 (lb/dscf)/ppm to convert it to units of lb/dscf. If 
CNOx is in mg/dscm, multiply it by 6.24 x 10-8 (lb/dscf)/(mg/
dscm) to convert it to lb/dscf. Then, use the diluent (O2 or 
CO2) reference method results for the run and the appropriate F or 
Fc factor from Table 1 in Appendix F of this part to convert 
CNOx from lb/dscf to lb/mmBtu units. Use the equations and 
procedure in section 3 of Appendix F to this part, as appropriate.

            7.4.2  NOx Emission Rate (Monitoring System)

    For each test run in a data set, calculate the average NOx 
emission rate (in lb/mmBtu), by means of the data acquisition and 
handling system, during the time period of the test run. Tabulate the 
results as shown in example Figure 4.

                        7.4.3  Relative Accuracy

    Use the equations and procedures in section 7.3 above to calculate 
the relative accuracy for the NOx continuous emission monitoring 
system. In using Equation A-7, ``d'' is, for each run, the difference 
between the NOx emission rate values (in lb/mmBtu) obtained from 
the reference method data and the NOx continuous emission 
monitoring system.

      7.5  Relative Accuracy for Combined SO2/Flow [Reserved]

                  7.6  Bias Test and Adjustment Factor

    Test the relative accuracy test audit data sets for SO2 
pollutant concentration monitors, flow monitors, and NOX continuous 
emission monitoring systems for bias using the procedures outlined 
below.

                         7.6.1  Arithmetic Mean

    Calculate the arithmetic mean of the difference, d, of the data set 
using Equation A-7 of this appendix. To calculate bias for an SO2 
pollutant concentration monitor, ``d'' is, for each paired data point, 
the difference between the SO2 concentration value (in ppm) 
obtained from the reference method and the monitor. To calculate bias 
for a flow monitor, ``d'' is, for each paired data point, the difference 
between the flow rate values (in scfh) obtained from the reference 
method and the monitor. To calculate bias for a NOX continuous 
emission monitoring system, ``d'' is, for each paired data point, the 
difference between the NOX emission rate values (in lb/mmBtu) 
obtained from the reference method and the monitoring system.

                        7.6.2  Standard Deviation

    Calculate the standard deviation, Sd, of the data set using 
Equation A-8.

                      7.6.3  Confidence Coefficient

    Calculate the confidence coefficient, cc, of the data set using 
Equation A-9.

                            7.6.4  Bias Test

    If the mean difference, d, is greater than the absolute value of the 
confidence coefficient, |cc|, the monitor or monitoring system has 
failed to meet the bias test requirement. For flow monitor bias tests, 
if the mean difference, d, is greater than |cc| at the operating level 
closest to normal operating level during the 3-level RATA, the monitor 
has failed to meet the bias test requirement. For flow monitors, apply 
the bias test at the operating level closest to normal operating level 
during the 3-level RATA.

                         7.6.5  Bias Adjustment

    If the monitor or monitoring system fails to meet the bias test 
requirement, adjust the value obtained from the monitor using the 
following equation:
[GRAPHIC] [TIFF OMITTED] TR17MY95.008

Where:

CEMiMonitor=Data (measurement) provided by the monitor at time 
          i.
CEMiAdjusted=Data value, adjusted for bias, at time i.
BAF=Bias adjustment factor, defined by

[[Page 303]]

[GRAPHIC] [TIFF OMITTED] TR17MY95.009


Where:

BAF=Bias adjustment factor, calculated to the nearest thousandth.
d=Arithmetic mean of the difference obtained during the failed bias test 
          using Equation A-7.
CEM=Mean of the data values provided by the monitor during the failed 
          bias test.

    If the bias test is failed by a flow monitor at the operating level 
closest to normal on a 3-level relative accuracy test audit, calculate 
the bias adjustment factor for each of the three operating levels. Apply 
the largest of the three bias adjustment factors to subsequent flow 
monitor data using Equation A-11.
    Apply this adjustment prospectively to all monitor or monitoring 
system data from the date and time of the failed bias test until the 
date and time of a relative accuracy test audit that does not show bias. 
Use the adjusted values in computing substitution values in the missing 
data procedure, as specified in subpart D of this part, and in reporting 
the concentration of SO2, the flow rate, and the average 
NO emission rate and calculated mass emissions of SO2 and 
CO2 during the quarter and calendar year, as specified in subpart G 
of this part.

                                                            Figures for Appendix A of Part 75                                                           
                                                        Figure 1.--Linearity Error Determination                                                        
--------------------------------------------------------------------------------------------------------------------------------------------------------
                   Day                       Date and time     Reference value     Monitor value        Difference         Percent of reference value   
--------------------------------------------------------------------------------------------------------------------------------------------------------
Low-level:                                                                                                                                              
                                                                                                                                                        
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========================================================================================================================================================
Mid-level:                                                                                                                                              
                                                                                                                                                        
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========================================================================================================================================================
High-level:                                                                                                                                             
                                                                                                                                                        
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[[Page 304]]


                  Figure 2.--Relative Accuracy Determination (Pollutant Concentration Monitors)                 
----------------------------------------------------------------------------------------------------------------
                                                SO2 (ppmc)                            CO2 (Pollutant) (ppmc)    
         Run No.           Date and ---------------------------------  Date and --------------------------------
                             time       RMa         Mb        Diff       time       RMa         Mb        Diff  
----------------------------------------------------------------------------------------------------------------
 1......................                                                                                        
----------------------------------------------------------------------------------------------------------------
 2......................                                                                                        
----------------------------------------------------------------------------------------------------------------
 3......................                                                                                        
----------------------------------------------------------------------------------------------------------------
 4......................                                                                                        
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 5......................                                                                                        
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 6......................                                                                                        
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 9......................                                                                                        
----------------------------------------------------------------------------------------------------------------
10......................                                                                                        
----------------------------------------------------------------------------------------------------------------
11......................                                                                                        
----------------------------------------------------------------------------------------------------------------
12......................                                                                                        
----------------------------------------------------------------------------------------------------------------
                                                                                                                
Arithmetic Mean Difference (Eq. A-7). Confidence Coefficient (Eq. A-                                            
                  9). Relative Accuracy (Eq. A-10).                                                             
----------------------------------------------------------------------------------------------------------------
a RM means ``reference method data.''                                                                           
b M means ``monitor data.''                                                                                     
c Make sure the RM and M data are on a consistent basis, either wet or dry.                                     


                                               Figure 3.--Relative Accuracy Determination (Flow Monitors)                                               
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                       Flow rate (Low) (scf/hr)*            Flow rate (Normal) (scf/             Flow rate (High) (scf/ 
                                                Date  ---------------------------   Date              hr)*              Date              hr)*          
                   Run No.                      and                                 and   ---------------------------   and   --------------------------
                                                time      RM       M       Diff     time      RM       M       Diff     time      RM       M       Diff 
--------------------------------------------------------------------------------------------------------------------------------------------------------
 1..........................................                                                                                                            
--------------------------------------------------------------------------------------------------------------------------------------------------------
 2..........................................                                                                                                            
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 3..........................................                                                                                                            
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 4..........................................                                                                                                            
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 5..........................................                                                                                                            
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 6..........................................                                                                                                            
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 7..........................................                                                                                                            
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 8..........................................                                                                                                            
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 9..........................................                                                                                                            
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10..........................................                                                                                                            
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11..........................................                                                                                                            
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12..........................................                                                                                                            
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                                                                                                                        
Arithmetic Mean Difference (Eq. A-7). Confidence Coefficient (Eq. A-9). Relative Accuracy                                                               
                                       (Eq. A-10).                                                                                                      
--------------------------------------------------------------------------------------------------------------------------------------------------------
* Make sure the RM and M data are on a consistent basis, either wet or dry.                                                                             


[[Page 305]]


                    Figure 4.--Relative Accuracy Determination (NOX/Diluent Combined System)                    
----------------------------------------------------------------------------------------------------------------
                                       Reference method data                   NOX system (lb/mmBtu)            
     Run No.       Date and time -------------------------------------------------------------------------------
                                     NOX(  )a         O2/CO2%           RM               M          Difference  
----------------------------------------------------------------------------------------------------------------
  1.............                                                                                                
                                                                                                                
----------------------------------------------------------------------------------------------------------------
  2.............                                                                                                
                                                                                                                
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  3.............                                                                                                
                                                                                                                
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  4.............                                                                                                
                                                                                                                
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  5.............                                                                                                
                                                                                                                
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  6.............                                                                                                
                                                                                                                
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  7.............                                                                                                
                                                                                                                
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  8.............                                                                                                
                                                                                                                
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  9.............                                                                                                
                                                                                                                
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  10............                                                                                                
                                                                                                                
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  11............                                                                                                
                                                                                                                
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  12............                                                                                                
                                                                                                                
----------------------------------------------------------------------------------------------------------------
                                                                                                                
  Arithmetic Mean Difference (Eq. A-7). Confidence Coefficient                                                  
            (Eq. A-9). Relative Accuracy (Eq. A-10).                                                            
----------------------------------------------------------------------------------------------------------------
a Specify units: ppm, lb/dscf, mg/dscm.                                                                         

                          Figure 5--Cycle Time

Date of test____________________________________________________________
Component/system ID#:___________________________________________________
Analyzer type___________________________________________________________
Serial Number___________________________________________________________
High level gas concentration: ______ ppm/% (circle one)
Zero level gas concentration: ______ ppm/% (circle one)
Analyzer span setting: ______ ppm/% (circle one)
Upscale:
    Stable starting monitor value: ______ ppm/% (circle one)
    Stable ending monitor reading: ______ ppm/% (circle one)
    Elapsed time: ______ seconds
Downscale:
    Stable starting monitor value: ______ ppm/% (circle one)
    Stable ending monitor value: ______ ppm/% (circle one)
    Elapsed time: ______ seconds
Component cycle time= ______ seconds
System cycle time= ______ seconds

[58 FR 3701, Jan. 11, 1993, as amended at 60 FR 26541-26546, 26569-
26570, May 17, 1995; 61 FR 25582, May 22, 1996]

    Effective Date Note: At 60 FR 26569, 26570, May 17, 1995, appendix A 
to part 75 was amended by temporarily adding sections 6.3.3, 6.3.4, 
6.4.1 and Figure 5, and by temporarily suspending sections 6.3.1, 6.3.2, 
and 6.4, effective July 17, 1995 through December 31, 1996.

 Appendix B to Part 75--Quality Assurance and Quality Control Procedures

                       1. Quality Control Program

    Develop and implement a quality control program for the continuous 
emission monitoring systems and their components. As a minimum, include 
in each quality control program a written plan that describes in detail 
complete, step-by-step procedures and operations for each of the 
following activities.

       1.1  Calibration Error Test and Linearity Check Procedures

    Identify calibration error test and linearity check procedures 
specific to the continuous emission monitoring system that may require 
variance from the procedures in Appendix A to this part (e.g., how gases 
are to

[[Page 306]]

be injected, adjustments of flow rates and pressures, introduction of 
reference values, length of time for injection of calibration gases, 
steps for obtaining calibration error or error in linearity, 
determination of interferences, and when calibration adjustments should 
be made).

               1.2  Calibration and Linearity Adjustments

    Explain how each component of the continuous emission monitoring 
system will be adjusted to provide correct responses to calibration 
gases, reference values, and/or indications of interference both 
initially and after repairs or corrective action. Identify equations, 
conversion factors, assumed moisture content, and other factors 
affecting calibration of each continuous emission monitoring system.

                       1.3  Preventive Maintenance

    Keep a written record of procedures, including those specified by 
the manufacturers, needed to maintain the continuous emission monitoring 
system in proper operating condition and a schedule for those 
procedures. Include provisions for maintaining an inventory of spare 
parts.

                          1.4  Audit Procedures

    Keep a written record of procedures and details peculiar to the 
installed continuous emission monitoring system that are to be used for 
relative accuracy test audits, such as sampling and analysis methods.

                    1.5  Recordkeeping and Reporting

    Keep a written record describing procedures that will be used to 
implement the recordkeeping and reporting requirements in subparts F and 
G of this part.

                         2. Frequency of Testing

    A summary chart showing each quality assurance test and the 
frequency at which each test is required is located at the end of this 
appendix in Figure 1.

                         2.1  Daily Assessments

    For each monitor or continuous emission monitoring system, perform 
the following assessments during each day in which the unit combusts any 
fuel (hereafter referred to as a ``unit operating day''), or for a 
monitor or continuous emission monitoring system on a bypass stack/duct, 
during each day that emissions pass through the by-pass stack or duct. 
These requirements are effective as of the date when the monitor or 
continuous emission monitoring system completes certification testing. 
The provisions in this section 2.1 are suspended from July 17, 1995 
through December 31, 1996.

 2.1.1  Calibration Error Test for Pollutant Concentration and CO2 
                           or O2 Monitors

    Test, record, and compute the calibration error of each SO2 or 
NOx pollutant concentration and CO2 or O2 monitor at 
least once on each unit operating day, or for monitors or monitoring 
systems on bypass ducts/stacks, on each day that emissions pass through 
the by-pass stack or duct. Conduct calibration error checks, to the 
extent practicable, approximately 24 hours apart. Perform the daily 
calibration error test according to the procedure in Appendix A, section 
6.3.1 of this part.
    For units with add-on emission controls and dual span or auto-
ranging monitors, and other units that use maximum expected 
concentration value to determine calibration gas values, perform the 
daily calibration error test on each scale that has been used since the 
previous calibration error test. For example, if the emissions 
concentration has not exceeded the low-scale span value (based on the 
maximum expected concentration) since the calibration test during the 
previous calendar day, the calibration error test may be performed on 
the low-scale only. If, however, the emissions concentration has 
exceeded the low-scale span value for one hour or longer since the 
previous calibration error test, perform the calibration error on both 
the low- and high-scales.

             2.1.2  Calibration Error Test for Flow Monitors

    Test, compute, and record the calibration error of each flow monitor 
at least once on each unit operating day, or for monitors or monitoring 
systems on bypass ducts/stacks, on each day that emissions pass through 
the by-pass stack or duct. Introduce the reference values (specified in 
section 2.2.2.1 of Appendix A to this part) to the probe tip (or 
equivalent) or to the transducer. Record flow monitor output from the 
data acquisition and handling system before and after any adjustments to 
the flow monitor. Keep a record of all maintenance and adjustments. 
Calculate the calibration error using Equation A-6 in Appendix A of this 
part.

                        2.1.3  Interference Check

    Perform the daily flow monitor interference checks specified in 
section 2.2.2.2 of Appendix A to this part at least once per operating 
day (when the unit(s) operate for any part of the day).

                          2.1.4  Recalibration

    The EPA recommends adjusting the calibration, at a minimum, whenever 
the daily calibration error exceeds the limits of the applicable 
performance specification for the pollutant concentration monitor, 
CO2, or O2 monitor, or flow monitor in appendix A of this 
part.

[[Page 307]]

                      2.1.5  Out-of-Control Period

    An out-of-control period occurs when the calibration error of an 
SO2 or NOx pollutant concentration monitor exceeds 5.0 percent 
based upon the span value (or exceeds 10 ppm, for span values <200 ppm), 
when the calibration error of a diluent gas monitor exceeds 1.0 percent 
O2 or CO2, or when the calibration error of a flow monitor 
exceeds 6.0 percent based upon the span value, which is twice the 
applicable specification of Appendix A of this part. The out-of-control 
period begins with the hour of completion of the failed calibration 
error test and ends with the hour of completion following an effective 
recalibration. Whenever the failed calibration, corrective action, and 
effective recalibration occur within the same hour, the hour is not out 
of control if 2 or more valid readings are obtained during that hour as 
required by Sec. 75.10 of this part. A NOx continuous emission 
monitoring system is considered out-of-control if either component 
monitor exceeds twice the applicable specification in Appendix A of this 
part.
    An out-of-control period also occurs whenever interference of a flow 
monitor is identified. The out-of-control period begins with the hour of 
completion of the failed interference check and ends with the hour of 
completion of an interference check that is passed.

                          2.1.6  Data Recording

    Record and tabulate all calibration error test data according to 
month, day, clock-hour, and magnitude in either ppm, percent volume, or 
scfh. Program monitors that automatically adjust data to the corrected 
calibration values (e.g., microprocessor control) to record either: (1) 
The unadjusted concentration or flow rate measured in the calibration 
error test prior to resetting the calibration, or (2) the magnitude of 
any adjustment. Record the following applicable flow monitor 
interference check data: (1) Sample line/sensing port pluggage, and (2) 
malfunction of each RTD, transceiver, or equivalent.

                        2.1.7  Daily Assessments

    For each monitor or continuous emission monitoring system, perform 
the following assessments during each day in which the unit combusts any 
fuel (hereafter referred to as a ``unit operating day''), or for a 
monitor on a bypass stack/duct, during each day that emissions pass 
through the by-pass stack or duct. If the unit discontinues operation or 
if use of the by-pass stack or duct is discontinued prior to performance 
of the calibration error test, data from the monitor or continuous 
emission monitoring system may be considered quality assured 
prospectively for 24 consecutive clock hours from the time of successful 
completion of the previous daily test performed while the unit is 
operating. These requirements are effective as of the date when the 
monitor or continuous emission monitoring system completes certification 
testing.

                       2.2  Quarterly Assessments

    For each monitor or continuous emission monitoring system, perform 
the following assessments during each unit operating quarter, or for 
monitors or monitoring systems on bypass ducts or bypass stacks, during 
each bypass operating quarter to be performed not less than once every 2 
calendar years. This requirement is effective as of the calendar quarter 
following the calendar quarter in which the monitor or continuous 
emission monitoring system is provisionally certified.

                         2.2.1  Linearity Check

    Perform a linearity check for each SO2 and NO 
pollutant concentration monitor and each CO2 or O2 monitor at 
least once during each unit operating quarter or each bypass operating 
quarter, in accordance with the procedures in appendix A, section 6.2 of 
this part. For units using emission controls and other units using a 
low-scale span value to determine calibration gases, perform a linearity 
check on both the low- and high-scales. Conduct the linearity checks no 
less than 2 months apart, to the extent practicable.

                            2.2.2  Leak Check

    For differential pressure flow monitors, perform a leak check of all 
sample lines (a manual check is acceptable) at least once during each 
unit operating quarter or each bypass operating quarter. Conduct the 
leak checks no less than 2 months apart, to the extent practicable.

                      2.2.3  Out-of-Control Period

    An out-of-control period occurs when the error in linearity at any 
of the three concentrations (six for dual range monitors) in the 
quarterly linearity check exceeds the applicable specification in 
Appendix A, section 3.2 of this part. The out-of-control period begins 
with the hour of the failed linearity check and ends with the hour of a 
satisfactory linearity check following corrective action and/or monitor 
repair. For the NOx continuous emission monitoring system, the 
system is considered out-of-control if either of the component monitors 
exceed the applicable specification in Appendix A, section 3.2 of this 
part. An out-of-control period occurs when a flow monitor sample line 
leak is detected. The out-of-control period begins with the hour of the 
failed leak check and ends with the hour of a satisfactory leak check 
following corrective action.

[[Page 308]]

                 2.3  Semiannual and Annual Assessments

    For each monitor or continuous emission monitoring system, perform 
the following assessments once semiannually (within two calendar 
quarters) or once annually (within four calendar quarters) after the 
calendar quarter in which the monitor or monitoring system was last 
tested, as specified below for the type of test and the performance 
achieved, except as provided below in section 2.3.1 of this appendix for 
monitors or continuous emission monitoring systems on bypass ducts or 
stacks or on peaking units. This requirement is effective as of the 
calendar quarter, unit operating quarter (for peaking units), or bypass 
operating quarter (for bypass stacks or ducts) following the calendar 
quarter in which the monitor or continuous emission monitoring system is 
provisionally certified. A summary chart showing the frequency with 
which a relative accuracy test audit must be performed, depending on the 
accuracy achieved, is located at the end of this appendix in Figure 2.

                   2.3.1  Relative Accuracy Test Audit

    Perform relative accuracy test audits semiannually and, to the 
extent practicable, no less than 4 months apart for each SO2 or 
CO2 pollutant concentration monitor, flow monitor, NO 
continuous emission monitoring system, or SO2-diluent continuous 
emission monitoring systems used by units with a Phase I qualifying 
technology for the period during which the units are required to monitor 
SO2 emission removal efficiency, from January 1, 1997 through 
December 31, 1999, except as provided for monitors or continuous 
emission monitoring systems on peaking units or bypass stacks or ducts. 
For monitors on bypass stacks/ducts, perform relative accuracy test 
audits no less than once every two successive bypass operating quarters, 
or once every two calendar years, whichever occurs first, in accordance 
with the procedures in section 6.5 of Appendix A of this part. For 
monitors on peaking units, perform relative accuracy test audits no less 
than once every two successive unit operating quarters, or once every 
two calendar years, whichever occurs first. Audits required under this 
section shall be performed no less than 4 months apart, to the extent 
practicable. The audit frequency may be reduced, as specified below for 
monitors or monitoring systems which qualify for less frequent testing.
    For flow monitors, one-level and three-level relative accuracy test 
audits shall be performed alternately (when a flow RATA is conducted 
semiannually), such that the three-level relative accuracy test audit is 
performed at least once annually. The three-level audit shall be 
performed at the three different operating or load levels specified in 
appendix A, section 6.5.2 of this part, and the one-level audit shall be 
performed at the normal operating or load level. Notwithstanding that 
requirement, relative accuracy test audits need only be performed at the 
normal operating or load level for monitors and continuous emission 
monitoring systems on peaking units and bypass stacks/ducts.
    Relative accuracy test audits may be performed on an annual basis 
rather than on a semiannual basis (or for monitors on peaking units and 
bypass ducts or bypass stacks, no less than (1) once every four 
successive unit or bypass operating quarters, or (2) every two calendar 
years, whichever occurs first) under any of the following conditions: 
(1) The relative accuracy during the previous audit for an SO2 or 
CO2 pollutant concentration monitor (including an O2 pollutant 
monitor used to measure CO2 using the procedures in appendix F of 
this part), or for a NO or SO2-diluent continuous 
emissions monitoring system is 7.5 percent or less; (2) prior to January 
1, 2000, the relative accuracy during the previous audit for a flow 
monitor is 10.0 percent or less at each operating level tested; (3) on 
and after January 1, 2000, the relative accuracy during the previous 
audit for a flow monitor is 7.5 percent or less at each operating level 
tested; (4) on low flow (10.0 fps) stacks/ducts, when the 
monitor mean, calculated using Equation A-7 in appendix A of this part 
is within 1.5 fps of the reference method mean or achieves a 
relative accuracy of 7.5 percent (10 percent if prior to January 1, 
2000) or less during the previous audit; (5) on low SO2 emitting 
units (SO2 concentrations 250.0 ppm, or equivalent lb/
mmBtu value for SO2-diluent continuous emission monitoring 
systems), when the monitor mean is within 8.0 ppm (or 
equivalent in lb/mmBtu for SO2-diluent continuous emission 
monitoring systems) of the reference method mean or achieves a relative 
accuracy of 7.5 percent or less during the previous audit; or (6) on low 
NOX emitting units (NOX emission rate 0.20 lb/
mmBtu), when the NO continuous emission monitoring system 
achieves a relative accuracy of 7.5 percent or less or when the 
monitoring system mean, calculated using Equation A-7 in appendix A of 
this part is within 0.01 lb/mmBtu of the reference method 
mean.
    A maximum of two relative accuracy test audit trials may be 
performed for the purpose of achieving the results required to qualify 
for less frequent relative accuracy test audits. Whenever two trials are 
performed, the results of the second (later) trial must be used in 
calculating both the relative accuracy and bias.

                      2.3.2  Out-of-Control Period

    An out-of-control period occurs under any of the following 
conditions: (1) The relative accuracy of an SO2, CO2, or 
O2 pollutant concentration monitor or a NOX or SO2-
diluent

[[Page 309]]

continuous emission monitoring system exceeds 10.0 percent; (2) prior to 
January 1, 2000, the relative accuracy of a flow monitor exceeds 15.0 
percent; (3) on and after January 1, 2000, the relative accuracy of a 
flow monitor exceeds 10.0 percent; (4) for low flow situations 
(10.0 fps), the flow monitor mean value (if applicable) 
exceeds 2.0 fps of the reference method mean whenever the 
relative accuracy is greater than 15.0 percent for Phase I or 10 percent 
for Phase II; (5) for low SO2 emitter situations, the monitor mean 
values exceeds 15.0 ppm (or  0.03 lb/mmBtu for 
SO2-diluent continuous emission monitoring systems from January 1, 
1997 through December 31, 1999) of the reference method mean whenever 
the relative accuracy is greater than 10.0 percent; or (6) for low 
NOX emitting units (NOX emission rate 0.2 lb/
mmBtu), the NOX continuous emission monitoring system mean values 
exceed 0.02 lb/mmBtu of the reference method mean whenever 
the relative accuracy is greater than 10.0 percent. For SO2, 
CO2, O2, NOX emission rate, and flow relative accuracy 
test audits performed at only one level, the out-of-control period 
begins with the hour of completion of the failed relative accuracy test 
audit and ends with the hour of completion of a satisfactory relative 
accuracy test audit. For a flow relative accuracy test audit at 3 
operating levels, the out-of-control period begins with the hour of 
completion of the first failed relative accuracy test audit at any of 
the three operating levels, and ends with the hour of completion of a 
satisfactory three-level relative accuracy test audit.
    Failure of the bias test does not result in the system or monitor 
being out-of-control.

                      2.3.3  Bias Adjustment Factor

    2.3.3  Bias Adjustment Factor. If an SO2 pollutant 
concentration monitor, flow monitor, or NOx continuous emission 
monitoring system fails the bias test specified in Section 7.6 of 
Appendix A of this part, use the bias adjustment factor given in 
Equations A-11 and A-12 of Appendix A of this part to adjust the 
monitored data.

                            2.4  Other Audits

    Affected units may be subject to relative accuracy test audits at 
any time. If a monitor or continuous emission monitoring system fails 
the relative accuracy test during the audit, the monitor or continuous 
emission monitoring system shall be considered to be out-of-control 
beginning with the date and time of completion of the audit, and 
continuing until a successful audit test is completed following 
corrective action. If a monitor or monitoring system fails the bias test 
during an audit, use the bias adjustment factor given by Equations A-11 
and A-12 in Appendix A to this part to adjust the monitored data. Apply 
this adjustment factor from the date and time of completion of the audit 
until the date and time of completion of a relative accuracy test audit 
that does not show bias.

             Figure 1.--Quality Assurance Test Requirements             
------------------------------------------------------------------------
                                     QA test frequency requirements     
             Test              -----------------------------------------
                                   Daily*      Quarterly*    Semiannual*
------------------------------------------------------------------------
Calibration Error (2 pt.).....      .............  ............
Interference (flow)...........      .............  ............
Leak (flow)                     ...........        ............
Linearity (3 pt.)               ...........        ............
RATA (SO2, NOx, CO2)\1\.......  ...........  .............     
RATA (flow, alternating 1-load  ...........  .............     
 and 3-load)\2\.                                                        
------------------------------------------------------------------------
* For monitors on bypass stack/duct, bypass operating days or quarters, 
  only.                                                                 
\1\ Conduct annually, if monitor meets accuracy requirements to qualify 
  for less frequent testing.                                            
\2\ Conduct 3-load RATAs annually, if requirements to qualify for less  
  frequent testing are met.                                             



                          Figure 2.--Relative Accuracy Test Frequency Incentive System                          
----------------------------------------------------------------------------------------------------------------
                RATA                  Semiannually\1\ (percent)                      Annual\1\                  
----------------------------------------------------------------------------------------------------------------
SO2................................  RA  10            RA  7.5% or 8.0 ppm.\2\
NOX................................  RA  10            RA  7.5% or 0.01 lb/   
                                                                   mmBtu.\2\                                    
Flow (Phase I)\3\..................  RA  15            RA  10% or  1.5 fps.\2\
Flow (Phase II)\3\.................  RA  10            RA  7.5% or  1.5       
                                                                   fps.\2\                                      
CO2/O2.............................  RA  10            RA  7.5%.                          
----------------------------------------------------------------------------------------------------------------
\1\ For monitors on bypass stack/duct, bypass operating quarters, not to exceed two calendar years. For monitors
  on peaking units, unit operating quarters, not to exceed two calendar years.                                  
\2\ The difference between monitor and reference method mean values; low emitters or low flow, only.            
\3\ Conduct 3-load RATAs annually, if requirements to qualify for less frequent testing are met.                


[58 FR 3701, Jan. 11, 1993, as amended at 60 FR 26546, 26571, May 17, 
1995]

    Effective Date Note: At 60 FR 26571, May 17, 1995, appendix B to 
part 75 was amended by temporarily suspending section 2.1 and

[[Page 310]]

temporarily adding section 2.1.7, effective July 17, 1995 through 
December 31, 1996.

        Appendix C to Part 75--Missing Data Estimation Procedures

1. Parametric Monitoring Procedure for Missing SO2 Concentration or 
                       NOX Emission Rate Data

                           1.1  Applicability

    The owner or operator of any affected unit equipped with post-
combustion SO2 or NOx emission controls and SO2 pollutant 
concentration monitors and/or NOx continuous emission monitoring 
systems at the inlet and outlet of the emission control system may apply 
to the Administrator for approval and certification of a parametric, 
empirical, or process simulation method or model for calculating 
substitute data for missing data periods. Such methods may be used to 
parametrically estimate the removal efficiency of the SO2 of 
postcombustion NOx emission controls which, with the monitored 
inlet concentration or emission rate data, may be used to estimate the 
average concentration of SO2 emissions or average emission rate of 
NOx discharged to the atmosphere. After approval by the 
Administrator, such method or model may be used for filling in missing 
SO2 concentration or NOx emission rate data when data from the 
outlet SO2 pollutant concentration monitor or outlet NOx 
continuous emission monitoring system have been reported with an annual 
monitor data availability of 90.0 percent or more.
    Base the empirical and process simulation methods or models on the 
fundamental chemistry and engineering principles involved in the 
treatment of pollutant gas. On a case-by-case basis, the Administrator 
may pre-certify commercially available process simulation methods and 
models.

                       1.2  Petition Requirements

    Continuously monitor, determine, and record hourly averages of the 
estimated SO2 or NOX removal efficiency and of the parameters 
specified below, at a minimum. The affected facility shall supply 
additional parametric information where appropriate. Measure the 
SO2 concentration or NOX emission rate, removal efficiency of 
the add-on emission controls, and the parameters for at least 2160 unit 
operating hours. Provide information for all expected operating 
conditions and removal efficiencies. At least 4 evenly spaced data 
points are required for a valid hourly average, except during periods of 
calibration, maintenance, or quality assurance activities, during which 
2 data points per hour are sufficient. The Administrator will review all 
applications on a case-by-case basis.
    1.2.1  Parameters for Wet Flue Gas Desulfurization System
    1.2.1.1  Number of scrubber modules in operation.
    1.2.1.2  Total slurry rate to each scrubber module (gal per min).
    1.2.1.3  In-line absorber pH of each scrubber module.
    1.2.1.4  Pressure differential across each scrubber module (inches 
of water column).
    1.2.1.5  Unit load (MWe).
    1.2.1.6  Inlet and outlet SO2 concentration as determined by 
the monitor or missing data substitution procedures.
    1.2.1.7  Percent solids in slurry for each scrubber module.
    1.2.1.8  Any other parameters necessary to verify scrubber removal 
efficiency, if the Administrator determines the parameters above are not 
sufficient.
    1.2.2  Parameters for Dry Flue Gas Desulfurization System
    1.2.2.1  Number of scrubber modules in operation.
    1.2.2.2  Atomizer slurry flow rate to each scrubber module (gal per 
min).
    1.2.2.3  Inlet and outlet temperature for each scrubber module 
( deg.F).
    1.2.2.4  Pressure differential across each scrubber module (inches 
of water column).
    1.2.2.5  Unit load (MWe).
    1.2.2.6  Inlet and outlet SO2 concentration as determined by 
the monitor or missing data substitution procedures.
    1.2.2.7  Any other parameters necessary to verify scrubber removal 
efficiency, if the Administrator determines the parameters above are not 
sufficient.

      1.2.3  Parameters for Other Flue Gas Desulfurization Systems

    If SO2 control technologies other than wet or dry lime or 
limestone scrubbing are selected for flue gas desulfurization, a 
corresponding empirical correlation or process simulation parametric 
method using appropriate parameters may be developed by the owner or 
operator of the affected unit, and then reviewed and approved or 
modified by the Administrator on a case-by-case basis.

    1.2.4  Parameters for Post-Combustion NOx Emission Controls

    1.2.4.1  Inlet air flow rate to the unit (boiler) (mcf/hr).
    1.2.4.2  Excess oxygen concentration of flue gas at stack outlet 
(percent).
    1.2.4.3  Carbon monoxide concentration of flue gas at stack outlet 
(ppm).
    1.2.4.4  Temperature of flue gas at outlet of the unit ( deg.F).
    1.2.4.5  Inlet and outlet NOx emission rate as determined by 
the NOx continuous emission monitoring system or missing data 
substitution procedures.

[[Page 311]]

    1.2.4.6  Any other parameters specific to the emission reduction 
process necessary to verify the NOx control removal efficiency, 
(e.g., reagent feedrate in gal/mi).

              1.3  Correlation of Emissions With Parameters

    Establish a method for correlating hourly averages of the parameters 
identified above with the percent removal efficiency of the SO2 or 
post-combustion NOX emission controls under varying unit operating 
loads. Equations 1-7 in Sec. 75.15 may be used to estimate the percent 
removal efficiency of the SO2 emission controls on an hourly basis.
    Each parametric data substitution procedure should develop a data 
correlation procedure to verify the performance of the SO2 emission 
controls or post-combustion NOx emission controls, along with the 
SO2 pollutant concentration monitor and NOx continuous 
emission monitoring system values for varying unit load ranges.
    For NOx emission rate data, and wherever the performance of the 
emission controls varies with the load, use the load range procedure 
provided in section 2.2 of this appendix.

                            1.4  Calculations

    1.4.1  Use the following equation to calculate substitute data for 
filling in missing (outlet) SO2 pollutant concentration monitor 
data.

Mo = Ic (1-E)
(Eq. C-1)

where,
Mo = Substitute data for outlet SO2 concentration, ppm.
Ic = Recorded inlet SO2 concentration, ppm.
E = Removal efficiency of SO2 emission controls as determined by 
          the correlation procedure described in section 1.3 of this 
          appendix.

    1.4.2  Use the following equation to calculate substitute data for 
filling in missing (outlet) NOx emission rate data.

Mo = Ic (1-E)
(Eq. C-2)

where,
Mo = Substitute data for outlet NOx emission rate, lb/mmBtu.
Ic = Recorded inlet NOx emission rate, lb/mmBtu.
 E = Removal efficiency of post-combustion NOx emission controls 
          determined by the correlation procedure described in section 
          1.3 of this appendix.

                            1.5  Missing Data

    1.5.1  If both the inlet and the outlet SO2 pollutant 
concentration monitors are unavailable simultaneously, use the maximum 
inlet SO2 concentration recorded by the inlet SO2 pollutant 
concentration monitor during the previous 720 quality assured monitor 
operating hours to substitute for the inlet SO2 concentration in 
Equation C-1 of this appendix.
    1.5.2  If both the inlet and outlet NOx continuous emission 
monitoring systems are unavailable simultaneously, use the maximum inlet 
NOx emission rate for the corresponding unit load recorded by the 
NOx continuous emission monitoring system at the inlet during the 
previous 2160 quality assured monitor operating hours to substitute for 
the inlet NOx emission rate in Equation C-2 of this Appendix.

                            1.6  Application

    Apply to the Administrator for approval and certification of the 
parametric substitution procedure for filling in missing SO2 
concentration or NOx emission rate data using the established 
criteria and information identified above. DO not use this procedure 
until approved by the Administrator.

2. Load-Based Procedure for Missing Flow Rate and NOx Emission Rate 
                                  Data

                           2.1  Applicability

    This procedure is applicable for data from all affected units for 
use in accordance with the provisions of this part to provide substitute 
data for volumetric flow (scfh) and NOx emission rate (in lb/
mmBtu).

                             2.2  Procedure

    2.2.1  For a single unit, establish 10 operating load ranges defined 
in terms of percent of the maximum hourly gross load of the unit, in 
gross megawatts (MWge), as shown in Table C-1. For units sharing a 
common stack monitored with a single flow monitor, the load ranges for 
flow (but not for NOX) may be broken down into 20 equally-sized 
operating load ranges in increments of 5 percent of the combined maximum 
hourly gross load of all units utilizing the common stack. For a 
cogenerating unit or other unit at which some portion of the heat input 
is not used to produce electricity or for a unit for which hourly gross 
load in MWge is not recorded separately, use the hourly gross steam load 
of the unit, in pounds of steam per hour at the measured temperature 
( deg.F) and pressure (psia) instead of MWge. Indicate a change in the 
number of load ranges or the units of loads to be used in the 
precertification section of the monitoring plan.

     Table C-1.--Definition of Operating Load Ranges for Load-Based     
                      Substitution Data Procedures                      
------------------------------------------------------------------------
                                                            Percent of  
                  Operating load range                    maximum hourly
                                                          gross load (%)
------------------------------------------------------------------------
1.......................................................            0-10

[[Page 312]]

                                                                        
2.......................................................           10-20
3.......................................................           20-30
4.......................................................           30-40
5.......................................................           40-50
6.......................................................           50-60
7.......................................................           60-70
8.......................................................           70-80
9.......................................................           80-90
10......................................................          90-100
------------------------------------------------------------------------


    2.2.2  Beginning with the first hour of unit operation after 
installation and certification of the flow monitor or the NOx 
continuous emission monitoring system, for each hour of unit operation 
record a number, 1 through 10 (or 1 through 20 for flow at common 
stacks), that identifies the operating load range corresponding to the 
integrated hourly gross load of the unit(s) recorded for each unit 
operating hour.
    2.2.3  Beginning with the first hour of unit operation after 
installation and certification of the flow monitor or the NOX 
continuous emission monitoring system and continuing thereafter, the 
data acquisition and handling system must be capable of calculating and 
recording the following information for each unit operating hour of 
missing flow or NOX data within each identified load range during 
the shorter of: (1) the previous 2,160 quality assured monitor operating 
hours (on a rolling basis), or (2) all previous quality assured monitor 
operating hours.
    2.2.3.1  Average of the hourly flow rates reported by a flow 
monitor, in scfh.
    2.2.3.2  The 90th percentile value of hourly flow rates, in scfh.
    2.2.3.3  The 95th percentile value of hourly flow rates, in scfh.
    2.2.3.4  The maximum value of hourly flow rates, in scfh.
    2.2.3.5  Average of the hourly NOX emission rate, in lb/mmBtu, 
reported by a NOX continuous emission monitoring system.
    2.2.3.6  The 90th percentile value of hourly NOx emission 
rates, in lb/mmBtu.
    2.2.3.7  The 95th percentile value of hourly NOx emission 
rates, in lb/mmBtu.
    2.2.3.8  The maximum value of hourly NOx emission rates, in lb/
mmBtu.
    2.2.4  Calculate all monitor or continuous emission monitoring 
system data averages, maximum values, and percentile values determined 
by this procedure using bias adjusted values in the load ranges.
    2.2.5  When a bias adjustment is necessary for the flow monitor and/
or the NOX continuous emission monitoring system, apply the 
adjustment factor to all monitor or continuous emission monitoring 
system data values placed in the load ranges.
    2.2.6  Use the calculated monitor or monitoring system data 
averages, maximum values, and percentile values to substitute for 
missing flow rate and NOx emission rate data according to the 
procedures in subpart D of this part.

[58 FR 3701, Jan. 11, 1993, as amended at 60 FR 26547, 26548, May 17, 
1995]

  Appendix D to Part 75--Optional SO2 Emissions Data Protocol for 
                      Gas-Fired and Oil-Fired Units

                            1. Applicability

    1.1  This protocol may be used in lieu of continuous SO2 
pollutant concentration and flow monitors for the purpose of determining 
hourly SO2 emissions and heat input from: (1) gas-fired units as 
defined in Sec. 72.2 of this chapter; or (2) oil-fired units as defined 
in Sec. 72.2 of this chapter. This optional SO2 emissions data 
protocol contains procedures for conducting oil sampling and analysis in 
section 2.2 of this appendix; the procedures for flow proportional oil 
sampling and the procedures for manual daily oil sampling may be used 
for any gas-fired unit or oil-fired unit. In addition, this optional 
SO2 emissions data protocol contains two procedures for determining 
SO2 emissions due to the combustion of gaseous fuels; these two 
procedures may be used for any gas-fired unit or oil-fired unit.
    1.2  Pursuant to the procedures in Sec. 75.20, complete all testing 
requirements to certify use of this protocol in lieu of a flow monitor 
and an SO2 continuous emission monitoring system. Complete all 
testing requirements no later than the applicable deadline specified in 
Sec. 75.4. Apply to the Administrator for initial certification to use 
this protocol no later than 45 days after the completion of all 
certification tests. Whenever the monitoring method is to be changed, 
reapply to the Administrator for recertification of the new monitoring 
method.

                              2. Procedure

                       2.1  Flowmeter Measurements

    For each hour when the unit is combusting fuel, measure and record 
the flow of fuel combusted by the unit, except as provided for gas in 
section 2.1.4 of this appendix. Measure the flow of fuel with an in-line 
fuel flowmeter and automatically record the data with a data acquisition 
and handling system, except as provided in section 2.1.4 of this 
appendix.
    2.1.1  Measure the flow of each fuel entering and being combusted by 
the unit. If a portion of the flow is diverted from the unit without 
being burned, and that diversion occurs downstream of the fuel 
flowmeter, an

[[Page 313]]

additional in-line fuel flowmeter is required to account for the 
unburned fuel. Record the flow of each fuel combusted by the unit as the 
difference between the flow measured in the pipe leading to the unit and 
the flow in the pipe diverting fuel away from the unit.
    2.1.2  Install and use fuel flowmeters meeting the requirements of 
this appendix in a pipe going to each unit, or install and use a fuel 
flowmeter in a common pipe header (i.e., a pipe carrying fuel for 
multiple units). If the flowmeter is installed in a common pipe header, 
do one of the following:
    2.1.2.1  Measure the fuel flow in the common pipe and combine 
SO2 mass emissions for the affected units for recordkeeping and 
compliance purposes; or
    2.1.2.2  Provide information satisfactory to the Administrator on 
methods for apportioning SO2 mass emissions and heat input to each 
of the affected units demonstrating that the method ensures complete and 
accurate accounting of all emissions regulated under this part. The 
information shall be provided to the Administrator through a petition 
submitted by the designated representative under Sec. 75.66. 
Satisfactory information includes apportionment using fuel flow 
measurements, the ratio of load (in MWe) in each unit to the total load 
for all units receiving fuel from the common pipe header, or the ratio 
of steam flow (in 1000 lb/hr) at each unit to the total steam flow for 
all units receiving fuel from the common pipe header.
    2.1.3  For a gas-fired unit or an oil-fired unit that continuously 
or frequently combusts a supplemental fuel for flame stabilization or 
safety purposes, measure the flow of the supplemental fuel with a fuel 
flowmeter meeting the requirements of this appendix.
    2.1.4  For an oil-fired unit that uses gas solely for start-up or 
burner ignition or a gas-fired unit that uses oil solely for start-up or 
burner ignition a flowmeter for the start-up fuel is not required. 
Estimate the volume of oil combusted for each start-up or ignition, 
either by using a fuel flowmeter or by using the dimensions of the 
storage container and measuring the depth of the fuel in the storage 
container before and after each start-up or ignition. A fuel flowmeter 
used solely for start-up or ignition fuel is not subject to the 
calibration requirements of section 2.1.5 and 2.1.6 of this appendix. 
Gas combusted solely for start-up or burner ignition does not need to be 
measured separately.
    2.1.5  Each fuel flowmeter used to meet the requirements of this 
protocol shall meet a flowmeter accuracy of 2.0 percent of 
the upper range value (i.e, maximum calibrated fuel flow rate), either 
by design or as calibrated and as measured under laboratory conditions 
by the manufacturer, by an independent laboratory, or by the owner or 
operator. The flowmeter accuracy must include all error from all parts 
of the fuel flowmeter being calibrated based upon the contribution to 
the error in the flowrate.
    2.1.5.1  Use the procedures in the following standards for flowmeter 
calibration or flowmeter design, as appropriate to the type of 
flowmeter: ASME MFC-3M-1989 with September 1990 Errata (``Measurement of 
Fluid Flow in Pipes Using Orifice, Nozzle, and Venturi''), ASME MFC-4M-
1986 (Reaffirmed 1990), ``Measurement of Gas Flow by Turbine Meters,'' 
American Gas Association Report No. 3, ``Orifice Metering of Natural Gas 
and Other Related Hydrocarbon Fluids Part 1: General Equations and 
Uncertainty Guidelines'' (October 1990 Edition), Part 2: ``Specification 
and Installation Requirements'' (February 1991 Edition) and Part 3: 
``Natural Gas Applications'' (August 1992 edition), (excluding the 
modified flow-calculation method in Part 3) ASME MFC-5M-1985 
(``Measurement of Liquid Flow in Closed Conduits Using Transit-Time 
Ultrasonic Flowmeters''), ASME MFC-6M-1987 with June 1987 Errata 
(``Measurement of Fluid Flow in Pipes Using Vortex Flow Meters''), ASME 
MFC-7M-1987 (Reaffirmed 1992), ``Measurement of Gas Flow by Means of 
Critical Flow Venturi Nozzles,'' ISO 8316: 1987(E) ``Measurement of 
Liquid Flow in Closed Conduits--Method by Collection of the Liquid in a 
Volumetric Tank,'' or MFC-9M-1988 with December 1989 Errata 
(``Measurement of Liquid Flow in Closed Conduits by Weighing Method'') 
for all other flow meter types (incorporated by reference under 
Sec. 75.6 of this part). The Administrator may also approve other 
procedures that use equipment traceable to National Institute of 
Standards and Technology (NIST) standards. Document other procedures, 
the equipment used, and the accuracy of the procedures in the monitoring 
plan for the unit and a petition submitted by the designated 
representative under Sec. 75.66(c). If the flowmeter accuracy exceeds 
2.0 percent of the upper range value, the flowmeter does not 
qualify for use under this part.
    2.1.5.2  Alternatively, a fuel flowmeter used for the purposes of 
this part may be calibrated or recalibrated at least annually (or, for 
fuel flowmeters measuring emergency fuel, backup fuel or fuel usage of 
peaking units, every four calendar quarters when the unit combusts the 
fuel measured by the fuel flowmeter) by comparing the measured flow of a 
flowmeter to the measured flow from another flowmeter which has been 
calibrated or recalibrated during the previous 365 days using a standard 
listed in section 2.1.5 of this appendix or other procedure approved by 
the Administrator under Sec. 75.66. Any secondary elements, such as 
pressure and temperature transmitters, must be calibrated immediately 
prior to the comparison. Perform the comparison over a period of no more 
than seven consecutive unit operating days. Compare the average of three 
fuel flow

[[Page 314]]

readings for each meter at each of three different flow levels, 
corresponding to (1) normal full operating load, (2) normal minimum 
operating load, and (3) a load point approximately equally spaced 
between the full and minimum operating loads. Calculate the flowmeter 
accuracy at each of the three flow levels using the following equation:
[GRAPHIC] [TIFF OMITTED] TR17MY95.010

Where:

ACC=Flow meter accuracy as a percentage of the upper range value, 
          including all error from all parts of both flowmeters.
R=Average of the three flow measurements of the reference flow meter.
A=Average of the three measurements of the flow meter being tested.
URV=Upper range value of fuel flow meter being tested (i.e. maximum 
          measurable flow).

    If the flow meter accuracy exceeds 2.0 percent of the 
upper range value at any of the three flow levels, either recalibrate 
the flow meter until the accuracy is within the performance 
specification, or replace the flow meter with another one that is within 
the performance specification. Notwithstanding the requirement for 
annual calibration of the reference flowmeter, if a reference flowmeter 
and the flowmeter being tested are within 1.0 percent of the 
flowrate of each other during all in-place calibrations in a calendar 
year, then the reference flowmeter does not need to be calibrated before 
the next in-place calibration. This exception to calibration 
requirements for the reference flowmeter may be extended for periods up 
to five calendar years.

                        2.1.6  Quality Assurance

    2.1.6.1  Recalibrate each fuel flowmeter to a flowmeter accuracy of 
2.0 percent of the upper range value prior to use under this 
part at least annually (or, for fuel flowmeters measuring emergency 
fuel, backup fuel or fuel usage of peaking units, every four calendar 
quarters when the unit combusts the fuel measured by the fuel 
flowmeter), or more frequently if required by manufacturer 
specifications. Perform the recalibration using the procedures in 
section 2.1.5 of this appendix. For orifice-, nozzle-, and venturi-type 
flowmeters, also recalibrate the flowmeter the following calendar 
quarter using the procedures in section 2.1.6.2 of this appendix, 
whenever the fuel flowmeter accuracy during a calibration or test is 
greater than 1.0 percent of the upper range value, or 
whenever a visual inspection of the orifice, nozzle, or venturi 
identifies corrosion since the previous visual inspection.
    2.1.6.2  For orifice-, nozzle-, and venturi-type flowmeters that are 
designed according to the standards in section 2.1.5 of this appendix, 
satisfy the calibration requirements of this appendix by calibrating the 
differential pressure transmitter or transducer, static pressure 
transmitter or transducer, and temperature transmitter or transducer, as 
applicable, using equipment that has a current certificate of 
traceability to NIST standards. In addition, conduct a visual inspection 
of the orifice, nozzle, or venturi at least annually.

                     2.2  Oil Sampling and Analysis

    Perform sampling and analysis of as-fired oil to determine the 
percentage of sulfur by weight in the oil.
    2.2.1  When combusting diesel fuel, sample the diesel fuel either 
(1) every day the unit combusts diesel fuel, or (2) upon receipt of a 
shipment of diesel fuel.
    2.2.1.1  If the diesel fuel is sampled every day, use either the 
flow proportional method described in section 2.2.3 of this appendix or 
the daily manual method described in section 2.2.4 of this appendix.
    2.2.1.2  If the diesel fuel is sampled upon delivery, calculate 
SO2 emissions using the highest sulfur content of any oil supply 
combusted in the previous 30 days that the unit combusted oil. Diesel 
fuel sampling and analysis may be performed either by the owner or 
operator of an affected unit, an outside laboratory, or a fuel supplier, 
provided that sampling is performed according to ASTM D4057-88, 
``Standard Practice for Manual Sampling of Petroleum and Petroleum 
Products'' (incorporated by reference under Sec. 75.6 of this part).
    2.2.2  Perform oil sampling every day the unit is combusting oil 
except as provided for diesel fuel. Use either the flow proportional 
method described in section 2.2.3 of this appendix or the daily manual 
method described in section 2.2.4 of this appendix.
    2.2.3  Conduct flow proportional oil sampling or continuous drip oil 
sampling in accordance with ASTM D4177-82 (Reapproved 1990), ``Standard 
Practice for Automatic Sampling of Petroleum and Petroleum Products'' 
(incorporated by reference under Sec. 75.6), every day the unit is 
combusting oil. Extract oil at least once every hour and blend into a 
daily composite sample. The sample composite period may not exceed 24 
hr.
    2.2.4  Representative as-fired oil samples may be taken manually 
every day that the unit combusts oil according to ASTM D4057-88, 
``Standard Practice for Manual Sampling of Petroleum and Petroleum 
Products'' (incorporated by reference under Sec. 75.6), provided that 
the highest fuel sulfur content recorded at that unit from the most 
recent 30 daily samples is used for the purposes of calculating SO2 
emissions under section 3 of

[[Page 315]]

this appendix. Use the gross calorific value measured from that day's 
sample to calculate heat input. If oil supplies with different sulfur 
contents are combusted on the same day, sample the highest sulfur fuel 
combusted that day.

    Note: For units with pressurized fuel flow lines such as some diesel 
and dual-fuel reciprocating internal combustion engine units, a manual 
sample may be taken from the point closest to the unit where it is safe 
to take a sample (including back to the oil tank), rather than just 
prior to entry to the boiler or combustion chamber. As-delivered manual 
samples of diesel fuel need not be as-fired.

    2.2.5  Split and label each oil sample. Maintain a portion (at least 
200 cc) of each sample throughout the calendar year and in all cases for 
not less than 90 calendar days after the end of the calendar year 
allowance accounting period. Analyze oil samples for percent sulfur 
content by weight in accordance with ASTM D129-91, ``Standard Test 
Method for Sulfur in Petroleum Products (General Bomb Method),'' ASTM 
D1552-90, ``Standard Test Method for Sulfur in Petroleum Products (High 
Temperature Method),'' ASTM D2622-92, ``Standard Test Method for Sulfur 
in Petroleum Products by X-Ray Spectrometry,'' or ASTM D4294-90, 
``Standard Test Method for Sulfur in Petroleum Products by Energy-
Dispersive X-Ray Fluorescence Spectroscopy'' (incorporated by reference 
under Sec. 75.6).
    2.2.6  Where the flowmeter records volumetric flow rather than mass 
flow, analyze oil samples to determine the density or specific gravity 
of the oil. Determine the density or specific gravity of the oil sample 
in accordance with ASTM D287-82 (Reapproved 1991), ``Standard Test 
Method for API Gravity of Crude Petroleum and Petroleum Products 
(Hydrometer Method),'' ASTM D941-88, ``Standard Test Method for Density 
and Relative Density (Specific Gravity) of Liquids by Lipkin Bicapillary 
Pycnometer,'' ASTM D1217-91, ``Standard Test Method for Density and 
Relative Density (Specific Gravity) of Liquids by Bingham Pycnometer,'' 
ASTM D1481-91, ``Standard Test Method for Density and Relative Density 
(Specific Gravity) of Viscous Materials by Lipkin Bicapillary,'' ASTM 
D1480-91, ``Standard Test Method for Density and Relative Density 
(Specific Gravity) of Viscous Materials by Bingham Pycnometer,'' 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,'' or ASTM D4052-91, ``Standard 
Test Method for Density and Relative Density of Liquids by Digital 
Density Meter'' (incorporated by reference under Sec. 75.6).
    2.2.7  Analyze oil samples to determine the heat content of the 
fuel. Determine oil heat content in accordance with ASTM D240-87 
(Reapproved 1991), ``Standard Test Method for Heat of Combustion of 
Liquid Hydrocarbon Fuels by Bomb Calorimeter,'' ASTM D2382-88, 
``Standard Test Method for Heat or Combustion of Hydrocarbon Fuels by 
Bomb Calorimeter (High-Precision Method)'', or ASTM D2015-91, ``Standard 
Test Method for Gross Calorific Value of Coal and Coke by the Adiabatic 
Bomb Calorimeter'' (incorporated by reference under Sec. 75.6) or any 
other procedures listed in section 5.5 of appendix F of this part.
    2.2.8  Results from the oil sample analysis must be available no 
later than thirty calendar days after the sample is composited or taken. 
However, during an audit, the Administrator may require that the results 
of the analysis be available within 5 business days, or sooner if 
practicable.

        2.3  SO2 Emissions from Combustion of Gaseous Fuels

    Account for the hourly SO2 mass emissions due to combustion of 
gaseous fuels for each day when gaseous fuels are combusted by the unit 
using the procedures in either section 2.3.1 or 2.3.2.
    2.3.1  Sample the gaseous fuel daily.
    2.3.1.1  Analyze the sulfur content of the gaseous fuel in grain/100 
scf using ASTM D1072-90, ``Standard Test Method for Total Sulfur in Fuel 
Gases'', ASTM D4468-85 (Reapproved 1989) ``Standard Test Method for 
Total Sulfur in Gaseous Fuels by Hydrogenolysis and Rateometric 
Colorimetry,'' ASTM D5504-94 ``Standard Test Method for Determination of 
Sulfur Compounds in Natural Gas and Gaseous Fuels by Gas Chromatography 
and Chemiluminescence,'' or ASTM D3246-81 (Reapproved 1987) ``Standard 
Test Method for Sulfur in Petroleum Gas By Oxidative Microcoulometry'' 
(incorporated by reference under Sec. 75.6). The test may be performed 
by the owner or operator, an outside laboratory, or the gas supplier.
    2.3.1.2  Results from the analysis must be available on-site no 
later than thirty calendar days after the sample is taken.
    2.3.1.3  Determine the heat content or gross calorific value for at 
least one sample each month and use the procedures of section 5.5 of 
appendix F of this part to determine the heat input for each hour the 
unit combusted gaseous fuel.
    2.3.1.4  Multiply the sulfur content by the hourly metered volume of 
gas combusted in 100 scf, using Equation D-4 of this appendix.
    2.3.2  If the fuel is pipeline natural gas, calculate SO2 
emissions using a default SO2 emission rate of 0.0006 lb/mmBtu.
    2.3.2.1  Use the default SO2 emission rate of 0.0006 lb/mmBtu 
and the hourly heat input from pipeline natural gas in mmBtu/hr, as 
determined using the procedures in section 5.5 of appendix F of this 
part. Calculate SO2

[[Page 316]]

emissions using Equation D-5 of this appendix.
    2.3.2.2  Provide information on the contractual sulfur content from 
the pipeline gas supplier in the monitoring plan for the unit, 
demonstrating that the gas has a hydrogen sulfide content of 1 grain/100 
scf or less, and a total sulfur content of 20 grain/100 scf or less.

                      2.4  Missing Data Procedures.

    When data from the procedures of this part are not available, 
provide substitute data using the following procedures.
    2.4.1  When sulfur content or oil density data from the analysis of 
an oil sample or when sulfur content data from the analysis of a gaseous 
fuel sample are missing or invalid, substitute, as applicable, the 
highest measured sulfur content or oil density (if using a volumetric 
oil flowmeter) recorded during the previous 30 days when the unit burned 
that fuel. If no previous sulfur content data are available, substitute 
the maximum potential sulfur content of that fuel.
    2.4.2  When gross calorific value data from the analysis of an oil 
sample are missing or invalid, substitute the highest measured gross 
calorific value recorded during the previous 30 days that the unit 
burned oil. When gross calorific value data from the analysis of a 
monthly gaseous fuel sample are missing or invalid, substitute the 
highest measured gross calorific value recorded during the previous 
three months that the unit burned gaseous fuel.
    2.4.3  Whenever data are missing from any fuel flowmeter that is 
part of an excepted monitoring system under appendix D or E of this 
part, where the fuel flowmeter data are required to determine the amount 
of fuel combusted by the unit, use the procedures in either section 
2.4.3.1 or sections 2.4.3.2 and 2.4.3.3 prior to January 1, 1996 and use 
the procedures in sections 2.4.3.2 and 2.4.3.3 but do not use the 
procedures in section 2.4.3.1 on or after January 1, 1996 to account for 
the flow rate of fuel combusted at the unit for each hour during the 
missing data period.
    2.4.3.1  [Reserved]
    2.4.3.2  For hours where only one fuel is combusted, substitute for 
each hour in the missing data period the average of the hourly fuel flow 
rate(s) measured and recorded by the fuel flowmeter (or flowmeters, 
where fuel is recirculated) at the corresponding operating unit load 
range recorded for each missing hour during the previous 720 hours 
during which the unit combusted that same fuel only. Establish load 
ranges for the unit using the procedures of section 2 in appendix C of 
this part for missing volumetric flow rate data. If no fuel flow rate 
data are available at the corresponding load range, use data from the 
next higher load range where data are available. If no fuel flow rate 
data are available at either the corresponding load range or a higher 
load range during any hour of the missing data period for that fuel, 
substitute the maximum potential fuel flow rate. The maximum potential 
fuel flow rate is the lesser of the following: (1) the maximum fuel flow 
rate the unit is capable of combusting or (2) the maximum flow rate that 
the flowmeter can measure.
    2.4.3.3  For hours where two or more fuels are combusted, substitute 
the maximum hourly fuel flow rate measured and recorded by the flowmeter 
(or flowmeters, where fuel is recirculated) for the fuel for which data 
are missing at the corresponding load range recorded for each missing 
hour during the previous 720 hours when the unit combusted that fuel 
with any other fuel. For hours where no previous recorded fuel flow rate 
data are available for that fuel during the missing data period, 
calculate and substitute the maximum potential flow rate of that fuel 
for the unit as defined in section 2.4.3.2 of this appendix.
    2.4.4.  In any case where the missing data provisions of this 
section require substitution of data measured and recorded more than 
three years (26,280 clock hours) prior to the date and time of the 
missing data period, use three years (26,280 clock hours) in place of 
the prescribed lookback period.

                             3. Calculations

    Use the calculation procedures in section 3.1 of this appendix to 
calculate SO2 mass emissions. Where an oil flowmeter records 
volumetric flow, use the calculation procedures in section 3.2 of this 
appendix to calculate mass flow of oil. Calculate hourly SO2 mass 
emissions from gaseous fuel using the procedures in section 3.3 of this 
appendix. Calculate hourly heat input for oil and for gaseous fuel using 
the equations in section 5.5 of Appendix F of this part. Calculate total 
SO2 mass emissions and heat input as provided under section 3.4 of 
this appendix.

             3.1 SO2 Mass Emissions Calculation for Oil

    3.1.1  Use the following equation to calculate SO2 mass 
emissions per hour (in lb/hr).

Mso2=2.0 x Moil x %Soil/100.0
(Eq. D-2)
Where:
MSO2=Hourly mass of SO2 emitted from combustion of oil, lb/hr.
Moil=Mass of oil consumed per hr, lb/hr.
%Soil=Percentage of sulfur by weight measured in the sample.
2.0=Ratio of lb SO2/lb S.

    3.1.2  Record the SO2 mass emissions from oil for each hour 
that oil is combusted.

[[Page 317]]

        3.2  Mass Flow Calculation for Oil Using Volumetric Flow

    3.2.1  Where the oil flowmeter records volumetric flow rather than 
mass flow, calculate and record the oil mass flow for each hourly period 
using hourly oil flow measurements and the density or specific gravity 
of the oil sample.
    3.2.2  Convert density, specific gravity, or API gravity of the oil 
sample to density of the oil sample at the sampling location's 
temperature using ASTM D1250-80 (Reapproved 1990), ``Standard Guide for 
Petroleum Measurement Tables'' (incorporated by reference under 
Sec. 75.6 of this part).
    3.2.3  Where density of the oil is determined by the applicable ASTM 
procedures from section 2.2.5 of this appendix, use the following 
equation to calculate the mass of oil consumed (in lb/hr).

Moil=Voi1 x Doil
(Eq. D-3)

where,
Moil=Mass of oil consumed per hr, lb/hr.
Voil=Volume of oil consumed per hr, measured in scf, gal, barrels, 
          or m\3\.
Doil=Density of oil, measured in lb/scf, lb/gal, lb/barrel, or lb/
          m\3\.

    3.2.4  Calculate the hourly heat input to the unit from oil (mmBtu) 
by multiplying the heat content of the daily oil sample by the hourly 
oil mass.

       3.3  SO2 Mass Emissions Calculation for Gaseous Fuels

    3.3.1  Use the following equation to calculate the SO2 
emissions using the gas sampling and analysis procedures in section 
2.3.1 of this appendix:
[GRAPHIC] [TIFF OMITTED] TR17MY95.011

Where:

MSO2g=Hourly mass of SO2 emitted due to combustion of gaseous 
          fuel, lb/hr.
Qg=Hourly metered flow or amount of gaseous fuel combusted, 100 
          scf/hr.
Sg=Sulfur content of gaseous fuel, in grain/100 scf.
2.0=Ratio of lb SO2/lb S.
7000=Conversion of grains/100 scf to lb/100 scf.

    3.3.2  Use the following equation to calculate the SO2 
emissions using the 0.0006 lb/mmBtu emission rate in section 2.3.2 of 
this appendix:
[GRAPHIC] [TIFF OMITTED] TR17MY95.012

Where:

MSO2g=Hourly mass of SO2 emissions from combustion of pipeline 
          natural gas, lb/hr.
ER=SO2 emission rate of 0.0006 lb/mmBtu for pipeline natural gas.
HIg=Hourly heat input of pipeline natural gas, calculated using 
          procedures in appendix F of this part, in mmBtu/hr.

    3.3.3  Record the SO2 mass emissions for each hour when the 
unit combusts gaseous fuel.

                        3.4  Records and Reports

    Calculate and record quarterly and cumulative SO2 mass 
emissions and heat input for each calendar quarter and for the calendar 
year by summing the hourly values. Calculate and record SO2 
emissions and heat input data using a data acquisition and handling 
system. Report these data in a standard electronic format specified by 
the Administrator.

[58 FR 3701, Jan. 11, 1993, as amended at 60 FR 26548, 26551, May 17, 
1995; 61 FR 25585, May 22, 1996]

 Appendix E to Part 75--Optional NOx Emissions Estimation Protocol 
         for Gas-Fired Peaking Units and Oil-Fired Peaking Units

                            1.  Applicability

                    1.1  Unit Operation Requirements

    This NOX emissions estimation procedure may be used in lieu of 
a continuous NOX emission monitoring system (lb/mmBtu) for 
determining the average NOX emission rate and hourly NOX rate 
from gas-fired peaking units and oil-fired peaking units as defined in 
Sec. 72.2 of this chapter. If a unit's operations exceed the levels 
required to be a peaking unit, install and certify a continuous NOX 
emission monitoring system no later than December 31 of the following 
calendar year. The provisions of Sec. 75.12 apply to excepted monitoring 
systems under this appendix.

                           1.2  Certification

    1.2.1  Pursuant to the procedures in Sec. 75.20, complete all 
testing requirements to certify use of this protocol in lieu of a 
NOX continuous emission monitoring system no later than the 
applicable deadline specified in Sec. 75.4. Apply to the Administrator 
for certification to use this method no later than 45 days after the 
completion of all certification testing. Whenever the monitoring method 
is to be changed, reapply to the Administrator for certification of the 
new monitoring method.
    1.2.2  If the owner or operator has already successfully completed 
certification testing of the unit using the protocol of appendix E of 
part 75 and submitted a certification application under Sec. 75.20(g) 
prior to ________ July 17, 1995, the unit's monitoring system does not 
need to repeat initial certification testing using the revised 
procedures published ________ May 17, 1995.

[[Page 318]]

                              2. Procedure

                    2.1  Initial Performance Testing

    Use the following procedures for: measuring NOX emission rates 
at heat input rate levels corresponding to different load levels; 
measuring heat input rate; and plotting the correlation between heat 
input rate and NOX emission rate, in order to determine the 
emission rate of the unit(s).

                          2.1.1  Load Selection

    Establish at least four approximately equally spaced operating load 
points, ranging from the maximum operating load to the minimum operating 
load. Select the maximum and minimum operating load from the operating 
history of the unit during the most recent two years. (If projections 
indicate that the unit's maximum or minimum operating load during the 
next five years will be significantly different from the most recent two 
years, select the maximum and minimum operating load based on the 
projected dispatched load of the unit.) For new gas-fired peaking units 
or new oil-fired peaking units, select the maximum and minimum operating 
load from the expected maximum and minimum load to be dispatched to the 
unit in the first five calendar years of operation.

         2.1.2  NOX and O2 Concentration Measurements

    Use the following procedures to measure NOX and O2 
concentration in order to determine NOX emission rate.
    2.1.2.1  For boilers, select an excess O2 level for each fuel 
(and, optionally, for each combination of fuels) to be combusted that is 
representative for each of the four or more load levels. If a boiler 
operates using a single, consistent combination of fuels only, the 
testing may be performed using the combination rather than each fuel. If 
a fuel is combusted only for the purpose of testing ignition of the 
burners for a period of five minutes or less per ignition test or for 
start-up, then the boiler NOX emission rate does not need to be 
tested separately for that fuel. Operate the boiler at a normal or 
conservatively high excess oxygen level in conjunction with these tests. 
Measure the NOX and O2 at each load point for each fuel or 
consistent fuel combination (and, optionally, for each combination of 
fuels) to be combusted. Measure the NOX and O2 concentrations 
according to Method 7E and 3A in appendix A of part 60 of this chapter. 
Select sampling points as specified in section 5.1, Method 3 in appendix 
A of part 60 of this chapter. The designated representative for the unit 
may also petition the Administrator under Sec. 75.66 to use fewer 
sampling points. Such a petition shall include the proposed alternative 
sampling procedure and information demonstrating that there is no 
concentration stratification at the sampling location.
    2.1.2.2  For stationary gas turbines, select sampling points and 
measure the NOX and O2 concentrations at each load point for 
each fuel or consistent combination of fuels (and, optionally, each 
combination of fuels) according to appendix A, Method 20 of part 60 of 
this chapter. For diesel or dual fuel reciprocating engines, measure the 
NOX and O2 concentrations according to Method 20, but modify 
Method 20 by selecting a sampling site to be as close as practical to 
the exhaust of the engine.
    2.1.2.3  Allow the unit to stabilize for a minimum of 15 minutes (or 
longer if needed for the NOX and O2 readings to stabilize) 
prior to commencing NOx, O2, and heat input measurements. Determine 
the average measurement system response time according to section 5.5 of 
Method 20 in appendix A, part 60 of this chapter. When inserting the 
probe into the flue gas for the first sampling point in each traverse, 
sample for at least one minute plus twice the average measurement system 
response time (or longer, if necessary to obtain a stable reading). For 
all other sampling points in each traverse, sample for at least one 
minute plus the average measurement response time (or longer, if 
necessary to obtain a stable reading). Perform three test runs at each 
load condition and obtain an arithmetic average of the runs for each 
load condition. During each test run on a boiler, record the boiler 
excess oxygen level at 5 minute intervals.

                            2.1.3  Heat Input

    Measure the total heat input (mmBtu) and heat input rate during 
testing (mmBtu/hr) as follows:
    2.1.3.1  When the unit is combusting fuel, measure and record the 
flow of fuel consumed. Measure the flow of fuel with an in-line 
flowmeter(s) and automatically record the data. If a portion of the flow 
is diverted from the unit without being burned, and that diversion 
occurs downstream of the fuel flowmeter, an in-line flowmeter is 
required to account for the unburned fuel. Install and calibrate in-line 
flow meters using the procedures and specifications contained in 
sections 2.1.2, 2.1.3, 2.1.4, and 2.1.5 of appendix D of this part. 
Correct any gaseous fuel flow rate measured at actual temperature and 
pressure to standard conditions of 68 deg.F and 29.92 inches of mercury.
    2.1.3.2  For liquid fuels, analyze fuel samples taken according to 
the requirements of section 2.2 of appendix D of this part to determine 
the heat content of the fuel. Determine heat content of liquid or 
gaseous fuel in accordance with the procedures in appendix F of this 
part. Calculate the heat input rate during testing (mmBtu/hr) associated 
with each load condition in accordance with Equations F-19 or F-20 in 
appendix F of this

[[Page 319]]

part and total heat input using Equation E-1 of this appendix. Record 
the heat input rate at each heat input/load point.

                          2.1.4  Emergency Fuel

    The designated representative of a unit that is restricted by its 
Federal, State or local permit to combusting a particular fuel only 
during emergencies where the primary fuel is not available may petition 
the Administrator pursuant to the procedures in Sec. 75.66 for an 
exemption from the requirements of this appendix for testing the 
NOX emission rate during combustion of the emergency fuel. The 
designated representative shall include in the petition a procedure for 
determining the NOX emission rate for the unit when the emergency 
fuel is combusted, and a demonstration that the permit restricts use of 
the fuel to emergencies only. The designated representative shall also 
provide notice under Sec. 75.61(a) for each period when the emergency 
fuel is combusted.

                      2.1.5  Tabulation of Results

    Tabulate the results of each baseline correlation test for each fuel 
or, as applicable, combination of fuels, listing: time of test, 
duration, operating loads, heat input rate (mmBtu/hr), F-factors, excess 
oxygen levels, and NOX concentrations (ppm) on a dry basis (at 
actual excess oxygen level). Convert the NOX concentrations (ppm) 
to NOX emission rates (to the nearest 0.01 lb/mm/Btu) according to 
Equation F-5 of appendix F of this part or 19-3 in Method 19 of appendix 
A of part 60 of this chapter, as appropriate. Calculate the NOX 
emission rate in lb/mmBtu for each sampling point and determine the 
arithmetic average NOX emission rate of each test run. Calculate 
the arithmetic average of the boiler excess oxygen readings for each 
test run. Record the arithmetic average of the three test runs as the 
NOX emission rate and the boiler excess oxygen level for the heat 
input/load condition.

                       2.1.6  Plotting of Results

    Plot the tabulated results as an x-y graph for each fuel and (as 
applicable) combination of fuels combusted according to the following 
procedures.
    2.1.6.1  Plot the heat input rate (mmBtu/hr) as the independent (or 
x) variable and the NOX emission rates (lb/mmBtu) as the dependent 
(or y) variable for each load point. Construct the graph by drawing 
straight line segments between each load point. Draw a horizontal line 
to the y-axis from the minimum heat input (load) point.
    2.1.6.2  Units that co-fire gas and oil may be tested while firing 
gas only and oil only instead of testing with each combination of fuels. 
In this case, construct a graph for each fuel.

              2.2  Periodic NOx Emission Rate Testing

    Retest the NOx emission rate of the gas-fired peaking unit or 
the oil-fired peaking unit prior to the earlier of 3,000 unit operating 
hours or the 5-year anniversary and renewal of its operating permit 
under part 72 of this chapter.

 2.3  Other Quality Assurance/Quality Control-Related NOx Emission Rate 
                                 Testing

    When the operating levels of certain parameters exceed the limits 
specified below, or where the Administrator issues a notice requesting 
retesting because the NOX emission rate data availability for when 
the unit operates within all quality assurance/quality control 
parameters in this section since the last test is less than 90.0 
percent, as calculated by the Administrator, complete retesting of the 
NOX emission rate by the earlier of: (1) 10 unit operating days (as 
defined in section 2.1 of appendix B of this part) or (2) 180 calendar 
days after exceeding the limits or after the date of issuance of a 
notice from the Administrator to re-verify the unit's NOX emission 
rate. Submit test results in accordance with Sec. 75.60(a) within 45 
days of completing the retesting.
    2.3.1  For a stationary gas turbine, obtain a list of at least four 
operating parameters indicative of the turbine's NOX formation 
characteristics, and the recommended ranges for these parameters at each 
tested load-heat input point, from the gas turbine manufacturer. If the 
gas turbine uses water or steam injection for NOX control, the 
water/fuel or steam/fuel ratio shall be one of these parameters. During 
the NOx-heat input correlation tests, record the average value of each 
parameter for each load-heat input to ensure that the parameters are 
within the manufacturer's recommended range. Redetermine the NOX 
emission rate-heat input correlation for each fuel and (optional) 
combination of fuels after continuously exceeding the manufacturer's 
recommended range of any of these parameters for one or more successive 
operating periods totaling more than 16 unit operating hours.
    2.3.2  For a diesel or dual-fuel reciprocating engine, obtain a list 
of at least four operating parameters indicative of the engine's 
NOX formation characteristics, and the recommended ranges for these 
parameters at each tested load-heat input point, from the engine 
manufacturer. Any operating parameter critical for NOX control 
shall be included. During the NOX heat-input correlation tests, 
record the average value of each parameter for each load-heat input to 
ensure that the parameters are within the manufacturer's recommended 
range. Redetermine the NOX emission rate-heat input correlation for 
each fuel and (optional) combination or fuels after continuously 
exceeding the manufacturer's recommended range of any of these

[[Page 320]]

parameters for one or more successive operating periods totaling more 
than 16 unit operating hours.
    2.3.3  For boilers using the procedures in this appendix, the 
NOX emission rate heat input correlation for each fuel and 
(optional) combination of fuels shall be redetermined if the excess 
oxygen level at any heat input rate (or unit operating load) 
continuously exceeds by more than 2 percentage points O2 from the 
boiler excess oxygen level recorded at the same operating heat input 
rate during the previous NOX emission rate test for one or more 
successive operating periods totaling more than 16 unit operating hours.

      2.4  Procedures for Determining Hourly NOX Emission Rate

    2.4.1  Record the time (hr. and min.), load (MWge or steam load in 
1000 lb/hr), fuel flow rate and heat input rate (using the procedures in 
section 2.1.3 of this appendix) for each hour during which the unit 
combusts fuel. Calculate the total hourly heat input using Equation E-1 
of this appendix. Record the heat input rate for each fuel to the 
nearest 0.1 mmBtu/hr. During partial unit operating hours or during 
hours where more than one fuel is combusted, heat input must be 
represented as an hourly rate in mmBtu/hr, as if the fuel were combusted 
for the entire hour at that rate (and not as the actual, total heat 
input during that partial hour or hour) in order to ensure proper 
correlation with the NOX emission rate graph.
    2.4.2  Use the graph of the baseline correlation results 
(appropriate for the fuel or fuel combination) to determine the NOX 
emissions rate (lb/mmBtu) corresponding to the heat input rate (mmBtu/
hr). Input this correlation into the data acquisition and handling 
system for the unit. Linearly interpolate to 0.1 mmBtu/hr heat input 
rate and 0.01 lb/mmBtu NOX.
    2.4.3  To determine the NOX emission rate for a unit co-firing 
fuels that has not been tested for that combination of fuels, 
interpolate between the NOX emission rate for each fuel as follows. 
Determine the heat input rate for the hour (in mmBtu/hr) for each fuel 
and select the corresponding NOX emission rate for each fuel on the 
appropriate graph. (When a fuel is combusted for a partial hour, 
determine the fuel usage time for each fuel and determine the heat input 
rate from each fuel as if that fuel were combusted at that rate for the 
entire hour in order to select the corresponding NOX emission 
rate.) Calculate the total heat input to the unit in mmBtu for the hour 
from all fuel combusted using Equation E-1. Calculate a Btu-weighted 
average of the emission rates for all fuels using Equation E-2 of this 
appendix.
    2.4.4  For each hour, record the critical quality assurance 
parameters, as identified in the monitoring plan, and as required by 
section 2.3 of this appendix.

                      2.5  Missing Data Procedures

    Provide substitute data for each unit electing to use this 
alternative procedure whenever a valid quality-assured hour of NOX 
emission rate data has not been obtained according to the procedures and 
specifications of this appendix.
    2.5.1  Use the procedures of this section whenever any of the 
quality assurance/quality control parameters exceeds the limits in 
section 2.3 of this appendix or whenever any of the quality assurance/
quality control parameters are not available.
    2.5.2  Substitute missing NOX emission rate data using the 
highest NOX emission rate tabulated during the most recent set of 
baseline correlation tests for the same fuel or, if applicable, 
combination of fuels.
    2.5.3  Maintain a record indicating which data are substitute data 
and the reasons for the failure to provide a valid quality-assured hour 
of NOX emission rate data according to the procedures and 
specifications of this appendix.
    2.5.4  Substitute missing data from a fuel flowmeter using the 
procedures in section 2.4.3 of appendix D of this part.
    2.5.5  Substitute missing data for gross calorific value of fuel 
using the procedures in section 2.4.2 of appendix D of this part.

                             3. Calculations

                             3.1  Heat Input

    Calculate the total heat input by summing the product of heat input 
rate and fuel usage time of each fuel, as in the following equation:

HT = HIfuel1 t1 + HIfuel2 t2 + HIfuel3 
          t3 + . . . + HIlastfuel tlast    (Eq. E-1)
Where:

HT = Total heat input of fuel flow or a combination of fuel flows 
          to a unit, mmBtu;
HIfuel 1,2,3,...last = Heat input rate from each fuel during fuel 
          usage time, in mmBtu/hr, as determined using equation F-19 or 
          F-20 in section 5.5 of appendix F of this part, mmBtu/hr;
t1,2,3....last = Fuel usage time for each fuel, rounded up to the 
          nearest .25 hours.

    Note: For hours where a fuel is combusted for only part of the hour, 
use the fuel flow rate or mass flow rate during the fuel usage time, 
instead of the total fuel flow during the hour, when calculating heat 
input rate using Equation F-19 or F-20.

                             3.2  F-factors

    Determine the F-factors for each fuel or combination of fuels to be 
combusted according to section 3.3 of appendix F of this part.

[[Page 321]]

                       3.3  NOX Emission Rate

     3.3.1  Conversion from Concentration to Emission Rate [Amended]

    Convert the NOX concentrations (ppm) and O2 concentrations 
to NOX emission rates (to the nearest 0.01 lb/mmBtu) according to 
the appropriate one of the following equations: F-5 in appendix F of 
this part for dry basis concentration measurements, or 19-3 in Method 19 
of appendix A of part 60 of this chapter for wet basis concentration 
measurements.

             3.3.2  Quarterly Average NOX Emission Rate

    Report the quarterly average emission rate (lb/mmBtu) as required in 
subpart G of this part. Calculate the quarterly average NOX 
emission rate according to Equation F-9 in Appendix F of this part.

              3.3.3  Annual Average NOX Emission Rate

    Report the average emission rate (lb/mmBtu) for the calendar year as 
required in subpart G of this part. Calculate the average NOX 
emission rate according to equation F-10 in appendix F of this part.
    3.3.4  Average NOX Emission Rate During Co-firing of Fuels 
[Amended]    (Eq. E-2)
Where:

Eh=NOX emission rate for the unit for the hour, lb/mmBtu;
[GRAPHIC] [TIFF OMITTED] TR17MY95.013

Ef=NOX emission rate for the unit for a given fuel at heat 
          input rate HIf, lb/mmBtu;
HIf=Heat input rate for a given fuel during the fuel usage time, as 
          determined using equation F-19 or F-20 in section 5.5 of 
          appendix F of this part, mmBtu/hr;
HT=Total heat input for all fuels for the hour from Equation E-1;
tt=Fuel usage time for each fuel, rounded to the nearest .25 hour.

    Note: For hours where a fuel is combusted for only part of the hour, 
use the fuel flow rate or mass flow rate during the fuel usage time, 
instead of the total fuel flow or mass flow during the hour, when 
calculating heat input rate using Equation F-19 or F-20.

                4. Quality Assurance/Quality Control Plan

    Include a section on the NOX emission rate determination as 
part of the monitoring quality assurance/quality control plan required 
under Sec. 75.21 and appendix B of this part for each gas-fired peaking 
unit and each oil-fired peaking unit. In this section present 
information including, but not limited to, the following: (1) a copy of 
all data and results from the initial NOX emission rate testing, 
including the values of quality assurance parameters specified in 
Section 2.3 of this appendix; (2) a copy of all data and results from 
the most recent NOX emission rate load correlation testing; (3) a 
copy of the unit manufacturer's recommended range of quality assurance- 
and quality control-related operating parameters.
    4.1  Submit a copy of the unit manufacturer's recommended range of 
operating parameter values, and the range of operating parameter values 
recorded during the previous NOX emission rate test that determined 
the unit's NOX emission rate, along with the unit's revised 
monitoring plan submitted with the certification application.
    4.2  Keep records of these operating parameters for each hour of 
operation in order to demonstrate that a unit is remaining within the 
manufacturer's recommended operating range.

[58 FR 3701, Jan. 11, 1993, as amended at 60 FR 26551-26553, May 17, 
1995]

              Appendix F to Part 75--Conversion Procedures

                            1. Applicability

    Use the procedures in this appendix to convert measured data from a 
monitor or continuous emission monitoring system into the appropriate 
units of the standard.

                  2. Procedures for SO2 emissions

    Use the following procedures to compute hourly, quarterly, and 
annual SO2 mass emissions (in lb/hr). Use the procedures in Method 
19 in Appendix A to part 60 of this chapter to compute hourly SO2 
emission rates (in lb/mmBtu) for qualifying Phase I technologies.
    2.1  When measurements of SO2 concentration and flow rate are 
on a wet basis, use the following equation to compute hourly SO2 
mass emissions (in lb/hr).

Eh=K Ch Qh
(Eq. F-1)

where,
Eh=Hourly SO2 mass emissions, lb/hr.
K=1.660 x 10-7 for SO2, (lb/scf)/ppm.
Ch=Hourly average SO2 concentration, stack moisture basis, 
          ppm.
Qh=Hourly average volumetric flow rate, stack moisture basis, scfh.

    2.2  When measurements by the SO2 pollutant concentration 
monitor are on a dry basis and the flow rate monitor measurements are on 
a wet basis, use the following equation to compute hourly SO2 mass 
emissions (in lb/hr).

[[Page 322]]

[GRAPHIC] [TIFF OMITTED] TC01SE92.120


(Eq. F-2)

where,
Eh=Hourly SO2 mass emissions, lb/hr.
K=1.660 x 10-7 for SO2 , (lb/scf)/ppm.
Chp=Hourly average SO2 concentration, ppm (dry).
Qhs=Hourly average volumetric flow rate, scfh as measured (wet).
%H2O=Hourly average stack moisture content, percent by volume.

    2.3  Use the following equations to calculate total SO2 mass 
emissions for each calendar quarter (Eq. F-3) and for each calendar year 
(Eq. F-4) in tons.
[GRAPHIC] [TIFF OMITTED] TC01SE92.121

(Eq. F-3)

where,
Eq=Quarterly total SO2 mass emissions, tons.
Eh=Hourly SO2 mass emissions, lb/hr.
n=Number of hourly SO2 emissions values during calendar quarter.
2000=Conversion of 2000 lb per ton.
[GRAPHIC] [TIFF OMITTED] TC01SE92.122

(Eq. F-4)

where,
Ea=Annual total SO2 mass emissions, tons.
Eq=Quarterly SO2 mass emissions, tons.
q=Quarters for which Eq are available during calendar year.

    2.4  Round all SO2 mass emissions to the number of decimal 
places identified in Sec. 75.50(c) or Sec. 75.54(c) of this part (in lb/
hr).

                3. Procedures for NOx Emission Rate

    Use the following procedures to convert continuous emission 
monitoring system measurements of NOx concentration (ppm) and 
diluent concentration (percentage) into NOx emission rates (in lb/
mmBtu). Perform measurements of NOx and diluent (O2 or 
CO2) concentrations on the same moisture (wet or dry) basis.
    3.1  When the NOx continuous emission monitoring system uses 
O2 as the diluent, and measurements are performed on a dry basis, 
use the following conversion procedure:
[GRAPHIC] [TIFF OMITTED] TC01SE92.123

(Eq. F-5)

where,

K, E, Ch, F, and %O2 are defined in section 3.3 of this 
appendix. When measurements are performed on a wet basis, use the 
equations in Method 19 in Appendix A of part 60 of this chapter.
    3.2  When the NOX continuous emission monitoring system uses 
CO2 as the diluent, use the following conversion procedure:
[GRAPHIC] [TIFF OMITTED] TR17MY95.014

(Eq. F-6)

where:

K, E, Ch, Fc, and %CO2 are defined in section 3.3 of this appendix.
When CO2 and NOX measurements are performed on a different 
          moisture basis, use the equations in Method 19 in Appendix A 
          of part 60 of this chapter.
    3.3  Use the definitions listed below to derive values for the 
parameters in Equations F-5 and F-6 of this appendix.
    3.3.1  K=1.194x10-7 (lb/dscf)/ppm NOx.
    3.3.2  E=pollutant emissions, lb/mmBtu.
    3.3.3  Ch=hourly average pollutant concentration, ppm.
    3.3.4  %O2, %CO2=oxygen or carbon dioxide volume 
(expressed as percent O2 or CO2).

[[Page 323]]

    3.3.5  F, Fc=a factor representing a ratio of the volume of dry 
flue gases generated to the caloric value of the fuel combusted (F), and 
a factor representing a ratio of the volume of CO2 generated to the 
calorific value of the fuel combusted (Fc), respectively. Table 1 
lists the values of F and Fc for different fuels. A minimum 
concentration of 5.0 percent CO2 and a maximum concentration of 
14.0 percent O2 may be substituted for measured diluent gas 
concentration values during unit start-up.

                     Table 1.--F- and Fc-Factors \1\                    
------------------------------------------------------------------------
                                          F-factor (dscf/ Fc-factor (scf
                  Fuel                        mmBtu)        CO2/mmBtu)  
------------------------------------------------------------------------
Coal (as defined by ASTM D388-92):                                      
  Anthracite............................          10,100           1,970
  Bituminous and subbituminous..........           9,780           1,800
  Lignite...............................           9,860           1,910
Oil.....................................           9,190           1,420
Gas:                                                                    
  Natural gas...........................           8,710           1,040
  Propane...............................           8,710           1,190
  Butane................................           8,710           1,250
Wood:                                                                   
  Bark..................................           9,600           1,920
  Wood residue..........................           9,240           1,830
------------------------------------------------------------------------
\1\ Determined at standard conditions: 20  deg.C (68  deg.F) and 29.92  
  inches of mercury.                                                    


    3.3.6  Equations F-7a and F-7b may be used in lieu of the F or 
Fc factors specified in Section 3.3.5 of this appendix to calculate 
an F factor (dscf/mmBtu) on a dry basis or an Fc factor (scf 
CO2/mmBtu) on either a dry or wet basis.

(Calculate all F- and Fc factors at standard conditions of 20 
deg.C (68  deg.F) and 29.92 inches of mercury.)
[GRAPHIC] [TIFF OMITTED] TC01SE92.124

(Eq. F-7a)
[GRAPHIC] [TIFF OMITTED] TC01SE92.125

  
(Eq. F-7b)

    3.3.6.1  H, C, S, N, and O are content by weight of hydrogen, 
carbon, sulfur, nitrogen, and oxygen (expressed as percent), 
respectively, as determined on the same basis as the gross calorific 
value (GCV) by ultimate analysis of the fuel combusted using ASTM D3176-
89, ``Standard Practice for Ultimate Analysis of Coal and Coke'' (solid 
fuels), ASTM D5291-92, ``Standard Test Methods for Instrumental 
Determination of Carbon, Hydrogen, and Nitrogen in Petroleum Products 
and Lubricants'' (liquid fuels) or computed from results using ASTM 
D1945-91, ``Standard Test Method for Analysis of Natural Gas by Gas 
Chromatography'' or ASTM D1946-90, ``Standard Practice for Analysis of 
Reformed Gas by Gas Chromatography'' (gaseous fuels) as applicable. 
(These methods are incorporated by reference under Sec. 75.6 of this 
part.)
    3.3.6.2  GCV is the gross calorific value (Btu/lb) of the fuel 
combusted determined by ASTM D2015-91, ``Standard Test Method for Gross 
Calorific Value of Coal and Coke by the Adiabatic Bomb Calorimeter'', 
ASTM D1989-92 ``Standard Test Method for Gross Calorific Value of Coal 
and Coke by Microprocessor Controlled Isoperibol Calorimeters,'' or ASTM 
D3286-91a ``Standard Test Method for Gross Calorific Value of Coal and 
Coke by the Isoperibol Bomb Calorimeter'' for solid and liquid fuels, 
and ASTM D240-87 (Reapproved 1991) ``Standard Test Method for Heat of 
Combustion of Liquid Hydrocarbon Fuels by Bomb Calorimeter'', or ASTM 
D2382-88 ``Standard Test Method for Heat of Combustion of Hydrocarbon 
Fuels by Bomb Calorimeter (High-Precision Method)'' for oil; and ASTM 
D3588-91 ``Standard Practice for Calculating Heat Value, Compressibility 
Factor, and Relative Density (Specific Gravity) of Gaseous Fuels,'' ASTM 
D4891-89 ``Standard Test Method for Heating Value of Gases in Natural 
Gas Range by Stoichiometric Combustion,'' GPA Standard 2172 86 
``Calculation of Gross Heating Value, Relative Density and 
Compressibility Factor for Natural Gas Mixtures from Compositional 
Analysis,'' GPA Standard 2261-90 ``Analysis for Natural Gas and Similar 
Gaseous Mixtures by Gas Chromatography,'' or ASTM D1826-88, ``Standard 
Test Method for Calorific (Heating) Value of Gases in Natural Gas Range 
by Continuous Recording Calorimeter'' for gaseous fuels, as applicable. 
(These methods are incorporated by reference under Sec. 75.6).
    3.3.6.3  For affected units that combust a combination of fossil 
(coal, oil and gas) and nonfossil (e.g., bark, wood, residue, or 
refuse) 

[[Page 324]]

fuels, the F or Fc value is subject to the Administrator's 
approval.
    3.3.6.4  For affected units that combust combinations of fossil 
fuels or fossil fuels and wood residue, prorate the F or Fc factors 
determined by Section 3.3.5 of this appendix in accordance with the 
applicable formula as follows:
[GRAPHIC] [TIFF OMITTED] TC01SE92.126

  
(Eq. F-8)

where,
Xi = Fraction of total heat input derived from each type of fuel 
          (e.g., natural gas, bituminous coal, wood).
Fi or (Fc)i = Applicable F or Fc factor for each 
          fuel type determined in accordance with Section 3.3.5 of this 
          appendix.
n = Number of fuels being combusted in combination.

    3.4  Use the following equations to calculate the average NOX 
emission rate for each calendar quarter (Eq. F-9) and the average 
emission rate for the calendar year (Eq. F-10) in lb/mmBtu.
[GRAPHIC] [TIFF OMITTED] TR17MY95.015

where:

Eq=Quarterly average NOX emission rate, lb/mmBtu.
Ei=Hourly average Nox emission rate, lb/mmBtu.
n=Number of hourly rates during calendar quarter.
[GRAPHIC] [TIFF OMITTED] TR22MY96.004

where:

Ea=Average NOX emission rate for the calendar year, lb/mmBtu.
Ei=Hourly average NOX emission rate, lb/mmBtu.
m=Number of hours for which Ei is available in the calendar year.
    3.5  Round all NOx emission rates to the nearest 0.01 lb/mmBtu.

                4. Procedures for CO2 Mass Emissions

    Use the following procedures to convert continuous emission 
monitoring system measurements of CO2 concentration (percentage) 
and volumetric flow rate (scfh) into CO2 mass emissions (in tons/
day) when the owner or operator uses a CO2 continuous emission 
monitoring system (consisting of a CO2 or O2 pollutant 
monitor) and a flow monitoring system to monitor CO2 emissions from 
an affected unit.
    4.1  When CO2 concentration is measured on a wet basis, use the 
following equation to calculate hourly CO2 mass emissions rates (in 
tons/hr).

Eh = K Ch Qh
(Eq. F-11)

where,
Eh = Hourly CO2 mass emissions, tons/hr.
K = 5.7  x  10-7 for CO2, (tons/scf) /%CO2.
Ch=Hourly average CO2 concentration, stack moisture basis, 
          %CO2. A minimum concentration of 5.0 percent CO2 may 
          be substituted for the measured concentration during unit 
          start-up.
Qh = Hourly average volumetric flow rate, stack moisture basis, 
          scfh.

    4.2  When CO2 concentration is measured on a dry basis, use 
Equation F-2 to calculate the hourly CO2 mass emissions (in tons/
hr) with a K-value of 5.7 x 10-7 (tons/scf)%CO2, where Eh 
= hourly CO2 mass emissions, tons/hr and Chp = hourly average 
CO2 concentration in flue; dry basis, %CO2.
    4.3  Use the following equations to calculate total CO2 mass 
emissions for each calendar quarter (Equation F-12 and for each calendar 
year (Equation F-13).
[GRAPHIC] [TIFF OMITTED] TC01SE92.127

  
(Eq. F-12)

where,
ECO2q = Quarterly total CO2 mass emissions, tons.
Ehi = Hourly CO2 mass emissions (tons/hr).
HR = Number of hourly CO2 mass emissions available during 
          calendar quarter.
          [GRAPHIC] [TIFF OMITTED] TC01SE92.128
          
  
(Eq. F-13)

where,
ECO2a=Annual total CO2 mass emissions, tons.
ECO2q=Quarterly total CO2 mass emissions, tons.
q=Quarters for which ECO2q are available during calendar year.

    4.4  For an affected unit, when the owner or operator is 
continuously monitoring O2 concentration (in percent by volume) of 
flue gases using an O2 monitor, use the equations 

[[Page 325]]

and procedures in section 4.4.1 through 4.4.3 of this appendix to 
determine hourly CO2 mass emissions (in tons).
    4.4.1  Use appropriate F and Fc factors from section 3.3.5 of 
this appendix in the following equation to determine hourly average 
CO2 concentration of flue gases (in percent by volume).
[GRAPHIC] [TIFF OMITTED] TR17MY95.017

(Eq. F-14a)
Where:

CO2d=Hourly average CO2 concentration, percent by volume, dry 
          basis.
F, Fc=F-factor or carbon-based Fc-factor from section 3.3.5 of this 
          appendix.
20.9=Percentage of O2 in ambient air.
O2d=Hourly average O2 concentration, percent by volume, dry 
          basis. A maximum concentration of 14.0 percent O2 may be 
          substituted for the measured concentration during unit start-
          up.
or
[GRAPHIC] [TIFF OMITTED] TR22MY96.005

(Eq. F-14b)
Where:

CO2w=Hourly average CO2 concentration, percent by volume, wet 
          basis.
O2w=Hourly average O2 concentration, percent by volume, wet 
          basis. A maximum concentration of 14.0 percent O2 may be 
          substituted for the measured concentration during unit start-
          up.
F, Fc=F-factor or carbon-based Fc-factor from section 3.3.5 of 
          this appendix.
20.9=Percentage of O2 in ambient air.
%H2O=Moisture content of gas in the stack, percent.

    4.4.2  Determine CO2 mass emissions (in tons) from hourly 
average CO2 concentration (percent by volume) using Equation F-11 
and the procedure in section 4.1, where O2 measurements are on a 
wet basis, or using the procedures in section 4.2 of this appendix, 
where O2 measurements are on a dry basis.

                      5. Procedures for Heat Input

    Use the following procedures to compute heat input to an affected 
unit (in mmBtu/hr or mmBtu/day).
    5.1  Calculate and record heat input to an affected unit on an 
hourly basis, except as provided below. The owner or operator may choose 
to use the provisions specified in Sec. 75.16(e) or in section 2.1.2 of 
appendix D of this part in conjunction with the procedures provided 
below to apportion heat input among each unit using the common stack or 
common pipe header.
    5.2  For an affected unit that has a flow monitor (or approved 
alternate monitoring system under subpart E of this part for measuring 
volumetric flow rate) and a diluent gas (O2 or CO2) monitor, 
use the recorded data from these monitors and one of the following 
equations to calculate hourly heat input (in mmBtu/hr).
    5.2.1  When measurements of CO2 concentration are on a wet 
basis, use the following equation:
[GRAPHIC] [TIFF OMITTED] TC01SE92.129

  
(Eq. F-15)

where,
HI=Hourly heat input, mmBtu/hr.
Qw=Hourly average volumetric flow rate, wet basis, scfh.
Fc=Carbon-based F-factor, listed in Section 3.3.5 of this appendix 
          for each fuel, scf/mmBtu.

[[Page 326]]

%CO2w=Hourly concentration of CO2, percent CO2 wet basis. 
          A minimum concentration of 5.0 percent CO2 may be 
          substituted for the measured concentration during unit 
          startup.

    5.2.2  When measurements of CO2 concentration are on a dry 
basis, use the following equation:
[GRAPHIC] [TIFF OMITTED] TC01SE92.130

  
(Eq. F-16)

where
HI=Hourly heat input, mmBtu/hr.
Qh=Hourly average volumetric flow rate, wet basis, scfh.
Fc=Carbon-based F-Factor, listed above in Section 3.3.5 of this 
          appendix for each fuel, scf/mmBtu.
%CO2d=Hourly concentration of CO2, percent CO2 dry basis. 
          A minimum concentration of 5.0 percent CO2 may be 
          substituted for the measured concentration during unit 
          startup.
%H2O=Moisture content of gas in the stack, percent.

    5.2.3  When measurements of O2 concentration are on a wet 
basis, use the following equation:
[GRAPHIC] [TIFF OMITTED] TC01SE92.131

(Eq. F-17)

where
HI=Hourly heat input, mmBtu/hr.
Qw=Hourly average volumetric flow rate, wet basis, scfh.
F=Dry basis F-Factor, listed above in Section 3.3.5 of this appendix for 
          each fuel, dscf/mmBtu.
%O2w=Hourly concentration of O2, percent O2 wet basis. A 
          maximum concentration of 14.0 percent O2 may be 
          substituted for the measured concentration during unit 
          startup.
%H2O=Hourly average stack moisture content, percent by volume.

    5.2.4  When measurements of O2 concentration are on a dry 
basis, use the following equation:
[GRAPHIC] [TIFF OMITTED] TC01SE92.132

  
(Eq. F-18)

where,
HI=Hourly heat input, mmBtu/hr.
Qw=Hourly average volumetric flow, wet basis, scfh.
F=Dry basis F-factor, listed above in Section 3.3.5 of this appendix for 
          each fuel, dscf/mmBtu.
%H2O=Moisture content of the stack gas, percent.
%O2d=Hourly concentration of O2, percent O2 dry basis. A 
          maximum concentration of 14.0 percent O2 may be 
          substituted for the measured concentration during unit 
          startup.
    5.3--5.4  [Reserved]
    5.5  For a gas-fired or oil-fired unit that does not have a flow 
monitor and is using the procedures specified in appendix D to this part 
to monitor SO2 emissions or for any affected unit using a common 
stack for which the owner or operator chooses to determine heat input by 
fuel sampling and analysis, use the following procedures to calculate 
hourly heat input in mmBtu/hr.
    5.5.1  When the unit is combusting oil, use the following equation 
to calculate hourly heat input.

(Eq. F-19)
[GRAPHIC] [TIFF OMITTED] TR17MY95.018

Where:

HIo=Hourly heat input from oil, mmBtu/hr.
Mo=Mass of oil consumed per hour, as determined using procedures in 
          appendix D of this part, in lb, tons, or kg.
GCVo=Gross calorific value of oil, as measured daily by ASTM D240-87 
          (Reapproved 1991), ASTM D2015-91, or ASTM D2382-88, Btu/unit 
          mass (incorporated by reference under Sec. 75.6 of this part).
    106=Conversion of Btu to mmBtu.

    When performing oil sampling and analysis solely for the purpose of 
the missing data procedures in Sec. 75.36, oil samples for measuring GCV 
may be taken weekly and the procedures specified in appendix D of this 
part for determining the mass of oil consumed per hour are optional.
    5.5.2  When the unit is combusting gaseous fuels, use the following 
equation to calculate heat input from gaseous fuels for each hour.

(Eq. F-20)

[[Page 327]]

[GRAPHIC] [TIFF OMITTED] TR17MY95.019


Where:
HIg=Hourly heat input from gaseous fuel, mmBtu/hour.
Qg=Metered flow or amount of gaseous fuel combusted during the 
          hour, hundred cubic feet.
GCVg=Gross calorific value of gaseous fuel, as determined by 
          sampling at least every month the gaseous fuel is combusted, 
          or as verified by the contractual supplier at least once every 
          month the gaseous fuel is combusted using ASTM D1826-88, ASTM 
          D3588-91, ASTM D4891-89, GPA Standard 2172-86 ``Calculation of 
          Gross Heating Value, Relative Density and Compressibility 
          Factor for Natural Gas Mixtures from Compositional Analysis,'' 
          or GPA Standard 2261-90 ``Analysis for Natural Gas and Similar 
          Gaseous Mixtures by Gas Chromatography,'' Btu/cubic foot 
          (incorporated by reference under Sec. 75.6 of this part).
10,000=Conversion factor, (Btu-100 scf)/(mmBtu-scf).
    5.5.3  When the unit is combusting coal, use the procedures, 
methods, and equations in sections 5.5.3.1-5.5.3.3 of this appendix to 
determine the heat input from coal for each 24-hour period. (All ASTM 
methods are incorporated by reference under Sec. 75.6 of this part.)
    5.5.3.1  Perform coal sampling daily according to section 5.3.2.2 in 
Method 19 in appendix A to part 60 of this chapter and use ASTM Method 
D2234-89, ``Standard Test Methods for Collection of a Gross Sample of 
Coal,'' (incorporated by reference under Sec. 75.6) Type I, Conditions 
A, B, or C and systematic spacing for sampling. (When performing coal 
sampling solely for the purposes of the missing data procedures in 
Sec. 75.36, use of ASTM D2234-89 is optional, and coal samples may be 
taken weekly.)
    5.5.3.2  Use ASTM D2013-86, ``Standard Method of Preparing Coal 
Samples for Analysis,'' for preparation of a daily coal sample and 
analyze each daily coal sample for gross calorific value using ASTM 
D2015-91, ``Standard Test Method for Gross Calorific Value of Coal and 
Coke by the Adiabatic Bomb Calorimeter'', ASTM 1989-92 ``Standard Test 
Method for Gross Calorific Value of Coal and Coke by Microprocessor 
Controlled Isoperibol Calorimeters,'' or ASTM 3286-91a ``Standard Test 
Method for Gross Calorific Value of Coal and Coke by the Isoperibol Bomb 
Calorimeter.'' (All ASTM methods are incorporated by reference under 
Sec. 75.6 of this part.)
    On-line coal analysis may also be used if the on-line analytical 
instrument has been demonstrated to be equivalent to the applicable ASTM 
methods under Secs. 75.23 and 75.66.
    5.5.3.3  Calculate the heat input from coal using the following 
equation:
[GRAPHIC] [TIFF OMITTED] TR17MY95.020

(Eq. F-21)
Where:

HIc=Daily heat input from coal, mmBtu/day.
Mc=Mass of coal consumed per day, as measured and recorded in company 
          records, tons.
GCVc=Gross calorific value of coal sample, as measured by ASTM 
          D3176-89, D1989-92, D3286-91a, or D2015-91, Btu/lb.
500=Conversion of Btu/lb to mmBtu/ton.

    5.5.4  For units obtaining heat input values daily instead of 
hourly, apportion the daily heat input using the fraction of the daily 
steam load or daily unit operating load used each hour in order to 
obtain HIi for use in the above equations. Alternatively, use the 
hourly mass of coal consumed in equation F-21.
    5.5.5  If a daily fuel sampling value for gross calorific value is 
not available, substitute the maximum gross calorific value measured 
from the previous 30 daily samples. If a monthly fuel sampling value for 
gross calorific value is not available, substitute the maximum gross 
calorific value measured from the previous 3 monthly samples.
    5.5.6  If a fuel flow value is not available, use the fuel flowmeter 
missing data procedures in section 2.4 of appendix D of this part. If a 
daily coal consumption value is not available, substitute the maximum 
fuel feed rate during the previous thirty days when the unit burned 
coal.
    5.5.7  Results for samples must be available no later than thirty 
calendar days after the sample is composited or taken. However, during 
an audit, the Administrator may require that the results be available in 
five business days, or sooner if practicable.

           6. Procedure for Converting Volumetric Flow to STP

    Use the following equation to convert volumetric flow at actual 
temperature and pressure to standard temperature and pressure.
FSTP=FActual(TStd/TStack)(PStack/PStd)

Where:

FSTP=Flue gas volumetric flow rate at standard temperature and 
          pressure, scfh.
FActual=Flue gas volumetric flow rate at actual temperature and 
          pressure, acfh.
TStd=Standard temperature=528  deg.R.
TStack=Flue gas temperature at flow monitor location,  deg.R, where 
           deg.R=460+ deg.F.

[[Page 328]]

PStack=The absolute flue gas pressure=barometric pressure at the 
          flow monitor location + flue gas static pressure, inches of 
          mercury.
PStd=Standard pressure=29.92 inches of mercury.

    7. Procedures for SO2 Mass Emissions at Units With SO2 
Continuous Emission Monitoring Systems During the Combustion of Gaseous 
                                  Fuel

    Use the following equation to calculate hourly SO2 mass 
emissions as allowed for units with SO2 continuous emission 
monitoring systems during the combustion of pipeline natural gas under 
Sec. 75.11(e). These procedures are optional prior to January 1, 1997 
and are required on or after January 1, 1997.

Eh=(0.0006) HI    (Eq. F-23)

where,

Eh=Hourly SO2 mass emissions, lb/hr.
0.0006=Default SO2 emission rate for pipeline natural gas, lb/
          mmBtu.
HI=Hourly heat input, as determined using the procedures of section 5.2 
          of this appendix.

[58 FR 3701, Jan. 11, 1993; Redesignated and amended at 60 FR 26553-
26556, 26571, May 17, 1995; 61 FR 25585, May 22, 1996]

    Effective Date Note: At 60 FR 26571, May 17, 1995, appendix F to 
part 75 was amended by temporarily adding section 7, effective July 17, 
1995 through December 31, 1996.

       Appendix G to Part 75--Determination of CO2 Emissions

                            1. Applicability

    The procedures in this appendix may be used to estimate CO2 
mass emissions discharged to the atmosphere (in tons/day) as the sum of 
CO2 emissions from combustion and, if applicable, CO2 
emissions from sorbent used in a wet flue gas desulfurization control 
system, fluidized bed boiler, or other emission controls.

     2. Procedures for Estimating CO2 Emissions From Combustion

    Use the following procedures to estimate daily CO2 mass 
emissions from the combustion of fossil fuels. The optional procedure in 
section 2.3 of this appendix may also be used for an affected gas-fired 
unit. For an affected unit that combusts any nonfossil fuels (e.g., 
bark, wood, residue, or refuse), either use a CO2 continuous 
emission monitoring system or apply to the Administrator for approval of 
a unit-specific method for determining CO2 emissions.
    2.1  Use the following equation to calculate daily CO2 mass 
emissions (in tons/day) from the combustion of fossil fuels. Where fuel 
flow is measured in a common pipe header (i.e., a pipe carrying fuel for 
multiple units), the owner or operator may use the procedures in section 
2.1.2 of appendix D of this part for combining or apportioning 
emissions, except that the term ``SO2 mass emissions'' is replaced 
with the term ``CO2 mass emissions.''
[GRAPHIC] [TIFF OMITTED] TR17MY95.021



[[Page 329]]


Where:

Wco2=CO2 emitted from combustion, tons/day.
MWc=Molecular weight of carbon (12.0).
MWo2=Molecular weight of oxygen (32.0)
WC=Carbon burned, lb/day, determined using fuel sampling and 
          analysis and fuel feed rates. Collect at least one fuel sample 
          during each week that the unit combusts coal or oil, one 
          sample per each shipment for diesel fuel, and one fuel sample 
          each month the unit combusts gaseous fuels. Collect coal 
          samples from a location in the fuel handling system that 
          provides a sample representative of the fuel bunkered or 
          consumed during the week. Determine the carbon content of each 
          fuel sampling using one of the following methods: ASTM D3178-
          89 for coal; ASTM D5291-92 ``Standard Test Methods for 
          Instrumental Determination of Carbon, Hydrogen, and Nitrogen 
          in Petroleum Products and Lubricants,'' ultimate analysis of 
          oil, or computations based upon ASTM D3238-90 and either ASTM 
          D2502-87 or ASTM D2503-82 (Reapproved 1987) for oil; and 
          computations based on ASTM D1945-91 or ASTM D1946-90 for gas. 
          Use daily fuel feed rates from company records for all fuels 
          and the carbon content of the most recent fuel sample under 
          this section to determine tons of carbon per day from 
          combustion of each fuel. (All ASTM methods are incorporated by 
          reference under Sec. 75.6). Where more than one fuel is 
          combusted during a calendar day, calculate total tons of 
          carbon for the day from all fuels.
    2.2  For an affected coal-fired unit, the estimate of daily CO2 
mass emissions given by Equation G-1 may be adjusted to account for 
carbon retained in the ash using the procedures in either section 2.2.1 
through 2.2.3 or section 2.2.4 of this appendix.
    2.2.1  Determine the ash content of the weekly sample of coal using 
ASTM D3174-89 ``Standard Test Method for Ash in the Analysis Sample of 
Coal and Coke From Coal'' (incorporated by reference under Sec. 75.6 of 
this part).
    2.2.2  Sample and analyze the carbon content of the fly-ash 
according to ASTM D3178-89, ``Standard Test Methods for Carbon and 
Hydrogen in the Analysis Sample of Coal and Coke'' (incorporated by 
reference under Sec. 75.6 of this part).
    2.2.3  Discount the estimate of daily CO2 mass emissions from 
the combustion of coal given by Equation G-1 by the percent carbon 
retained in the ash using the following equation:
[GRAPHIC] [TIFF OMITTED] TC01SE92.133

  ......................................................................
where,
WNCO2 = Net CO2 mass emissions discharged to the atmosphere, 
          tons/day.
WCO2 = Daily CO2 mass emissions calculated by Equation G-1, 
          tons/day.
MWC02 = Molecular weight of carbon dioxide (44.0).
MWc = Molecular weight of carbon (12.0).
A% = Ash content of the coal sample, percent by weight.
C% = Carbon content of ash, percent by weight.
WCOAL = Feed rate of coal from company records, tons/day.

    2.2.4  The daily CO2 mass emissions from combusting coal may be 
adjusted to account for carbon retained in the ash using the following 
equation:

WNCO2 = .99 WCO2
(Eq. G-3)

where,
WNCO2 = Net CO2 mass emissions from the combustion of coal 
          discharged to the atmosphere, tons/day.
.99 = Average fraction of coal converted into CO2 upon combustion.
WCO2 = Daily CO2 mass emissions from the combustion of coal 
          calculated by Equation G-1, tons/day.

    2.3  In lieu of using the procedures, methods, and equations in 
section 2.1 of this appendix, the owner or operator of an affected gas-
fired unit as defined under Sec. 72.2 of this chapter may use the 
following equation and records of hourly heat input to estimate hourly 
CO2 mass emissions (in tons).
[GRAPHIC] [TIFF OMITTED] TR17MY95.022

(Eq.G-4)

Where:

WCO2=CO2 emitted from combustion, tons/hr.
Fc=Carbon-based F-factor, 1,040 scf/mmBtu for natural gas; 1,420 scf/mm/
          btu for crude, residual, or distillate oil.

[[Page 330]]

H = Hourly heat input in mmBtu, as calculated using the procedures in 
          section 5 of appendix F of this part.
Uf=1/385 scf CO2/lb-mole at 14.7 psia and 68  deg.F.

      3. Procedures for Estimating CO2 Emissions From Sorbent

    When the affected unit has a wet flue gas desulfurization system, is 
a fluidized bed boiler, or uses other emission controls with sorbent 
injection, use either a CO2 continuous emission monitoring system 
or an O2 monitor and a flow monitor, or use the procedures, 
methods, and equations in sections 3.1 through 3.2 of this appendix to 
determine daily CO2 mass emissions from the sorbent (in tons).
    3.1  When limestone is the sorbent material, use the equations and 
procedures in either section 3.1.1 or 3.1.2 of this appendix.
    3.1.1  Use the following equation to estimate daily CO2 mass 
emissions from sorbent (in tons).
[GRAPHIC] [TIFF OMITTED] TC01SE92.134

  ......................................................................
(Eq. G-5)

where,
SECO2=CO2 emitted from sorbent, tons/day.
WCaCO3=CaCO3 used, tons/day.
Fu=1.00, the calcium to sulfur stoichiometric ratio.
MWCO2=Molecular weight of carbon dioxide (44).
MWCaCO3=Molecular weight of calcium carbonate (100).

    3.1.2  In lieu of using Equation G-5, any owner or operator who 
operates and maintains a certified SO2-diluent continuous emission 
monitoring system (consisting of an SO2 pollutant concentration 
monitor and an O2 or CO2 diluent gas monitor), for measuring 
and recording SO2 emission rate (in lb/mmBtu) at the outlet to the 
emission controls and who uses the applicable procedures, methods, and 
equations in Sec. 75.15 of this part to estimate the SO2 emissions 
removal efficiency of the emission controls, may use the following 
equations to estimate daily CO2 mass emissions from sorbent (in 
tons).
[GRAPHIC] [TIFF OMITTED] TC01SE92.135

  ......................................................................
(Eq. G-6)

where,
SECO2=CO2 emitted from sorbent, tons/day.
MWCO2=Molecular weight of carbon dioxide (44).
MWSO2=Molecular weight of sulfur dioxide (64).
WSO2=Sulfur dioxide removed, lb/day, as calculated below using Eq. 
          G-7.
Fu=1.0, the calcium to sulfur stoichiometric ratio.

and
[GRAPHIC] [TIFF OMITTED] TR17MY95.023

(Eq. G-7)
where:

WSO2=Weight of sulfur dioxide removed, lb/day.
SO20=SO2 mass emissions monitored at the outlet, lb/day, as 
          calculated using the equations and procedures in section 2 of 
          appendix F of this part.
%R=Overall percentage SO2 emissions removal efficiency, calculated 
          using Equations 1 through 7 in Sec. 75.15 using daily instead 
          of annual average emission rates.
    3.2  When a sorbent material other than limestone is used, modify 
the equations, methods, and procedures in Section 3.1 of this appendix 
as follows to estimate daily CO2 mass emissions from sorbent (in 
tons).
    3.2.1  Determine a site-specific value for Fu, defined as the 
ratio of the number of moles of CO2 released upon capture of one 
mole of SO2, using methods and procedures satisfactory to the 
Administrator. Use this value of Fu (instead of 1.0) in either 
Equation G-5 or Equation G-6.
    3.2.2  When using Equation G-5, replace MWCaCO3, the molecular 
weight of calcium carbonate, with the molecular weight of the sorbent 
material that participates in the reaction to capture SO2 and that 
releases CO2, and replace WCaCO3, the amount of calcium 
carbonate used (in tons/day), with the amount of sorbent material used 
(in tons/day).

[[Page 331]]

          4. Procedures for Estimating Total CO2 Emissions

    When the affected unit has a wet flue gas desulfurization system, is 
a fluidized bed boiler, or uses other emission controls with sorbent 
injection, use the following equation to obtain total daily CO2 
mass emissions (in tons) as the sum of combustion-related emissions and 
sorbent-related emissions.

Wt=WCO2+SECO2
(Eq. G-8)

where,
Wt=Estimated total CO2 mass emissions, tons/day.
WCO2=CO2 emitted from fuel combustion, tons/day.
SECO2=CO2 emitted from sorbent, tons/day.

[58 FR 3701, Jan. 11, 1993, as amended at 60 FR 26556-26557, May 17, 
1995; 61 FR 25585, May 22, 1996]

       Appendix H to Part 75--Revised Traceability Protocol No. 1

    This appendix consists of section 3.0.4 of the Quality Assurance 
Handbook for Air Pollution Measurement Systems, Vol. 3, U.S. 
Environmental Protection Agency (revised 6/9/87). The Quality Assurance 
Handbook may be obtained from the Methods Research and Development 
Division, MD 78-A, Atmospheric Research Exposure and Assessment 
Laboratory, U.S. Environmental Protection Agency, Research Triangle 
Park, North Carolina 27711.

   3.0.4. Procedure for NBS-Traceable Certification of Compressed Gas 
 Working Standards Used for Calibration and Audit of Continuous Source 
         Emission Monitors (Revised Traceability Protocol No. 1)

                                Contents

Subsection                            Title                             
3.0.4.0                               General Information               
3.0.4.1                               Procedure G1: Assay and           
                                       Certification of a Compressed Gas
                                       Standard Without Dilution        
3.0.4.2                               References                        
                                                                        

                        4.0  General Information

                4.0.1  Purpose and Scope of the Procedure

    Section 3.0.4 describes a procedure for assaying the concentration 
of gaseous pollutant concentration standards and certifying that the 
assay concentrations are traceable to an authoritative reference 
concentration standard. This procedure is recommended for certifying the 
local working concentration standards required by the pollutant 
monitoring regulations of 40 CFR Part 601,2 for the calibration and 
audit of continuous source emission monitors. The procedure covers 
certification of compressed gas (cylinder) standards for CO, CO2, 
NO, NO2, and SO2 (Procedure G1).

                       4.0.2  Reference Standards

    Part 60 of the monitoring regulations 1,2 requires that working 
standards used for calibration and audit of continuous source emission 
monitors be traceable to either a National Bureau of Standards (NBS) 
gaseous Standard Reference Material (SRM or a NBS/EPA-approved Certified 
reference material (CRM) 3. Accordingly, the reference standard 
used for assaying and certifying a working standard for these purposes 
must be an SRM, a CRM, or a suitable intermediate standard (see the next 
paragraph). SRM cylinder gas standards available from NBS are listed in 
Table 7.2 at the end of subsection 4.0. A current list of CRM cylinder 
gases and CRM vendors is available from the Quality Assurance Division 
(MD-77), Environmental Monitoring Systems Laboratory, U.S. EPA, Research 
Triangle Park, NC 27711.
    The EPA regulations define a ``traceable'' standard as one which``. 
. . has been compared and certified, either directly or via not more 
than one intermediate standard, to a primary standard such as a . . . 
NBS [gaseous] SRM or . . . CRM''4,5. Certification of a working 
standard directly to an SRM or CRM primary standard is, of course, 
preferred and recommended because of the lower error. However, an 
intermediate reference standard is permitted, if necessary. In 
particular, a Gas Manufacturer's Intermediate Standard (see subsection 
4.0.2.1) that has been referenced directly to an SRM or a CRM according 
to Procedure G1 is an acceptable intermediate standard and could be used 
as the reference standard on that basis. However, purchasers of 
commercial gas standards referenced to an intermediate standard such as 
a GMIS should be aware that, according to the above definition, such a 
standard would have to be used directly for calibration or audit. Since 
a second intermediate standard is not permitted, such a standard could 
not be used as a reference standard to certify other standards.
    4.0.2.1  Gas Manufacturer's Intermediate Standard (GMIS). A GMIS is 
a compressed (cylinder) gas standard that has been assayed with direct 
reference to an SRM or CRM and certified according to Procedure G1, and 
also meets the following requirements:
    1. A candidate GMIS must be assayed a minimum of three (3) times, 
uniformly spaced over a three (3) month period.
    2. Each of the three (or more) assays must be within 1.0 percent of 
the mean of the three (or more) assays.
    3. The difference between the last assay and the first assay must 
not exceed 1.5 percent of the mean of the three (or more) assays.

[[Page 332]]

    4. The GMIS must be recertified every three months, and the reassay 
must be within 1.5 percent of the previous certified assay. The 
recertified concentration of the GMIS is the mean of the previous 
certified concentration and the reassay concentration.
    4.0.2.2  Recertification of Reference Standards. Recertification 
requirements for SRMs and CRMs are specified by NBS and NBS/EPA, 
respectively. See 4.0.2.1 for GMIS recertification requirements.

                       4.0.3  Using the Procedure

    The assay/certification procedure described here is carefully 
designed to minimize both systematic and random errors in the assay 
process. Therefore, the procedure should be carried out as closely as 
possible to the way it is described. Similarly, the assay apparatus has 
been specifically designed to minimize errors and should be configured 
as closely as possible to the design specified. Good laboratory practice 
should be observed in the selection of inert materials (e.g. Teflon, 
stainless steel, or glass, if possible) and clean, non-contaminating 
components for use in portions of the apparatus in contact with the 
candidate or reference gas concentrations.

                   4.0.4  Certification Documentation

    Each assay/certification must be documented in a written 
certification report signed by the analyst and containing at least the 
following information:
    1. Identification number (cylinder number).
    2. Certified concentration of the standard, in ppm or mole percent.
    3. Balance gas in the standard mixture.
    4. Cylinder pressure at certification.
    5. Date of the assay/certification.
    6. Certification expiration date (see 4.0.6.3).
    7. Identification of the reference standard used: SRM number, 
cylinder number, and concentration for an SRM; cylinder number and 
concentration for a CRM or GMIS.
    8. Statement that the assay/certification was performed according to 
this section 3.0.4.
    9. Identification of the laboratory where the standard was certified 
and the analyst who performed the certification.
    10. Identification of the gas analyzer used for the certification, 
including the make, model, serial number, the measurement principle, and 
the date of the last multipoint calibration.
    11. All analyzer readings used during the assay/certification and 
the calculations used to obtain the reported certified value.
    12. Chronological record of all certifications for the standard.
    Certification concentrations should be reported to 3 significant 
digits. Certification documentation should be maintained for at least 3 
years.

                       4.0.5  Certification Label

    A label or tag bearing the information described in items 1 through 
9 of subsection 4.0.4 must be attached to each certified gas cylinder.
    4.0.6  Assay/Certification of Compressed Gas (Cylinder) Standards
    4.0.6.1  Aging of newly-prepared gas standards. Freshly prepared gas 
standard concentrations and newly filled gas cylinders must be aged 
before being assayed and certified. SO2 concentrations contained in 
steel cylinders must be aged at least 15 days; other standards must be 
aged at least 4 days.
    4.0.6.2  Stability test for reactive gas standards. Reactive gas 
standards, including nitric oxide (NO), nitrogen dioxide (NO2), 
sulfur dioxide (SO2), and carbon monoxide (CO), that have not been 
previously certified must be tested for stability as follows: Reassay 
the concentration at least 7 days after the first assay and compare the 
two assays. If the second assay differs from the first assay by 1.5% or 
less, the cylinder may be considered stable, and the mean of the two 
assays should be reported as the certified concentration. Otherwise, age 
the cylinder for a week or more and repeat the test, using the second 
and third assays as if they were the first and second assays. Cylinders 
that are not stable may not be sold and/or used for calibration or audit 
purposes.
    4.0.6.3  Recertification of compressed gas standards. Compressed gas 
standards must be recertified according to this section 3.0.4 within the 
time limits specified in Table 7.13,6,7. The reassay concentration 
must be within 5% of the previous certified concentration. If not, the 
cylinder must be retested for stability (subsection 4.0.6.2). The 
certified concentration of a recertified standard should be reported as 
the mean of all assays, unless a clear trend or substantial change 
suggests that previous assays are no longer valid.

                         Table 7.1.--Recertification Limits for Compressed Gas Standards                        
----------------------------------------------------------------------------------------------------------------
                                                                                          Maximum months until  
                                                                                           recertification for  
                                                                                            cylinder material   
              Pollutant                   Balance gas \1\        Concentration range   -------------------------
                                                                                         Passivated             
                                                                                          Aluminum      Other   
----------------------------------------------------------------------------------------------------------------
Carbon monoxide.....................  N2 or air..............   8 ppm......           36            6

[[Page 333]]

                                                                                                                
Nitric oxide........................  N2.....................   5 ppm......           24            6
Sulfur dioxide......................  N2 or air..............   50-499 ppm............           24            6
Sulfur dioxide......................  N2 or air..............   500 ppm....           36            6
Oxides of nitrogen..................  Air....................   100 ppm....           24            6
Nitrogen dioxide....................  Air....................   1000 ppm...           24            6
Carbon dioxide......................  N2 or air..............   300 ppm....           36           18
Carbon dioxide and oxygen, (i.e.      N2.....................   5% CO2, 0% O2.                                   
Oxygen..............................  N2.....................   2 percent..           36           18
Carbon dioxide and nitrous oxide....  Air....................   300 ppm               36            6
                                                                CO2, 300                             
                                                                ppb N2O.                                        
Others not specifically listed......  .......................  .......................            6            6
Multicomponent mixtures.............  ____...................  ____...................        See 2            6
Mixtures with lower concentrations..  ____...................  ____...................        See 3            6
----------------------------------------------------------------------------------------------------------------
1 When used as a balance gas, ``air'' is defined as a mixture of O2 and N2 where the minimum concentration of O2
  is 10% and the concentration of N2 is greater than 60%.                                                       
2 This protocol may be used to assay and certify individual components of multicomponent standards, provided    
  that none of the components interferes with the analysis of other components and provided that individual     
  components must not react with each other or with the balance gas. A multicomponent standard can be certified 
  for a period of time equal to that of its most briefly certifiable component. For example, a standard         
  containing 250 ppm sulfur dioxide and 100 ppm carbon monoxide in nitrogen can be certified for 24 months      
  because the shortest certification period is 24 months.                                                       
3 This protocol may be used for the certification of standards with concentrations that may be lower than those 
  listed in Table 7.1. The initial certification period for such a lower concentration standard is 6 months.    
  After this period, the standards may be recertified. If the recertification demonstrates that the standard is 
  not unstable, the second certification period for this lower concentration standard is the same time period as
  indicated for the corresponding concentration standard listed in Table 7.1.                                   


    4.0.6.4  Minimum cylinder pressure. No compressed gas cylinder 
standard should be used when its gas pressure is below 700 kPa (100 
psi), as indicated by the cylinder pressure gauge.
    4.0.6.5  Assay/certification of multi-component compressed gas 
standards. Procedure G1 may be used to assay and certify individual 
components of multi-component gas standards, provided that none of the 
components other than the component being assayed cause a detectable 
response on the analyzer.

                       4.0.7  Analyzer Calibration

    4.0.7.1  Basic analyzer calibration requirements. The assay 
procedure described in this section 3.0.4 employs a direct ratio 
referencing technique that inherently corrects for minor analyzer 
calibration variations (drift) and DOES NOT depend on the absolute 
accuracy of the analyzer calibration. What is required of the analyzer 
is as follows: 1) it must have a linear response to the pollutant of 
interest (see subsection 4.0.7.5), 2) it must have good resolution and 
low noise, 3) its response calibration must be reasonably stable during 
the assay/certification process, and 4) all assay concentration 
measurements must fall within the calibrated response range of the 
analyzer.
    4.0.7.2  Analyzer multipoint calibration. The gas analyzer used for 
the assay/certification must have had a multipoint calibration within 3 
months of its use when used with this procedure. This calibration is not 
used to quantitatively interpret analyzer readings during the assay/
certification of the candidate gas because a more accurate, direct ratio 
comparison of the candidate concentration to the reference standard 
concentration is used. However, this multipoint calibration is necessary 
to establish the calibrated range of the analyzer and its response 
linearity.
    The multipoint calibration should consist of analyzer responses to 
at least 5 concentrations, including zero, approximately evenly spaced 
over the concentration range. Analyzer response units may be volts, 
millivolts, percent of scale, or other measurable analyzer response 
units. The upper range limit of the calibrated range is determined by 
the highest calibration point used. If the analyzer has a choice of 
concentration ranges, the optimum range for the procedure should be 
selected and calibrated. Plot the calibration points and compute the 
linear regression slope and intercept. See subsection 4.0.7.5 for 
linearity requirements and the use of a mathematical transformation, if 
needed. The intercept should be less than 1 percent of the upper 
concentration range limit, and the correlation coefficient (r) should be 
at least 0.999.
    4.0.7.3  Zero and span check and adjustment. On each day that the 
analyzer will be used for assay/certification, its response calibration 
must be checked with a zero and at least one span concentration near the 
upper concentration range limit. If necessary, the zero and span 
controls of the analyzer should be adjusted so that the analyzer's 
response 

[[Page 334]]

(i.e. calibration slope) is within about 5 percent of the 
response indicated by the most recent multipoint calibration. If a zero 
or span adjustment is made, allow the analyzer to stabilize for at least 
an hour or more before beginning the assay procedure, since some 
analyzers drift for a period of time following zero or span adjustment. 
If the analyzer is not in continuous operation, turn it on and allow it 
to stabilize for at least 12 hours before the zero and span check.
    4.0.7.4  Pollutant standard for multipoint calibration and zero and 
span adjustment. The pollutant standard or standards used for multipoint 
calibration or zero and span checks or adjustments must be obtained from 
a compressed gas standard certified traceable to an NBS SRM or a NBS/EPA 
CRM according to Procedure G1 of this section 3.0.4. This standard need 
not be the same as the reference standard used in the assay/
certification. The zero gas must meet the requirements in subsection 
4.0.8.
    4.0.7.5  Linearity of analyzer response. The direct ratio assay 
technique used in Procedure G1 requires that the analyzer have a linear 
response to concentration. Linearity is determined by comparing the 
quantitative difference between a smoothly-drawn calibration curve based 
on all calibration points and a straight line drawn between zero and an 
upper reference point (see Figure 1). This difference is measured in 
concentration units, parallel to the concentration axis, from a point on 
the calibration curve to the corresponding point for the same response 
on the straight line.
    For the general linearity requirement, the straight line is drawn 
between zero and the highest calibration point (Figure 1a). Linearity is 
then acceptable when no point on the smooth calibration curve deviates 
from the straight line by more than 1.5 percent of the value of the 
highest calibration concentration. An alternative linearity requirement 
is defined on the basis of the actual reference and candidate 
concentrations to be used for the assay. In this case, the reference and 
candidate concentrations are plotted on the calibration curve, and the 
straight line is drawn from zero to the reference concentration and 
extrapolated, if necessary, beyond the candidate concentration (Figure 
1b). The deviation of the smooth calibration curve from the straight 
line at the candidate concentration point then must not exceed 0.8 
percent of the value of the reference concentration. This latter 
specification may allow the use of an analyzer having greater 
nonlinearity when the reference and candidate concentrations are nearly 
the same.
    For analyzers having an inherently non-linear response, the response 
can usually be linearized with a simple mathematical transformation of 
the response values, such as R'=square root(R) or R'=log(R), where R' is 
the transformed response value and R is the actual analyzer response 
value. Using the transformed response values, the multipoint calibration 
should meet one of the above linearity requirements as well as the 
requirements for intercept and correlation coefficient given in 
subsection 4.0.7.2.

                             4.0.8  Zero Gas

    Zero gas used for dilution of any candidate or reference standard 
should be clean, dry, zero-grade air or nitrogen containing a 
concentration of the pollutant of interest equivalent to less than 0.5 
percent of the analyzer's upper range limit concentration. The zero gas 
also should contain no contaminant that causes a detectable response on 
the analyzer or that suppresses or enhances the analyzer's response to 
the pollutant. The oxygen content of zero air should be the same as that 
of ambient air.

     4.0.9  Accuracy Assessment of Commercially Available Standards

    Periodically, the USEPA will assess the accuracy of commercially 
available compressed gas standards that have been assayed and certified 
according to this section 3.0.4. Accuracy will be assessed by EPA audit 
analysis of representative actual commercial standards obtained via an 
anonymous agent. The accuracy audit results, identifying the actual gas 
manufacturers or vendors, will be published as public information.

[[Page 335]]

[GRAPHIC] [TIFF OMITTED] TC01SE92.136



[[Page 336]]



                   Table 7.2.--NBS SRM Reference Gases                  
------------------------------------------------------------------------
                                                           Nominal      
            SRM No.                     Type            concentration   
------------------------------------------------------------------------
2627...........................  NO/N2.............  5 ppm.             
2628...........................  NO/N2.............  10 ppm.            
2629...........................  NO/N2.............  20 ppm.            
1683b..........................  NO/N2.............  50 ppm.            
1684b..........................  NO/N2.............  100 ppm.           
1685b..........................  NO/N2.............  250 ppm.           
1686b..........................  NO/N2.............  500 ppm.           
1687b..........................  NO/N2.............  1000 ppm.          
2630...........................  NO/N2.............  1500 ppm.          
2631...........................  NO/N2.............  3000 ppm.          
2653...........................  NO/2Air...........  250 ppm.           
2654...........................  NO/2Air...........  500 ppm.           
2655...........................  NO/2Air...........  1000 ppm.          
2656...........................  NO/2Air...........  2500 ppm.          
2612a..........................  CO/Air............  10 ppm.            
2613a..........................  CO/Air............  20 ppm.            
2614a..........................  CO/Air............  45 ppm.            
1677c..........................  CO/N2.............  10 ppm.            
2635...........................  CO/N2.............  25 ppm.            
1678c..........................  CO/N2.............  50 ppm.            
1679c..........................  CO/N2.............  100 ppm.           
2636...........................  CO/N2.............  250 ppm.           
1680c..........................  CO/N2.............  500 ppm.           
1681c..........................  CO/N2.............  1000 ppm.          
2637...........................  CO/N2.............  2500 ppm.          
2638...........................  CO/N2.............  5000 ppm.          
2639...........................  CO/N2.............  1 percent.         
2640...........................  CO/N2.............  2 percent.         
2641...........................  CO/N2.............  4 percent.         
2642...........................  CO/N2.............  8 percent.         
2657...........................  O2/N2.............  2 percent.         
2658...........................  O2/N2.............  10 percent.        
2659...........................  O2/N2.............  21 percent.        
1693...........................  SO2/N2............  50 ppm.            
1694...........................  SO2/N2............  100 ppm.           
1661a..........................  SO2/N2............  500 ppm.           
1662a..........................  SO2/N2............  1000 ppm.          
1663a..........................  SO2/N2............  1500 ppm.          
1664a..........................  SO2/N2............  2500 ppm.          
1696...........................  SO2/N2............  3500 ppm.          
1670...........................  CO2/Air...........  330 ppm.           
1671...........................  CO2/Air...........  340 ppm.           
1672...........................  CO2/Air...........  350 ppm.           
2632...........................  CO2/N2............  300 ppm.           
2633...........................  CO2/N2............  400 ppm.           
2634...........................  CO2/N2............  800 ppm.           
2619a..........................  CO2/N2............  0.5 percent.       
2720a..........................  CO2/N2............  1.0 percent.       
2621a..........................  CO2/N2............  1.5 percent.       
2622a..........................  CO2/N2............  2.0 percent.       
2623a..........................  CO2/N2............  2.5 percent.       
2624a..........................  CO2/N2............  3.0 percent.       
2625a..........................  CO2/N2............  3.5 percent.       
2626a..........................  CO2/N2............  4.0 percent.       
1674b..........................  CO2/N2............  7.0 percent.       
1675b..........................  CO2/N2............  14.0 percent.      
1665b..........................  C3H8/Air..........  3 ppm.             
1666b..........................  C3H8/Air..........  10 ppm.            
1667b..........................  C3H8/Air..........  50 ppm.            
1668b..........................  C3H8/Air..........  100 ppm.           
1669b..........................  C3H8/Air..........  500 ppm.           
2643...........................  C3H8/N2...........  100 ppm.           
2644...........................  C3H8/N2...........  250 ppm.           
2645...........................  C3H8/N2...........  500 ppm.           
2646...........................  C3H8/N2...........  1000 ppm.          
2647...........................  C3H8/N2...........  2500 ppm.          
2648...........................  C3H8/N2...........  5000 ppm.          
2649...........................  C3H8/N2...........  1 percent.         
2650...........................  C3H8/N2...........  2 percent.         
------------------------------------------------------------------------
NBS-SRM cylinders contain approximately 870 liters of gas at STP.       
For availability, contact: Office of Standard Reference Materials,      
  Chemistry Building, Room B311, NBS, Gaithersburg, Maryland 20899,     
  (301) 975-6776. (FTS 879-6776).                                       

4.1  Procedure G1: Assay and Certification of a Compressed Gas Standard 
                            Without Dilution

                          4.1.1  Applicability

    This procedure may be used to assay the concentration of a candidate 
compressed gas (cylinder) pollutant standard, based on the concentration 
of a compressed gas (cylinder) reference standard of the same pollutant 
compound, and certify that the assayed concentration thus established 
for the candidate standard is traceable to the reference standard. The 
procedure employs a pollutant gas analyzer to compare the candidate and 
reference gas concentrations by direct measurement--without dilution of 
either gas--to minimize assay error.

                           4.1.2  Limitations

    1. The concentration of the candidate gas standard must be between 
0.3. and 1.3 times the concentration of the reference gas standard.
    2. The analyzer must have a calibrated range capable of directly 
measuring both the candidate and the reference gas concentrations.
    3. The analyzer's response (or transformed response) must be linear 
with respect to concentration.
    4. The balance gas in both the candidate and reference standards 
must be identical, unless it can be shown that the analyzer is 
insensitive to any difference in the balance gases.
    5. A source of clean, dry zero gas is required.

                         4.1.3  Assay Apparatus

    Figure G1 illustrates the relatively simple assay apparatus. The 
configuration is designed to allow convenient routing of the zero gas 
and undiluted samples of the reference gas and candidate gases, in turn, 
to the analyzer for measurement, as selected by three-way valves V1 and 
V2. Pressure regulators and needle valves (V3 and V4) control the 
individual gas flows. The pollutant concentrations are delivered to the 
analyzer via a vented tee, which discharges excess flow and insures that 
the assay concentrations sampled by the analyzer are always at a fixed 
(atmospheric) pressure. A small, uncalibrated rotameter monitors the 
vent flow to verify that the total gas flow rate exceeds the sample flow 
rate demand of the analyzer so that no room air is admitted through the 
vent. Valves V1 and V2 could be replaced by a single four-way valve 
(with 3 inputs and 1 output) or by manually moving the output connection 
to each of the gases as needed. See also subsection 4.0.3.

[[Page 337]]

[GRAPHIC] [TIFF OMITTED] TC01SE92.137



[[Page 338]]

                             4.1.4  Analyzer

    See subsection 4.0.7.1. The pollutant gas analyzer must have a 
linear response function and a calibrated range capable of measuring the 
full concentration of both the candidate and the reference gas standards 
directly, without dilution. It must have good resolution (readability), 
good precision, a stable response, and low output signal noise. In 
addition, the analyzer must have good specificity for the pollutant of 
interest so that it has no detectable response to any contaminant that 
may be contained in either the candidate or reference gas. If the 
candidate and reference gases contain dissimilar balance gases (air 
versus nitrogen or different proportions of oxygen in the balance air, 
for example), the analyzer must be proven to be insensitive to the 
different balance gases. This may be accomplished by showing no 
difference in analyzer response when measuring pollutant concentrations 
diluted with identical flow rates of the two balance gases.
    The analyzer should be connected to a suitable, precision chart 
recorder or other data acquisition device to facilitate graphical 
observation and documentation of the analyzer responses obtained during 
the assay.

                       4.1.5  Analyzer Calibration

    4.1.5.1  Multipoint calibration. See subsections 4.0.7.2 and 
4.0.7.4.
    4.1.5.2  Calibration range. The calibrated range of the analyzer 
must include both the candidate and reference gas concentrations, such 
that the higher concentration does not exceed 97 percent of the upper 
range limit, and the lower concentration is not below 25 percent of the 
upper range limit (assuming a lower range limit of zero). Within these 
limits, select a calibrated analyzer range that will produce the highest 
analyzer responses.
    4.1.5.3  Linearity. The direct ratio assay technique used in this 
procedure requires that the analyzer have a linear response to 
concentration (see subsection 4.0.7.5). High-concentration-range 
analyzers of the type that are required for this procedure may not be 
inherently linear, but they usually have a predictable, non-linear 
response characteristic that can be mathematically transformed to 
produce a sufficiently linear response characteristic suitable for use 
in this procedure. Any such response transformation should be verified 
by using it for the multipoint calibration. Caution should be exercised 
in using a transformed response curve because physical zero or span 
adjustments to the analyzer may produce unexpected effects on the 
transformed characteristic.
    4.1.5.4  Zero and span adjustment. See subsections 4.0.7.3 and 
4.0.7.4. Prior to carrying out the assay/certification procedure, check 
the calibration of the analyzer and, if necessary, adjust the analyzer's 
zero and span controls to reestablish the response characteristic 
determined at the most recent multipoint calibration. Allow the analyzer 
to stabilize for an hour or more after any zero or span adjustment. If 
there is any doubt that a transformed response characteristic is still 
linear following a zero or span adjustment, verify linearity with a 
multipoint calibration (subsection 4.0.7.2) using at least 3 known 
pollutant concentrations, including zero.

                           4.1.6  Assay Gases

    4.1.6.1  Candidate gas standard. See subsections 4.0.6 and 4.1.2.
    4.1.6.2  Reference gas standard. See subsections 4.0.2, 4.1.2, and 
4.0.6.4. Select a reference standard such that the concentration of the 
candidate gas is not more than 30 percent above nor less than 70 percent 
below the concentration of the standard.
    4.1.6.3  Zero gas. See subsection 4.0.8. The zero gas should match 
the balance gas used in the cylinder concentrations.

                         4.1.7  Assay Procedure

    1. Verify that the assay apparatus is properly configured, as 
described in subsection 4.1.3 and shown in Figure G1.
    2. Verify that the linearity of the analyzer has been checked within 
the last 3 months (see subsections 4.0.7.2, 4.0.7.5, and 4.1.4), that 
the zero and span are adjusted correctly (subsection 4.0.7.3), that the 
candidate and reference gas concentrations are within 25 and 97 percent 
of the upper range limit of the calibrated measurement range of the 
analyzer, and that the analyzer is operating stably.
    3. Adjust the flow rates of the three gases (reference, candidate, 
and zero) to approximately the same value that will provide enough flow 
for the analyzer and sufficient excess to assure that no ambient air 
will be drawn into the vent.
    4. Conduct a triad of measurements with the analyzer. Each triad 
consists of a measurement of the zero gas concentration, a measurement 
of the reference gas concentration, and a measurement of the candidate 
gas concentration. Use valves V1 and V2 to select each of the three 
concentrations for measurement. For each measurement, allow ample time 
for the analyzer to achieve a stable response reading. Record the stable 
analyzer response for each measurement, using the same response units 
(volt, millivolts, percent of scale, etc.) used for the multipoint 
calibration and any transformation of the response readings necessary 
for linearity. Do not translate the response readings to concentration 
values via the calibration curve (see the footnote following Equation 
G1). Do not make any zero, span, or other physical

[[Page 339]]

adjustments to the analyzer during the triad of measurements.
    5. Conduct at least 2 additional measurement triads, similar to step 
4 above. However, for these subsequent triads, change the order of the 
three measurements (e.g. measure reference gas, zero gas, candidate gas 
for the second triad and zero gas, candidate gas, reference gas for the 
third triad, etc.).
    6. If any one or more of the measurements of a triad is invalid or 
abnormal for any reason, discard all three measurements of the triad and 
repeat the triad.
    7. For each triad of measurements, calculate the assay concentration 
of the candidate gas as follows:
[GRAPHIC] [TIFF OMITTED] TC01SE92.138

  
Equation G1

where:
Cc=Assay concentration of the candidate gas standard, ppm or 
          percent;
Cr=Concentration of the reference gas standard, ppm or percent;
Rc=Stable response reading of the analyzer for the candidate gas, 
          analyzer response units;*
Rz=Stable response reading of the analyzer for the zero gas, 
          analyzer response units;*
Rr=Stable response reading of the analyzer for the reference gas, 
          analyzer response units.*

*Analyzer response units are the units used to express the direct 
response readings of the analyzer, such as volts, millivolts, percent of 
scale, etc. DO NOT convert these direct response readings to 
concentration units with the multipoint calibration curve or otherwise 
adjust these readings except for transformation necessary to achieve 
response linearity.

    8. Calculate the mean of the 3 (or more) valid assays. Calculate the 
percent difference of each assay from the mean. If any one of the assay 
values differs from the mean by more than 1.5%, discard that assay value 
and conduct another triad of measurements to obtain another assay value. 
When at least 3 assay values all agree within 1.5% of their mean, report 
the mean value as the certified concentration of the candidate gas 
standard. For newly-prepared reactive standards, a reassay at least 7 
days later is required to check the stability of the standard; see 
subsection 4.0.6.2.

           4.1.8  Stability Test for Newly-Prepared Standards

    See subsections 4.0.6.1 and 4.0.6.2.

                   4.1.9  Certification Documentation

    See subsections 4.0.4 and 4.0.5.

                  4.1.10  Recertification Requirements

    See subsections 4.0.6.3 and 4.0.6.4.

                             4.2  References

    1. Code of Federal Regulations, title 40, part 60, ``Standards of 
Performance for New Stationary Sources,'' appendix A, Method 20 (1982).
    2. Standards of Performance for New Stationary Sources; Quality 
Assurance Requirements for Gaseous Continuous Emission Monitoring 
Systems Used for Compliance Determination, promulgated in the Federal 
Register, June 4, 1987, pp. 21003-21010.
    3. ``A Procedure for Establishing Traceability of Gas Mixtures to 
Certain National Bureau of Standards Standard Reference Materials. EPA-
600/7-81-010. Joint publication by NBS and EPA, May 1981. Available from 
the U.S. Environmental Protection Agency, Environmental Monitoring 
Systems Laboratory (MD-77), Research Triangle Park, NC 27711.
    4. Code of Federal Regulation, title 40, part 50, ``National Ambient 
Air Quality Measurement Methodology''.
    5. Code of Federal Regulations, title 40, part 58, ``Ambient Air 
Quality Surveillance,'' appendixes A and B.
    6. Shores, R.C. and F. Smith, ``Stability Evaluation of Sulfur 
Dioxide, Nitric Oxide, and Carbon Monoxide Gases in Cylinders''. NTIS 
No. PB 85-122646. Available from the National Technical Information 
Service, 5285 Port Royal Road, Springfield, VA 22161.
    7. Method 6A and 6B, ``Determination of Sulfur Dioxide, Moisture, 
and Carbon Dioxide Emissions from Fossil Fuel Combustion Sources,'' 
Quality Assurance Handbook for Air Pollution Measurement Systems, Volume 
III, Section 3.13.8, July 1986. Available from the U.S. Environmental 
Protection Agency, Center for Environmental Research Information, 
Cincinnati, OH 45268.
    8. ``List of Designated Reference and Equivalent Methods.'' Current 
edition available from the U.S. Environmental Protection Agency, 
Environmental Monitoring Systems Laboratory, Quality Assurance Division 
(MD-77), Research Triangle Park, NC 27711.

[58 FR 3701, Jan. 11, 1993; 58 FR 40751, 40752, July 30, 1993]

[[Page 340]]

  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

                      1. Recordkeeping Requirements

    The owner or operator shall meet the recordkeeping requirements of 
subpart F of this part by following either Secs. 75.50, 75.51 and 75.52 
or Secs. 75.54, 75.55 and 75.56, from July 17, 1995 through December 31, 
1995. On or after January 1, 1996, the owner or operator shall meet the 
recordkeeping requirements of subpart F of this part by meeting the 
requirements of Secs. 75.54, 75.55, and 75.56.

                 2. Missing Data Substitution Procedures

    The owner or operator shall meet the missing data substitution 
requirements for carbon dioxide (CO2) and heat input by following 
either Secs. 75.35 and 75.36 or sections 4.3.1 through 4.3.3, section 
4.4.3 and sections 5.3 through 5.4 of appendix F of this part from July 
17, 1995 through December 31, 1995. The owner or operator shall meet the 
missing data substitution requirements for fuel flowmeters in appendix D 
of this part by following either section 2.4.3.1 or sections 2.4.3.2 and 
2.4.3.3 of appendix D of this part from July 17, 1995 through December 
31, 1995. On or after January 1, 1996, the owner or operator shall meet 
the missing data substitution requirements for CO2 concentration, 
that input and fuel flowmeters by meeting the requirements of 
Secs. 75.35 and 75.36 and sections 2.4.3.2 through 2.4.3.3 of appendix D 
of this part.

[60 FR 26557, May 17, 1995]



PART 76--ACID RAIN NITROGEN OXIDES EMISSION REDUCTION PROGRAM--Table of Contents




Sec.
76.1  Applicability.
76.2  Definitions.
76.3  General Acid Rain Program provisions.
76.4  Incorporation by reference.
76.5  NOX emission limitations for Group 1 boilers.
76.6  NOX emission limitations for Group 2 boilers. [Reserved]
76.7  Revised NOX emission limitations for Group 1, Phase II 
          boilers. [Reserved]
76.8  Early election for Group 1, Phase II boilers.
76.9  Permit application and compliance plans.
76.10  Alternative emission limitations.
76.11  Emissions averaging.
76.12  Phase I NOX compliance extensions.
76.13  Compliance and excess emissions.
76.14  Monitoring, recordkeeping, and reporting.
76.15  Test methods and procedures.
76.16  [Reserved]

Appendix A to Part 76--Phase I Affected Coal-Fired Utility Units With 
          Group 1 or Cell Burner Boilers

Appendix B to Part 76--Procedures and Methods for Estimating Costs of 
          Nitrogen Oxides Controls Applied to Group 1, Phase I Boilers

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

    Source: 60 FR 18761, Apr. 13, 1995, unless otherwise noted.



Sec. 76.1  Applicability.

    (a) Except as provided in paragraphs (b) through (d) of this 
section, the provisions apply to each coal-fired utility unit that is 
subject to an Acid Rain emissions limitation or reduction requirement 
for SO2 under Phase I or Phase II pursuant to sections 404, 405, or 
409 of the Act.
    (b) The emission limitations for NOX under this part apply to 
each affected coal-fired utility unit subject to section 404(d) or 
409(b) of the Act on the date the unit is required to meet the Acid Rain 
emissions reduction requirement for SO2.
    (c) The provisions of this part apply to each coal-fired 
substitution unit or compensating unit, designated and approved as a 
Phase I unit pursuant to Sec. 72.41 or Sec. 72.43 of this chapter as 
follows:
    (1) A coal-fired substitution unit that is designated in a 
substitution plan that is approved and active as of January 1, 1995 
shall be treated as a Phase I coal-fired utility unit for purposes of 
this part. In the event the designation of such unit as a substitution 
unit is terminated after December 31, 1995, pursuant to Sec. 72.41 of 
this chapter and the unit is no longer required to meet Phase I SO2 
emissions limitations, the provisions of this part (including those 
applicable in Phase I) will continue to apply.
    (2) A coal-fired substitution unit that is designated in a 
substitution plan that is not approved or not active as of January 1, 
1995, or a coal-fired compensating unit, shall be treated as a Phase II 
coal-fired utility unit for purposes of this part.

[[Page 341]]

    (d) The provisions of this part for Phase I units apply to each 
coal-fired transfer unit governed by a Phase I extension plan, approved 
pursuant to Sec. 72.42 of this chapter, on January 1, 1997. 
Notwithstanding the preceding sentence, a coal-fired transfer unit shall 
be subject to the Acid Rain emissions limitations for nitrogen oxides 
beginning on January 1, 1996 if, for that year, a transfer unit is 
allocated fewer Phase I extension reserve allowances than the maximum 
amount that the designated representative could have requested in 
accordance with Sec. 72.42(c)(5) of this chapter (as adjusted under 
Sec. 72.42(d) of this chapter) unless the transfer unit is the last unit 
allocated Phase I extension reserve allowances under the plan.



Sec. 76.2  Definitions.

    All terms used in this part shall have the meaning set forth in the 
Act, in Sec. 72.2 of this chapter, and in this section as follows:
    Alternative contemporaneous annual emission limitation means the 
maximum allowable NOX emission rate (on a lb/mmBtu, annual average 
basis) assigned to an individual unit in a NOX emissions averaging 
plan pursuant to Sec. 76.10.
    Alternative technology means a control technology for reducing 
NOX emissions that is outside the scope of the definition of low 
NOX burner technology. Alternative technology does not include 
overfire air as applied to wall-fired boilers or separated overfire air 
as applied to tangentially fired boilers.
    Approved clean coal technology demonstration project means a project 
using funds appropriated under the Department of Energy's ``Clean Coal 
Technology Demonstration Program,'' up to a total amount of 
$2,500,000,000 for commercial demonstration of clean coal technology, or 
similar projects funded through appropriations for the Environmental 
Protection Agency. The Federal contribution for a qualifying project 
shall be at least 20 percent of the total cost of the demonstration 
project.
    Cell burner boiler means a wall-fired boiler that utilizes two or 
three circular burners combined into a single vertically oriented 
assembly that results in a compact, intense flame. Any low NOX 
retrofit of a cell burner boiler that reuses the existing cell burner, 
close-coupled wall opening configuration would not change the 
designation of the unit as a cell burner boiler.
    Coal-fired utility unit means a utility unit in which the combustion 
of coal (or any coal-derived fuel) on a Btu basis exceeds 50.0 percent 
of its annual heat input, for Phase I units in calendar year 1990 and, 
for Phase II units in the calendar year 1995. For the purposes of this 
part, this definition shall apply notwithstanding the definition at 
Sec. 72.2 of this chapter.
    Cyclone boiler means a boiler with one or more water-cooled 
horizontal cylindrical chambers in which coal combustion takes place. 
The horizontal cylindrical chamber(s) is (are) attached to the bottom of 
the furnace. One or more cylindrical chambers are arranged either on one 
furnace wall or on two opposed furnace walls. Gaseous combustion 
products exiting from the chamber(s) turn 90 degrees to go up through 
the boiler while coal ash exits the bottom of the boiler as a molten 
slag.
    Demonstration period means a period of time not less than 15 months, 
approved under Sec. 76.10, for demonstrating that the affected unit 
cannot meet the applicable emission limitation under Sec. 76.5, 76.6, or 
76.7 and establishing the minimum NOX emission rate that the unit 
can achieve during long-term load dispatch operation.
    Dry bottom means the boiler has a furnace bottom temperature below 
the ash melting point and the bottom ash is removed as a solid.
    Economizer means the lowest temperature heat exchange section of a 
utility boiler where boiler feed water is heated by the flue gas.
    Flue gas means the combustion products arising from the combustion 
of fossil fuel in a utility boiler.
    Group 1 boiler means a tangentially fired boiler or a dry bottom 
wall-fired boiler (other than a unit applying cell burner technology).
    Group 2 boiler means a wet bottom wall-fired boiler, a cyclone 
boiler, a boiler applying cell burner technology, a vertically fired 
boiler, an arch-fired

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boiler, or any other type of utility boiler (such as a fluidized bed or 
stoker boiler) that is not a Group 1 boiler.
    Low NOX burners and low NOX burner technology means 
commercially available combustion modification NOX controls that 
minimize NOX formation by introducing coal and its associated 
combustion air into a boiler such that initial combustion occurs in a 
manner that promotes rapid coal devolatilization in a fuel-rich (i.e., 
oxygen deficient) environment and introduces additional air to achieve a 
final fuel-lean (i.e., oxygen rich) environment to complete the 
combustion process. This definition shall include the staging of any 
portion of the combustion air using air nozzles or registers located 
inside any waterwall hole that includes a burner. This definition shall 
exclude the staging of any portion of the combustion air using air 
nozzles or ports located outside any waterwall hole that includes a 
burner (commonly referred to as NOX ports or separated overfire air 
ports).
    Operating period means a period of time of not less than three 
consecutive months and that occurs not more than one month prior to 
applying for an alternative emission limitation demonstration period 
under Sec. 76.10, during which the owner or operator of an affected unit 
that cannot meet the applicable emission limitation:
    (1) Operates the installed NOX emission controls in accordance 
with primary vendor specifications and procedures, with the unit 
operating under normal conditions; and
    (2) records and reports quality-assured continuous emission 
monitoring (CEM) and unit operating data according to the methods and 
procedures in part 75 of this chapter.
    Primary vendor means the vendor of the NOX emission control 
system who has primary responsibility for providing the equipment, 
service, and technical expertise necessary for detailed design, 
installation, and operation of the controls, including process data, 
mechanical drawings, operating manuals, or any combination thereof.
    Reburning means reducing the coal and combustion air to the main 
burners and injecting a reburn fuel (such as gas or oil) to create a 
fuel-rich secondary combustion zone above the main burner zone and final 
combustion air to create a fuel-lean burnout zone. The formation of 
NOX is inhibited in the main burner zone due to the reduced 
combustion intensity, and NOX is destroyed in the fuel-rich 
secondary combustion zone by conversion to molecular nitrogen.
    Selective catalytic reduction means a noncombustion control 
technology that destroys NOX by injecting a reducing agent (e.g., 
ammonia) into the flue gas that, in the presence of a catalyst (e.g., 
vanadium, titanium, or zeolite), converts NOX into molecular 
nitrogen and water.
    Selective noncatalytic reduction means a noncombustion control 
technology that destroys NOX by injecting a reducing agent (e.g., 
ammonia, urea, or cyanuric acid) into the flue gas, downstream of the 
combustion zone that converts NOX to molecular nitrogen, water, and 
when urea or cyanuric acid are used, to carbon dioxide (CO2).
    Stoker boiler means a boiler that burns solid fuel in a bed, on a 
stationary or moving grate, that is located at the bottom of the 
furnace.
    Tangentially fired boiler means a boiler that has coal and air 
nozzles mounted in each corner of the furnace where the vertical furnace 
walls meet. Both pulverized coal and air are directed from the furnace 
corners along a line tangential to a circle lying in a horizontal plane 
of the furnace.
    Turbo-fired boiler means a pulverized coal, wall-fired boiler with 
burners arranged on walls so that the individual flames extend down 
toward the furnace bottom and then turn back up through the center of 
the furnace.
    Wall-fired boiler means a boiler that has pulverized coal burners 
arranged on the walls of the furnace. The burners have discrete, 
individual flames that extend perpendicularly into the furnace area.
    Wet bottom means the boiler has a furnace bottom temperature above 
the ash melting point and the bottom ash is removed as a liquid.



Sec. 76.3  General Acid Rain Program provisions.

    The following provisions of part 72 of this chapter shall apply to 
this part:

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    (a) Sec. 72.2  (Definitions);
    (b) Sec. 72.3  (Measurements, abbreviations, and acronyms);
    (c) Sec. 72.4  (Federal authority);
    (d) Sec. 72.5  (State authority);
    (e) Sec. 72.6  (Applicability);
    (f) Sec. 72.7  (New unit exemption);
    (g) Sec. 72.8  (Retired units exemption);
    (h) Sec. 72.9  (Standard requirements);
    (i) Sec. 72.10  (Availability of information); and
    (j) Sec. 72.11  (Computation of time).
    In addition, the procedures for appeals of decisions of the 
Administrator under this part are contained in part 78 of this chapter.



Sec. 76.4  Incorporation by reference.

    (a) The materials listed in this section are incorporated by 
reference in the sections noted. These incorporations by reference 
(IBR's) were approved by the Director of the Federal Register in 
accordance with 5 U.S.C. 552(a) and 1 CFR part 51. These materials are 
incorporated as they existed on the date of approval, and notice of any 
change in these materials will be published in the Federal Register. The 
materials are available for purchase at the corresponding address noted 
below and are available for inspection at the Office of the Federal 
Register, 800 North Capitol St., NW., 7th Floor, Suite 700, Washington, 
DC, at the Public Information Reference Unit, U.S. EPA, 401 M Street, 
SW., Washington, DC, and at the Library (MD-35), U.S. EPA, Research 
Triangle Park, North Carolina.
    (b) The following materials are available for purchase from at least 
one of the following addresses: American Society for Testing and 
Materials (ASTM), 1916 Race Street, Philadelphia, Pennsylvania 19103; or 
the University Microfilms International, 300 North Zeeb Road, Ann Arbor, 
Michigan 48106.
    (1) ASTM D 3176-89, Standard Practice for Ultimate Analysis of Coal 
and Coke, IBR approved May 23, 1995 for Sec. 76.15.
    (2) ASTM D 3172-89, Standard Practice for Proximate Analysis of Coal 
and Coke, IBR approved May 23, 1995 for Sec. 76.15.
    (c) The following material is available for purchase from the 
American Society of Mechanical Engineers (ASME), 22 Law Drive, Box 2350, 
Fairfield, NJ 07007-2350.
    (1) ASME Performance Test Code 4.2 (1991), Test Code for Coal 
Pulverizers, IBR approved May 23, 1995 for Sec. 76.15.
    (2) [Reserved]
    (d) The following material is available for purchase from the 
American National Standards Institute, 11 West 42nd Street, New York, NY 
10036 or from the International Organization for Standardization (ISO), 
Case Postale 56, CH-1211 Geneve 20, Switzerland.
    (1) ISO 9931 (December, 1991) ``Coal--Sampling of Pulverized Coal 
Conveyed by Gases in Direct Fired Coal Systems,'' IBR approved May 23, 
1995 for Sec. 76.15.
    (2) [Reserved]



Sec. 76.5  NOX emission limitations for Group 1 boilers.

    (a) Beginning January 1, 1996, or for a unit subject to section 
404(d) of the Act, the date on which the unit is required to meet Acid 
Rain emission reduction requirements for SO2, the owner or operator 
of a Phase I coal-fired utility unit with a tangentially fired boiler or 
a dry bottom wall-fired boiler (other than units applying cell burner 
technology) shall not discharge, or allow to be discharged, emissions of 
NOX to the atmosphere in excess of the following limits, except as 
provided in paragraphs (c) or (e) of this section or in Sec. 76.10, 
76.11, or 76.12:
    (1) 0.45 lb/mmBtu of heat input on an annual average basis for 
tangentially fired boilers.
    (2) 0.50 lb/mmBtu of heat input on an annual average basis for dry 
bottom wall-fired boilers (other than units applying cell burner 
technology).
    (b) The owner or operator shall determine the annual average 
NOX emission rate, in lb/mmBtu, using the methods and procedures 
specified in part 75 of this chapter.
    (c) Unless the unit meets the early election requirement of 
Sec. 76.8, the owner or operator of a coal-fired substitution unit with 
a tangentially fired boiler or a dry bottom wall-fired boiler (other 
than units applying cell burner technology) that satisfies the 
requirements of Sec. 76.1(c)(2), shall comply with

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the NOX emission limitations that apply to Group 1, Phase II 
boilers.
    (d) The owner or operator of a Phase I unit with a cell burner 
boiler that converts to a conventional wall-fired boiler on or before 
January 1, 1995 or, for a unit subject to section 404(d) of the Act, the 
date the unit is required to meet Acid Rain emissions reduction 
requirements for SO2 shall comply, by such respective date or 
January 1, 1996, whichever is later, with the NOX emissions 
limitation applicable to dry bottom wall-fired boilers under paragraph 
(a) of this section, except as provided in paragraphs (c) or (e) of this 
section or in Sec. 76.10, 76.11, or 76.12.
    (e) The owner or operator of a Phase I unit with a Group 1 boiler 
that converts to a fluidized bed or other type of utility boiler not 
included in Group 1 boilers on or before January 1, 1995 or, for a unit 
subject to section 404(d) of the Act, the date the unit is required to 
meet Acid Rain emissions reduction requirements for SO2 is exempt 
from the NOX emissions limitations specified in paragraph (a) of 
this section, but shall comply with the NOX emission limitations 
for Group 2 boilers under Sec. 76.6.
    (f) Except as provided in Sec. 76.8 and in paragraph (c) of this 
section, each unit subject to the requirements of this section is not 
subject to the requirements of Sec. 76.7.
    (g) Beginning January 1, 2000, the owner or operator of a Group 1, 
Phase II coal-fired utility unit with a tangentially fired boiler or a 
wall-fired boiler shall be subject to the emission limitations in 
paragraph (a) of this section.



Sec. 76.6  NOX emission limitations for Group 2 boilers.  [Reserved]



Sec. 76.7  Revised NOX emission limitations for Group 1, Phase II boilers.  [Reserved]



Sec. 76.8  Early election for Group 1, Phase II boilers.

    (a) General provisions. (1) The owner or operator of a Phase II 
coal-fired utility unit with a Group 1 boiler may elect to have the unit 
become subject to the applicable emissions limitation for NOX under 
Sec. 76.5, starting no later than January 1, 1997.
    (2) The owner or operator of a Phase II coal-fired utility unit with 
a Group 1 boiler that elects to become subject to the applicable 
emission limitation under Sec. 76.5 shall not be subject to any revised 
NOX emissions limitation for Group 1 boilers that the Administrator 
may issue pursuant to section 407(b)(2) of the Act until January 1, 
2008, provided the designated representative demonstrates that the unit 
is in compliance with the limitation under Sec. 76.5, using the methods 
and procedures specified in part 75 of this chapter, for the period 
beginning January 1 of the year in which the early election takes effect 
(but not later than January 1, 1997) and ending December 31, 2007.
    (3) The owner or operator of any Phase II unit with a cell burner 
boiler that converts to conventional burner technology may elect to 
become subject to the applicable emissions limitation under Sec. 76.5 
for dry bottom wall-fired boilers, provided the owner or operator 
complies with the provisions in paragraph (a)(2) of this section.
    (4) The owner or operator of a Phase II unit approved for early 
election shall not submit an application for an alternative emissions 
limitation demonstration period under Sec. 76.10 until the earlier of:
    (i) January 1, 2008; or
    (ii) Early election is terminated pursuant to paragraph (e)(3) of 
this section.
    (5) The owner or operator of a Phase II unit approved for early 
election may not incorporate the unit into an averaging plan prior to 
January 1, 2000. On or after January 1, 2000, for purposes of the 
averaging plan, the early election unit will be treated as subject to 
the applicable emissions limitation for NOX for Phase II units with 
Group 1 boilers under Sec. 76.5(g) and if revised emission limitations 
are issued for Group 1 boilers pursuant to section 407(b)(2) of the Act, 
Sec. 76.7.
    (b) Submission requirements. In order to obtain early election 
status, the designated representative of a Phase II unit with a Group 1 
boiler shall submit an early election plan to the Administrator by 
January 1 of the year the early election is to take effect, but not

[[Page 345]]

later than January 1, 1997. Notwithstanding Sec. 72.40 of this chapter, 
and unless the unit is a substitution unit under Sec. 72.41 of this 
chapter or a compensating unit under Sec. 72.43 of this chapter, a 
complete compliance plan covering the unit shall not include the 
provisions for SO2 emissions under Sec. 72.40(a)(1) of this 
chapter.
    (c) Contents of an early election plan. A complete early election 
plan shall include the following elements in a format prescribed by the 
Administrator:
    (1) A request for early election;
    (2) The first year for which early election is to take effect, but 
not later than 1997; and
    (3) The special provisions under paragraph (e) of this section.
    (d)(1) Permitting authority's action. To the extent the 
Administrator determines that an early election plan complies with the 
requirements of this section, the Administrator will approve the plan 
and:
    (i) If a Phase I Acid Rain permit governing the source at which the 
unit is located has been issued, will revise the permit in accordance 
with the permit modification procedures in Sec. 72.81 of this chapter to 
include the early election plan; or
    (ii) If a Phase I Acid Rain permit governing the source at which the 
unit is located has not been issued, will issue a Phase I Acid Rain 
permit effective from January 1, 1995 through December 31, 1999, that 
will include the early election plan and a complete compliance plan 
under Sec. 72.40(a) of this chapter and paragraph (b) of this section. 
If the early election plan is not effective until after January 1, 1995, 
the permit will not contain any NOX emissions limitations until the 
effective date of the plan.
    (2) Beginning January 1, 2000, the permitting authority will approve 
any early election plan previously approved by the Administrator during 
Phase I, unless the plan is terminated pursuant to paragraph (e)(3) of 
this section.
    (e) Special provisions--(1) Emissions limitations--(i) Sulfur 
dioxide. Notwithstanding Sec. 72.9 of this chapter, a unit that is 
governed by an approved early election plan and that is not a 
substitution unit under Sec. 72.41 of this chapter or a compensating 
unit under Sec. 72.43 of this chapter shall not be subject to the 
following standard requirements under Sec. 72.9 of this chapter for 
Phase I:
    (A) The permit requirements under Secs. 72.9(a)(1) (i) and (ii) of 
this chapter;
    (B) The sulfur dioxide requirements under Sec. 72.9(c) of this 
chapter; and
    (C) The excess emissions requirements under Sec. 72.9(e)(1) of this 
chapter.
    (ii) Nitrogen oxides. A unit that is governed by an approved early 
election plan shall be subject to an emissions limitation for NOX 
as provided under paragraph (a)(2) of this section except as provided 
under paragraph (e)(3)(iii) of this section.
    (2) Liability. The owners and operators of any unit governed by an 
approved early election plan shall be liable for any violation of the 
plan or this section at that unit. The owners and operators shall be 
liable, beginning January 1, 2000, for fulfilling the obligations 
specified in part 77 of this chapter.
    (3) Termination. An approved early election plan shall be in effect 
only until the earlier of January 1, 2008 or January 1 of the calendar 
year for which a termination of the plan takes effect.
    (i) If the designated representative of the unit under an approved 
early election plan fails to demonstrate compliance with the applicable 
emissions limitation under Sec. 76.5 for any year during the period 
beginning January 1 of the first year the early election takes effect 
and ending December 31, 2007, the permitting authority will terminate 
the plan. The termination will take effect beginning January 1 of the 
year after the year for which there is a failure to demonstrate 
compliance, and the designated representative may not submit a new early 
election plan.
    (ii) The designated representative of the unit under an approved 
early election plan may terminate the plan any year prior to 2008 but 
may not submit a new early election plan. In order to terminate the 
plan, the designated representative must submit a notice under 
Sec. 72.40(d) of this chapter by January 1 of the year for which the 
termination is to take effect.
    (iii)(A) If an early election plan is terminated any year prior to 
2000, the unit shall meet, beginning January 1,

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2000, the applicable emissions limitation for NOX for Phase II 
units with Group 1 boilers under Sec. 76.5(g) and, if revised emission 
limitations are issued pursuant to section 407(b)(2) of the Act, 
Sec. 76.7.
    (B) If an early election plan is terminated in or after 2000, the 
unit shall meet, beginning on the effective date of the termination, the 
applicable emissions limitation for NOX for Phase II units with 
Group 1 boilers under Sec. 76.5(g) and, if revised emission limitations 
are issued pursuant to section 407(b)(2) of the Act, Sec. 76.7.



Sec. 76.9  Permit application and compliance plans.

    (a) Duty to apply. (1) The designated representative of any source 
with an affected unit subject to this part shall submit, by the 
applicable deadline under paragraph (b) of this section, a complete Acid 
Rain permit application (or, if the unit is covered by an Acid Rain 
permit, a complete permit revision) that includes a complete compliance 
plan for NOX emissions covering the unit.
    (2) The original and three copies of the permit application and 
compliance plan for NOX emissions for Phase I shall be submitted to 
the EPA regional office for the region where the applicable source is 
located. The original and three copies of the permit application and 
compliance plan for NOX emissions for Phase II shall be submitted 
to the permitting authority.
    (b) Deadlines. (1) For a Phase I unit with a Group 1 boiler, the 
designated representative shall submit a complete permit application and 
compliance plan for NOX covering the unit during Phase I to the 
applicable permitting authority not later than May 6, 1994.
    (2) For a Phase I or Phase II unit with a Group 2 boiler or a Phase 
II unit with a Group 1 boiler, the designated representative shall 
submit a complete permit application and compliance plan for NOX 
emissions covering the unit in Phase II to the Administrator not later 
than January 1, 1998, except that early election units shall also submit 
an application not later than January 1, 1997.
    (c) Information requirements for NOX compliance plans. (1) In 
accordance with Sec. 72.40(a)(2) of this chapter, a complete compliance 
plan for NOX shall, for each affected unit included in the permit 
application and subject to this part, either certify that the unit will 
comply with the applicable emissions limitation under Sec. 76.5, 76.6, 
or 76.7 or specify one or more other Acid Rain compliance options for 
NOX in accordance with the requirements of this part. A complete 
compliance plan for NOX for a source shall include the following 
elements in a format prescribed by the Administrator:
    (i) Identification of the source;
    (ii) Identification of each affected unit that is at the source and 
is subject to this part;
    (iii) Identification of the boiler type of each unit;
    (iv) Identification of the compliance option proposed for each unit 
(i.e., meeting the applicable emissions limitation under Sec. 76.5, 
76.6, 76.7, 76.8 (early election), 76.10 (alternative emission 
limitation), 76.11 (NOX emissions averaging), or 76.12 (Phase I 
NOX compliance extension)) and any additional information required 
for the appropriate option in accordance with this part;
    (v) Reference to the standard requirements in Sec. 72.9 of this 
chapter (consistent with Sec. 76.8(e)(1)(i)); and
    (vi) The requirements of Secs. 72.21 (a) and (b) of this chapter.
    (d) Duty to reapply. The designated representative of any source 
with an affected unit subject to this part shall submit a complete Acid 
Rain permit application, including a complete compliance plan for 
NOX emissions covering the unit, in accordance with the deadlines 
in Sec. 72.30(c) of this chapter.



Sec. 76.10  Alternative emission limitations.

    (a) General provisions. (1) The designated representative of an 
affected unit that is not an early election unit pursuant to Sec. 76.8 
and cannot meet the applicable emission limitation in Sec. 76.5, 76.6, 
or 76.7 using, for Group 1 boilers, either low NOX burner 
technology or an alternative technology in accordance with paragraph 
(e)(11) of this section, or, for tangentially fired boilers, separated 
overfire air, or, for Group 2 boilers, the technology on which the 
applicable emission limitation is based may

[[Page 347]]

petition the permitting authority for an alternative emission limitation 
less stringent than the applicable emission limitation.
    (2) In order for the unit to qualify for an alternative emission 
limitation, the designated representative shall demonstrate that the 
affected unit cannot meet the applicable emission limitation in 
Sec. 76.5, 76.6, or 76.7 based on a showing, to the satisfaction of the 
Administrator, that:
    (i)(A) For a tangentially fired boiler, the owner or operator has 
either properly installed low NOX burner technology or properly 
installed separated overfire air; or
    (B) For a dry bottom wall-fired boiler (other than a unit applying 
cell burner technology), the owner or operator has properly installed 
low NOX burner technology; or
    (C) For a Group 1 boiler, the owner or operator has properly 
installed an alternative technology (including but not limited to 
reburning, selective noncatalytic reduction, or selective catalytic 
reduction) that achieves NOX emission reductions demonstrated in 
accordance with paragraph (e)(11) of this section; or
    (D) For a Group 2 boiler, the owner or operator has properly 
installed the appropriate NOX emission control technology on which 
the applicable emission limitation in Sec. 76.6 is based; and
    (ii) The installed NOX emission control system has been 
designed to meet the applicable emission limitation in Sec. 76.5, 76.6, 
or 76.7; and
    (iii) For a demonstration period of at least 15 months or other 
period of time, as provided in paragraph (f)(1) of this section:
    (A) The NOX emission control system has been properly installed 
and properly operated according to specifications and procedures 
designed to minimize the emissions of NOX to the atmosphere;
    (B) Unit operating data as specified in this section show that the 
unit and NOX emission control system were operated in accordance 
with the bid and design specifications on which the design of the 
NOX emission control system was based; and
    (C) Unit operating data as specified in this section, continuous 
emission monitoring data obtained pursuant to part 75 of this chapter, 
and the test data specific to the NOX emission control system show 
that the unit could not meet the applicable emission limitation in 
Sec. 76.5, 76.6, or 76.7.
    (b) Petitioning process. The petitioning process for an alternative 
emission limitation shall consist of the following steps:
    (1) Operation during a period of at least 3 months, following the 
installation of the NOX emission control system, that shows that 
the specific unit and the NOX emission control system was unable to 
meet the applicable emissions limitation under Sec. 76.5, 76.6, or 76.7 
and was operated in accordance with the operating conditions upon which 
the design of the NOX emission control system was based and with 
vendor specifications and procedures;
    (2) Submission of a petition for an alternative emission limitation 
demonstration period as specified in paragraph (d) of this section;
    (3) Operation during a demonstration period of at least 15 months, 
or other period of time as provided in paragraph (f)(1) of this section, 
that demonstrates the inability of the specific unit to meet the 
applicable emissions limitation under Sec. 76.5, 76.6, or 76.7 and the 
minimum NOX emissions rate that the specific unit can achieve 
during long-term load dispatch operation; and
    (4) Submission of a petition for a final alternative emission 
limitation as specified in paragraph (e) of this section.
    (c) Deadlines--(1) Petition for an alternative emission limitation 
demonstration period. The designated representative of the unit shall 
submit a petition for an alternative emission limitation demonstration 
period to the permitting authority after the unit has been operated for 
at least 3 months after installation of the NOX emission control 
system required under paragraph (a)(2) of this section and by the 
following deadline:
    (i) For units that seek to have an alternative emission limitation 
demonstration period apply during all or part of calendar year 1996, or 
any previous calendar year by the later of:
    (A) 120 days after startup of the NOX emission control system, 
or

[[Page 348]]

    (B) May 1, 1996.
    (ii) For units that seek an alternative emission limitation 
demonstration period beginning in a calendar year after 1996, not later 
than:
    (A) 120 days after January 1 of that calendar year, or
    (B) 120 days after startup of the NOX emission control system 
if the unit is not operating at the beginning of that calendar year.
    (2) Petition for a final alternative emission limitation. Not later 
than 90 days after the end of an approved alternative emission 
limitation demonstration period for the unit, the designated 
representative of the unit may submit a petition for an alternative 
emission limitation to the permitting authority.
    (3) Renewal of an alternative emission limitation. In order to 
request continuation of an alternative emission limitation, the 
designated representative must submit a petition to renew the 
alternative emission limitation on the date that the application for 
renewal of the source's Acid Rain permit containing the alternative 
emission limitation is due.
    (d) Contents of petition for an alternative emission limitation 
demonstration period. The designated representative of an affected unit 
that has met the minimum criteria under paragraph (a) of this section 
and that has been operated for a period of at least 3 months following 
the installation of the required NOX emission control system may 
submit to the permitting authority a petition for an alternative 
emission limitation demonstration period. In the petition, the 
designated representative shall provide the following information in a 
format prescribed by the Administrator:
    (1) Identification of the unit;
    (2) The type of NOX control technology installed (e.g., low 
NOX burner technology, selective noncatalytic reduction, selective 
catalytic reduction, reburning);
    (3) If an alternative technology is installed, the time period (not 
less than 6 consecutive months) prior to installation of the technology 
to be used for the demonstration required in paragraph (e)(11) of this 
section.
    (4) Documentation as set forth in Sec. 76.14(a)(1) showing that the 
installed NOX emission control system has been designed to meet the 
applicable emission limitation in Sec. 76.5, 76.6, or 76.7 and that the 
system has been properly installed according to procedures and 
specifications designed to minimize the emissions of NOX to the 
atmosphere;
    (5) The date the unit commenced operation following the installation 
of the NOX emission control system or the date the specific unit 
became subject to the emission limitations of Sec. 76.5, 76.6, or 76.7, 
whichever is later;
    (6) The dates of the operating period (which must be at least 3 
months long);
    (7) Certification by the designated representative that the owner(s) 
or operator operated the unit and the NOX emission control system 
during the operating period in accordance with: Specifications and 
procedures designed to achieve the maximum NOX reduction possible 
with the installed NOX emission control system or the applicable 
emission limitation in Sec. 76.5, 76.6, or 76.7; the operating 
conditions upon which the design of the NOX emission control system 
was based; and vendor specifications and procedures;
    (8) A brief statement describing the reason or reasons why the unit 
cannot achieve the applicable emission limitation in Sec. 76.5, 76.6, or 
76.7;
    (9) A demonstration period plan, as set forth in Sec. 76.14(a)(2);
    (10) Unit operating data and quality-assured continuous emission 
monitoring data (including the specific data items listed in 
Sec. 76.14(a)(3) collected in accordance with part 75 of this chapter 
during the operating period) and demonstrating the inability of the 
specific unit to meet the applicable emission limitation in Sec. 76.5, 
76.6, or 76.7 on an annual average basis while operating as certified 
under paragraph (d)(7) of this section;
    (11) An interim alternative emission limitation, in lb/mmBtu, that 
the unit can achieve during a demonstration period of at least 15 
months. The interim alternative emission limitation shall be derived 
from the data specified in paragraph (d)(10) of this section using 
methods and procedures satisfactory to the Administrator;
    (12) The proposed dates of the demonstration period (which must be 
at least 15 months long);

[[Page 349]]

    (13) A report which outlines the testing and procedures to be taken 
during the demonstration period in order to determine the maximum 
NOX emission reduction obtainable with the installed system. The 
report shall include the reasons for the NOX emission control 
system's failure to meet the applicable emission limitation, and the 
tests and procedures that will be followed to optimize the NOX 
emission control system's performance. Such tests and procedures may 
include those identified in Sec. 76.15 as appropriate.
    (14) The special provisions at paragraph (g)(1) of this section.
    (e) Contents of petition for a final alternative emission 
limitation. After the approved demonstration period, the designated 
representative of the unit may petition the permitting authority for an 
alternative emission limitation. The petition shall include the 
following elements in a format prescribed by the Administrator:
    (1) Identification of the unit;
    (2) Certification that the owner(s) or operator operated the 
affected unit and the NOX emission control system during the 
demonstration period in accordance with: specifications and procedures 
designed to achieve the maximum NOX reduction possible with the 
installed NOX emission control system or the applicable emissions 
limitation in Sec. 76.5, 76.6, or 76.7; the operating conditions 
(including load dispatch conditions) upon which the design of the 
NOX emission control system was based; and vendor specifications 
and procedures.
    (3) Certification that the owner(s) or operator have installed in 
the affected unit all NOX emission control systems, made any 
operational modifications, and completed any planned upgrades and/or 
maintenance to equipment specified in the approved demonstration period 
plan for optimizing NOX emission reduction performance, consistent 
with the demonstration period plan and the proper operation of the 
installed NOX emission control system. Such certification shall 
explain any differences between the installed NOX emission control 
system and the equipment configuration described in the approved 
demonstration period plan.
    (4) A clear description of each step or modification taken during 
the demonstration period to improve or optimize the performance of the 
installed NOX emission control system.
    (5) Engineering design calculations and drawings that show the 
technical specifications for installation of any additional operational 
or emission control modifications installed during the demonstration 
period.
    (6) Unit operating and quality-assured continuous emission 
monitoring data (including the specific data listed in Sec. 76.14(b)) 
collected in accordance with part 75 of this chapter during the 
demonstration period and demonstrating the inability of the specific 
unit to meet the applicable emission limitation in Sec. 76.5, 76.6, or 
76.7 on an annual average basis while operating in accordance with the 
certification under paragraph (e)(2) of this section.
    (7) A report (based on the parametric test requirements set forth in 
the approved demonstration period plan as identified in paragraph 
(d)(13) of this section), that demonstrates the unit was operated in 
accordance with the operating conditions upon which the design of the 
NOX emission control system was based and describes the reason or 
reasons for the failure of the installed NOX emission control 
system to meet the applicable emission limitation in Sec. 76.5, 76.6, or 
76.7 on an annual average basis.
    (8) The minimum NOX emission rate, in lb/mmBtu, that the 
affected unit can achieve on an annual average basis with the installed 
NOX emission control system. This value, which shall be the 
requested alternative emission limitation, shall be derived from the 
data specified in this section using methods and procedures satisfactory 
to the Administrator and shall be the lowest annual emission rate the 
unit can achieve with the installed NOX emission control system;
    (9) All supporting data and calculations documenting the 
determination of the requested alternative emission limitation and its 
conformance with the methods and procedures satisfactory to the 
Administrator;
    (10) The special provisions in paragraph (g)(2) of this section.

[[Page 350]]

    (11) In addition to the other requirements of this section, the 
owner or operator of an affected unit with a Group 1 boiler that has 
installed an alternative technology in addition to or in lieu of low 
NOX burner technology and cannot meet the applicable emission 
limitation in Sec. 76.5 shall demonstrate, to the satisfaction of the 
Administrator, that the actual percentage reduction in NOX 
emissions (lbs/mmBtu), on an annual average basis is greater than 65 
percent of the average annual NOX emissions prior to the 
installation of the NOX emission control system. The percentage 
reduction in NOX emissions shall be determined using continuous 
emissions monitoring data for NOX taken during the time period 
(under paragraph (d)(3) of this section) prior to the installation of 
the NOX emission control system and during long-term load dispatch 
operation of the specific boiler.
    (f) Permitting authority's action--(1) Alternative emission 
limitation demonstration period. (i) The permitting authority may 
approve an alternative emission limitation demonstration period and 
demonstration period plan, provided that the requirements of this 
section are met to the satisfaction of the permitting authority. The 
permitting authority shall disapprove a demonstration period if the 
requirements of paragraph (a) of this section were not met during the 
operating period.
    (ii) If the demonstration period is approved, the permitting 
authority will include, as part of the demonstration period, the 4 month 
period prior to submission of the application in the demonstration 
period.
    (iii) The alternative emission limitation demonstration period will 
authorize the unit to emit at a rate not greater than the interim 
alternative emission limitation during the demonstration period on or 
after January 1, 1996 for Phase I units and the applicable date 
established in Sec. 76.5(g) or 76.6 for Phase II units, and until the 
date that the Administrator approves or denies a final alternative 
emission limitation.
    (iv) After an alternative emission limitation demonstration period 
is approved, if the designated representative requests an extension of 
the demonstration period in accordance with paragraph (g)(1)(i)(B) of 
this section, the permitting authority may extend the demonstration 
period by administrative amendment (under Sec. 72.83 of this chapter) to 
the Acid Rain permit.
    (v) The permitting authority shall deny the demonstration period if 
the designated representative cannot demonstrate that the unit met the 
requirements of paragraph (a)(2) of this section. In such cases, the 
permitting authority shall require that the owner or operator operate 
the unit in compliance with the applicable emission limitation in 
Sec. 76.5, 76.6, or 76.7 for the period preceding the submission of the 
application for an alternative emission limitation demonstration period, 
including the operating period, if such periods are after the date on 
which the unit is subject to the standard limit under Sec. 76.5, 76.6, 
or 76.7.
    (2) Alternative emission limitation. (i) If the permitting authority 
determines that the requirements in this section are met, the permitting 
authority will approve an alternative emission limitation and issue or 
revise an Acid Rain permit to apply the approved limitation, in 
accordance with subparts F and G of part 72 of this chapter. The permit 
will authorize the unit to emit at a rate not greater than the approved 
alternative emission limitation, starting the date the permitting 
authority revises an Acid Rain permit to approve an alternative emission 
limitation.
    (ii) If a permitting authority disapproves an alternative emission 
limitation under paragraph (a)(2) of this section, the owner or operator 
shall operate the affected unit in compliance with the applicable 
emission limitation in Sec. 76.5, 76.6, or 76.7 (unless the unit is 
participating in an approved averaging plan under Sec. 76.11) beginning 
on the date the permitting authority revises an Acid Rain permit to 
disapprove an alternative emission limitation.
    (3) Alternative emission limitation renewal. (i) If, upon review of 
a petition to renew an approved alternative emission limitation, the 
permitting authority determines that no changes have been made to the 
control technology, its operation, the operating conditions on which the 
alternative emission limitation was based, or the actual NOX

[[Page 351]]

emission rate, the alternative emission limitation will be renewed.
    (ii) If the permitting authority determines that changes have been 
made to the control technology, its operation, the fuel quality, or the 
operating conditions on which the alternative emission limitation was 
based, the designated representative shall submit, in order to renew the 
alternative emission limitation or to obtain a new alternative emission 
limitation, a petition for an alternative emission limitation 
demonstration period that meets the requirements of paragraph (d) of 
this section using a new demonstration period.
    (g) Special provisions--(1) Alternative emission limitation 
demonstration period--(i) Emission limitations. (A) Each unit with an 
approved alternative emission limitation demonstration period shall 
comply with the interim emission limitation specified in the unit's 
permit beginning on the effective date of the demonstration period 
specified in the permit and, if a timely petition for a final 
alternative emission limitation is submitted, extending until the date 
on which the permitting authority issues or revises an Acid Rain permit 
to approve or disapprove an alternative emission limitation. If a timely 
petition is not submitted, then the unit shall comply with the standard 
emission limit under Sec. 76.5, 76.6, or 76.7 beginning on the date the 
petition was required to be submitted under paragraph (c)(2) of this 
section.
    (B) When the owner or operator identifies, during the demonstration 
period, boiler operating or NOX emission control system 
modifications or upgrades that would produce further NOX emission 
reductions, enabling the affected unit to comply with or bring its 
emission rate closer to the applicable emissions limitation under 
Sec. 76.5, 76.6, or 76.7, the designated representative may submit a 
request and the permitting authority may grant, by administrative 
amendment under Sec. 72.83 of this chapter, an extension of the 
demonstration period for such period of time (not to exceed 12 months) 
as may be necessary to implement such modifications or upgrades.
    (C) If the approved interim alternative emission limitation applies 
to a unit for part, but not all, of a calendar year, the unit shall 
determine compliance for the calendar year in accordance with the 
procedures in Sec. 76.13(a).
    (ii) Operating requirements. (A) A unit with an approved alternative 
emission limitation demonstration period shall be operated under load 
dispatch conditions consistent with the operating conditions upon which 
the design of the NOX emission control system and performance 
guarantee were based, and in accordance with the demonstration period 
plan.
    (B) A unit with an approved alternative emission limitation 
demonstration period shall install all NOX emission control 
systems, make any operational modifications, and complete any upgrades 
and maintenance to equipment specified in the approved demonstration 
period plan for optimizing NOX emission reduction performance.
    (C) When the owner or operator identifies boiler or NOX 
emission control system operating modifications that would produce 
higher NOX emission reductions, enabling the affected unit to 
comply with, or bring its emission rate closer to, the applicable 
emission limitation under Sec. 76.5, 76.6, or 76.7, the designated 
representative shall submit an administrative amendment under Sec. 72.83 
of this chapter to revise the unit's Acid Rain permit and demonstration 
period plan to include such modifications.
    (iii) Testing requirements. A unit with an approved alternative 
emission limitation demonstration period shall monitor in accordance 
with part 75 of this chapter and shall conduct all tests required under 
the approved demonstration period plan.
    (2) Final alternative emission limitation--(i) Emission limitations. 
(A) Each unit with an approved alternative emission limitation shall 
comply with the alternative emission limitation specified in the unit's 
permit beginning on the date specified in the permit as issued or 
revised by the permitting authority to apply the final alternative 
emission limitation.
    (B) If the approved interim or final alternative emission limitation 
applies to a unit for part, but not all, of a calendar year, the unit 
shall determine

[[Page 352]]

compliance for the calendar year in accordance with the procedures in 
Sec. 76.13(a).



Sec. 76.11  Emissions averaging.

    (a) General provisions. In lieu of complying with the applicable 
emission limitation in Sec. 76.5, 76.6, or 76.7, any affected units 
subject to such emission limitation, under control of the same owner or 
operator, and having the same designated representative may average 
their NOX emissions under an averaging plan approved under this 
section.
    (1) Each affected unit included in an averaging plan for Phase I 
shall be a Phase I unit with a Group 1 boiler subject to an emission 
limitation in Sec. 76.5 during all years for which the unit is included 
in the plan.
    (i) If a unit with an approved NOX compliance extension is 
included in an averaging plan for 1996, the unit shall be treated, for 
the purposes of applying Equation 1 in paragraph (a)(6) of this section 
and Equation 2 in paragraph (d)(1)(ii)(A) of this section, as subject to 
the applicable emissions limitation under Sec. 76.5 for the entire year 
1996.
    (ii) A Phase II unit approved for early election under Sec. 76.8 
shall not be included in an averaging plan for Phase I.
    (2) Each affected unit included in an averaging plan for Phase II 
shall be a boiler subject to an emission limitation in Sec. 76.5, 76.6, 
or 76.7 for all years for which the unit is included in the plan.
    (3) Each unit included in an averaging plan shall have an 
alternative contemporaneous annual emission limitation (lb/mmBtu) and 
can only be included in one averaging plan.
    (4) Each unit included in an averaging plan shall have a minimum 
allowable annual heat input value (mmBtu), if it has an alternative 
contemporaneous annual emission limitation more stringent than that 
unit's applicable emission limitation under Sec. 76.5, 76.6, or 76.7, 
and a maximum allowable annual heat input value, if it has an 
alternative contemporaneous annual emission limitation less stringent 
than that unit's applicable emission limitation under Sec. 76.5, 76.6, 
or 76.7.
    (5) The Btu-weighted annual average emission rate for the units in 
an averaging plan shall be less than or equal to the Btu-weighted annual 
average emission rate for the same units had they each been operated, 
during the same period of time, in compliance with the applicable 
emission limitations in Sec. 76.5, 76.6, or 76.7.
    (6) In order to demonstrate that the proposed plan is consistent 
with paragraph (a)(5) of this section, the alternative contemporaneous 
annual emission limitations and annual heat input values assigned to the 
units in the proposed averaging plan shall meet the following 
requirement:
[GRAPHIC] [TIFF OMITTED] TR13AP95.000

Where:

RLi = Alternative contemporaneous annual emission limitation for 
unit i, lb/mmBtu, as specified in the averaging plan;
Rli = Applicable emission limitation for unit i, lb/mmBtu, as 
specified in Sec. 76.5, 76.6, or 76.7 except that for early election 
units, which may be included in an averaging plan only on or after 
January 1, 2000, Rli shall equal the most stringent applicable 
emission limitation under Sec. 76.5 or 76.7;
HIi = Annual heat input for unit i, mmBtu, as specified in the 
averaging plan;
n = Number of units in the averaging plan.


[[Page 353]]


    (7) For units with an alternative emission limitation, Rli 
shall equal the applicable emissions limitation under Sec. 76.5, 76.6, 
or 76.7, not the alternative emissions limitation.
    (8) No unit may be included in more than one averaging plan.
    (b)(1) Submission requirements. The designated representative of a 
unit meeting the requirements of paragraphs (a)(1), (a)(2), and (a)(8) 
of this section may submit an averaging plan (or a revision to an 
approved averaging plan) to the permitting authority(ies) at any time up 
to and including January 1 (or July 1, if the plan is restricted to 
units located within a single permitting authority's jurisdiction) of 
the calendar year for which the averaging plan is to become effective.
    (2) The designated representative shall submit a copy of the same 
averaging plan (or the same revision to an approved averaging plan) to 
each permitting authority with jurisdiction over a unit in the plan.
    (3) When an averaging plan (or a revision to an approved averaging 
plan) is not approved, the owner or operator of each unit in the plan 
shall operate the unit in compliance with the emission limitation that 
would apply in the absence of the averaging plan (or revision to a 
plan).
    (c) Contents of NOX averaging plan. A complete NOX 
averaging plan shall include the following elements in a format 
prescribed by the Administrator:
    (1) Identification of each unit in the plan;
    (2) Each unit's applicable emission limitation in Sec. 76.5, 76.6, 
or 76.7;
    (3) The alternative contemporaneous annual emission limitation for 
each unit (in lb/mmBtu). If any of the units identified in the NOX 
averaging plan utilize a common stack pursuant to Sec. 75.17(a)(2)(i)(B) 
of this chapter, the same alternative contemporaneous emission 
limitation shall be assigned to each such unit and different heat input 
limits may be assigned;
    (4) The annual heat input limit for each unit (in mmBtu);
    (5) The calculation for Equation 1 in paragraph (a)(6) of this 
section;
    (6) The calendar years for which the plan will be in effect; and
    (7) The special provisions in paragraph (d)(1) of this section.
    (d) Special provisions.--(1) Emission limitations. Each affected 
unit in an approved averaging plan is in compliance with the Acid Rain 
emission limitation for NOX under the plan only if the following 
requirements are met:
    (i) For each unit, the unit's actual annual average emission rate 
for the calendar year, in lb/mmBtu, is less than or equal to its 
alternative contemporaneous annual emission limitation in the averaging 
plan; and
    (A) For each unit with an alternative contemporaneous emission 
limitation less stringent than the applicable emission limitation in 
Sec. 76.5, 76.6, or 76.7, the actual annual heat input for the calendar 
year does not exceed the annual heat input limit in the averaging plan;
    (B) For each unit with an alternative contemporaneous annual 
emission limitation more stringent than the applicable emission 
limitation in Sec. 76.5, 76.6, or 76.7, the actual annual heat input for 
the calendar year is not less than the annual heat input limit in the 
averaging plan; or
    (ii) If one or more of the units does not meet the requirements 
under paragraph (d)(1)(i) of this section, the designated representative 
shall demonstrate, in accordance with paragraph (d)(1)(ii)(A) of this 
section (Equation 2) that the actual Btu-weighted annual average 
emission rate for the units in the plan is less than or equal to the 
Btu-weighted annual average rate for the same units had they each been 
operated, during the same period of time, in compliance with the 
applicable emission limitations in Sec. 76.5, 76.6, or 76.7.
    (A) A group showing of compliance shall be made based on the 
following equation:

[[Page 354]]

[GRAPHIC] [TIFF OMITTED] TR13AP95.001


Where:

Rai = Actual annual average emission rate for unit i, lb/mmBtu, as 
determined using the procedures in part 75 of this chapter. For units in 
an averaging plan utilizing a common stack pursuant to 
Sec. 75.17(a)(2)(i)(B) of this chapter, use the same NOX emission 
rate value for each unit utilizing the common stack, and calculate this 
value in accordance with appendix F to part 75 of this chapter;
Rli = Applicable annual emission limitation for unit i lb/mmBtu, as 
specified in Sec. 76.5, 76.6, or 76.7, except that for early election 
units, which may be included in an averaging plan only on or after 
January 1, 2000, Rli shall equal the most stringent applicable 
emission limitation under Sec. 76.5 or 76.7;
HIai = Actual annual heat input for unit i, mmBtu, as determined 
using the procedures in part 75 of this chapter;
n = Number of units in the averaging plan.

    (B) For units with an alternative emission limitation, Rli 
shall equal the applicable emission limitation under Sec. 76.5, 76.6, or 
76.7, not the alternative emission limitation.
    (C) If there is a successful group showing of compliance under 
paragraph (d)(1)(ii)(A) of this section for a calendar year, then all 
units in the averaging plan shall be deemed to be in compliance for that 
year with their alternative contemporaneous emission limitations and 
annual heat input limits under paragraph (d)(1)(i) of this section.
    (2) Liability. The owners and operators of a unit governed by an 
approved averaging plan shall be liable for any violation of the plan or 
this section at that unit or any other unit in the plan, including 
liability for fulfilling the obligations specified in part 77 of this 
chapter and sections 113 and 411 of the Act.
    (3) Withdrawal or termination. The designated representative may 
submit a notification to terminate an approved averaging plan in 
accordance with Sec. 72.40(d) of this chapter, no later than October 1 
of the calendar year for which the plan is to be withdrawn or 
terminated.



Sec. 76.12  Phase I NOX compliance extension.

    (a) General provisions. (1) The designated representative of a Phase 
I unit with a Group 1 boiler may apply for and receive a 15-month 
extension of the deadline for meeting the applicable emissions 
limitation under Sec. 76.5 where it is demonstrated, to the satisfaction 
of the Administrator, that:
    (i) The low NOX burner technology designed to meet the 
applicable emission limitation is not in adequate supply to enable 
installation and operation at the unit, consistent with system 
reliability, by January 1, 1995 and the reliability problems are due 
substantially to NOX emission control system installation and 
availability; or
    (ii) The unit is participating in an approved clean coal technology 
demonstration project.
    (2) In order to obtain a Phase I NOX compliance extension, the 
designated representative shall submit a Phase I NOX compliance 
extension plan by October 1, 1994.
    (b) Contents of Phase I NOX compliance extension plan. A 
complete Phase I NOX compliance extension plan shall include the 
following elements in a format prescribed by the Administrator:
    (1) Identification of the unit.
    (2) For units applying pursuant to paragraph (a)(1)(i) of this 
section:
    (i) A list of the company names, addresses, and telephone numbers of 
vendors who are qualified to provide the

[[Page 355]]

services and low NOX burner technology designed to meet the 
applicable emission limitation under Sec. 76.5 and have been contacted 
to obtain the required services and technology. The list shall include 
the dates of contact, and a copy of each request for bids shall be 
submitted, along with any other information necessary to show a good-
faith effort to obtain the required services and technology necessary to 
meet the requirements of this part on or before January 1, 1995.
    (ii) A copy of those portions of a legally binding contract with a 
qualified vendor that demonstrate that services and low NOX burner 
technology designed to meet the applicable emission limitation under 
Sec. 76.5, with a completion date not later than December 31, 1995 have 
been contracted for.
    (iii) Scheduling information, including justification and test 
schedules.
    (iv) To demonstrate, if applicable, that the supply of the low 
NOX burner technology designed to meet the applicable emission 
limitation under Sec. 76.5 is inadequate to enable its installation and 
operation at the unit, consistent with system reliability, in time for 
the unit to comply with the applicable emission limitation on or before 
January 1, 1995, either:
    (A) Certification from the selected vendor(s) (by a certifying 
official) listed in paragraph (b)(2)(i) of this section stating that 
they cannot provide the necessary services and install the low NOX 
burner technology on or before January 1, 1995 and explaining the 
reasons why the services cannot be provided and why the equipment cannot 
be installed in a timely manner; or
    (B) The following information:
    (i) Standard load forecasts, based on standard forecasting models 
available throughout the utility industry and applied to the period, 
January 1, 1993, through December 31, 1994.
    (ii) Specific reasons why an outage cannot be scheduled to enable 
the unit to install and operate the low NOX burner technology by 
January 1, 1995, including reasons why no other units can be used to 
replace this unit's generation during such outage.
    (iii) Fuel and energy balance summaries and power and other 
consumption requirements (including those for air, steam, and cooling 
water).
    (3) To demonstrate, if applicable, participation in an approved 
clean coal technology demonstration project, a description of the 
project, including all sources of federal, State, and other outside 
funding, amount and date for approval of federal funding, the duration 
of the project, and the anticipated completion date of the project.
    (4) The special provisions in paragraph (d) of this section.
    (c)(1) Administrator's action. To the extent the Administrator 
determines that a Phase I NOX compliance extension plan complies 
with the requirements of this section, the Administrator will approve 
the plan and revise the Acid Rain permit governing the unit in the plan 
in order to incorporate the plan by administrative amendment under 
Sec. 72.83 of this chapter, except that the Administrator shall have 90 
days from receipt of the compliance extension plan to take final action.
    (2) The Administrator will approve or disapprove a proposed NOX 
compliance extension plan within 3 months of receipt.
    (d) Special provisions. (1) Emission limitations. The unit shall 
comply with the applicable emission limitation under Sec. 76.5 beginning 
April 1, 1996. Compliance shall be determined as specified in part 75 of 
this chapter using measured values of NOX emissions and heat input 
only for the portion of the year that the emission limit is in effect.
    (2) If a unit with an approved NOX compliance extension is 
included in an averaging plan under Sec. 76.11 for year 1996, the unit 
shall be treated, for purposes of applying Equation 1 in 
Sec. 76.11(a)(6) and Equation 2 in Sec. 76.11(d)(1)(ii)(A), as subject 
to the applicable emission limitation under Sec. 76.5 for the entire 
year 1996.
    (e) Extension until December 31, 1997. (1) The designated 
representative of a Phase I unit that is subject to section 404(d) of 
the Act, has a tangentially fired boiler, and is unable to install low 
NOX burner technology by January 1, 1997 may submit a petition for 
and receive an extension for meeting the applicable emission limitation 
under

[[Page 356]]

Sec. 76.5 where it is demonstrated, to the satisfaction of the 
Administrator, that:
    (i) The unit is located at a source with two or more other units, 
all of which are Phase I units that are subject to section 404(d) of the 
Act and have tangentially fired boilers;
    (ii) The NOX control system at the unit was scheduled to be 
installed by January 1, 1997 and, because of operational problems 
associated with the NOX control system, will be redesigned; and
    (iii) Installation of the redesigned low NOX burner technology 
at the unit cannot be completed by January 1, 1997 without causing 
system reliability problems.
    (2) A complete petition shall include the following elements and 
shall be submitted by April 28, 1995.
    (i) Identification of the unit and the other units at the source;
    (ii) A statement describing how the requirements of paragraphs 
(e)(1)(ii) and (e)(1)(iii) of this section are met;
    (iii) The earliest date, not later than December 31, 1997, by which 
installation of the redesigned low NOX burner technology can be 
completed consistent with system reliability; and
    (iv) The provisions in paragraph (e)(4) of this section.
    (3) To the extent the Administrator determines that a Phase I unit 
meets the requirements of paragraphs (e)(1) and (e)(2) of this section, 
the Administrator will approve the petition within 90 days from receipt 
of the complete petition. The Acid Rain permit governing the unit will 
be revised in order to incorporate the approved extension, which shall 
terminate no later than December 31, 1997, by administrative amendment 
under Sec. 72.83 of this chapter except that the Administrator will have 
90 days to take final action.
    (4) The unit shall comply with the applicable emission limitation 
under Sec. 76.5 beginning on the day immediately following the day on 
which the extension approved under paragraph (e)(3) of this section 
terminates. Compliance shall be determined as specified in part 75 of 
this chapter using measured values of NOX emissions and heat input 
only for the portion of the year that the emission limit is in effect. 
If a unit with an approved extension is included in an averaging plan 
under Sec. 76.11 for year 1997, the unit shall be treated, for the 
purpose of applying Equation 1 in Sec. 76.11(a)(6) and Equation 2 in 
Sec. 76.11(d)(1)(ii)(A), as subject to the applicable emission 
limitation under Sec. 76.5 for the entire year 1997.



Sec. 76.13  Compliance and excess emissions.

    Excess emissions of nitrogen oxides under Sec. 77.6 of this chapter 
shall be calculated as follows:
    (a) For a unit that is not in an approved averaging plan:
    (1) Calculate EEi for each portion of the calendar year that 
the unit is subject to a different NOX emission limitation:
[GRAPHIC] [TIFF OMITTED] TR13AP95.002

Where:

EEi = Excess emissions for NOX for the portion of the calendar 
year (in tons);
Rai = Actual average emission rate for the unit (in lb/mmBtu), 
determined according to part 75 of this chapter for the portion of the 
calendar year for which the applicable emission limitation Rl is in 
effect;
Rli = Applicable emission limitation for the unit, (in lb/mmBtu), 
as specified in Sec. 76.5, 76.6, or 76.7 or as determined under 
Sec. 76.10;
[GRAPHIC] [TIFF OMITTED] TR13AP95.003

HIi = Actual heat input for the unit, (in mmBtu), determined 
according to part 75 of this chapter for the portion of the calendar 
year for which the applicable emission limitation, Rl, is in 
effect.

    (2) If EEi is a negative number for any portion of the calendar 
year, the EE value for that portion of the calendar year shall be equal 
to zero (e.g., if EEi = -100, then EEi = 0).
    (3) Sum all EEi values for the calendar year:
Where:

EE = Excess emissions for NOX for the year (in tons);

[[Page 357]]

n = The number of time periods during which a unit is subject to 
different emission limitations; and

    (b) For units participating in an approved averaging plan, when all 
the requirements under Sec. 76.11(d)(1) are not met,
[GRAPHIC] [TIFF OMITTED] TR13AP95.004

Where:

EE = Excess emissions for NOX for the year (in tons);
Rai = Actual annual average emission rate for NOX for unit i, 
(in lb/mmBtu), determined according to part 75 of this chapter;
Rli = Applicable emission limitation for unit i, (in lb/mmBtu), as 
specified in Sec. 76.5, 76.6, or 76.7;
HIi = Actual annual heat input for unit i, mmBtu, determined 
according to part 75 of this chapter;
n = Number of units in the averaging plan.



Sec. 76.14  Monitoring, recordkeeping, and reporting.

    (a) A petition for an alternative emission limitation demonstration 
period under Sec. 76.10(d) shall include the following information:
    (1) In accordance with Sec. 76.10(d)(4), the following information:
    (i) Documentation that the owner or operator solicited bids for a 
NOX emission control system designed for application to the 
specific boiler and designed to achieve the applicable emission 
limitation in Sec. 76.5, 76.6, or 76.7 on an annual average basis. This 
documentation must include a copy of all bid specifications.
    (ii) A copy of the performance guarantee submitted by the vendor of 
the installed NOX emission control system to the owner or operator 
showing that such system was designed to meet the applicable emission 
limitation in Sec. 76.5, 76.6, or 76.7 on an annual average basis.
    (iii) Documentation describing the operational and combustion 
conditions that are the basis of the performance guarantee.
    (iv) Certification by the primary vendor of the NOX emission 
control system that such equipment and associated auxiliary equipment 
was properly installed according to the modifications and procedures 
specified by the vendor.
    (v) Certification by the designated representative that the owner(s) 
or operator installed technology that meets the requirements of 
Sec. 76.10(a)(2).
    (2) In accordance with Sec. 76.10(d)(9), the following information:
    (i) The operating conditions of the NOX emission control system 
including load range, O2 range, coal volatile matter range, and, 
for tangentially fired boilers, distribution of combustion air within 
the NOX emission control system;
    (ii) Certification by the designated representative that the 
owner(s) or operator have achieved and are following the operating 
conditions, boiler modifications, and upgrades that formed the basis for 
the system design and performance guarantee;
    (iii) Any planned equipment modifications and upgrades for the 
purpose of achieving the maximum NOX reduction performance of the 
NOX emission control system that were not included in the design 
specifications and performance guarantee, but that were achieved prior 
to submission of this application and are being followed;
    (iv) A list of any modifications or replacements of equipment that 
are to be done prior to the completion of the demonstration period for 
the purpose of reducing emissions of NOX; and
    (v) The parametric testing that will be conducted to determine the 
reason or reasons for the failure of the unit to achieve the applicable 
emission limitation and to verify the proper operation of the installed 
NOX emission control

[[Page 358]]

system during the demonstration period. The tests shall include tests in 
Sec. 76.15, which may be modified as follows:
    (A) The owner or operator of the unit may add tests to those listed 
in Sec. 76.15, if such additions provide data relevant to the failure of 
the installed NOX emission control system to meet the applicable 
emissions limitation in Sec. 76.5, 76.6, or 76.7; or
    (B) The owner or operator of the unit may remove tests listed in 
Sec. 76.15 that are shown, to the satisfaction of the permitting 
authority, not to be relevant to NOX emissions from the affected 
unit; and
    (C) In the event the performance guarantee or the NOX emission 
control system specifications require additional tests not listed in 
Sec. 76.15, or specify operating conditions not verified by tests listed 
in Sec. 76.15, the owner or operator of the unit shall include such 
additional tests.
    (3) In accordance with Sec. 76.10(d)(10), the following information 
for the operating period:
    (i) The average NOX emission rate (in lb/mmBtu) of the specific 
unit;
    (ii) The highest hourly NOX emission rate (in lb/mmBtu) of the 
specific unit;
    (iii) Hourly NOX emission rate (in lb/mmBtu), calculated in 
accordance with part 75 of this chapter;
    (iv) Total heat input (in mmBtu) for the unit for each hour of 
operation, calculated in accordance with the requirements of part 75 of 
this chapter; and
    (v) Total integrated hourly gross unit load (in MWge).
    (b) A petition for an alternative emission limitation shall include 
the following information in accordance with Sec. 76.10(e)(6).
    (1) Total heat input (in mmBtu) for the unit for each hour of 
operation, calculated in accordance with the requirements of part 75 of 
this chapter;
    (2) Hourly NOX emission rate (in lb/mmBtu), calculated in 
accordance with the requirements of part 75 of this chapter; and
    (3) Total integrated hourly gross unit load (MWge).
    (c) Reporting of the costs of low NOX burner technology applied 
to Group 1, Phase I boilers. (1) Except as provided in paragraph (c)(2) 
of this section, the designated representative of a Phase I unit with a 
Group 1 boiler that has installed or is installing any form of low 
NOX burner technology shall submit to the Administrator a report 
containing the capital cost, operating cost, and baseline and post-
retrofit emission data specified in appendix B to this part. If any of 
the required equipment, cost, and schedule information are not available 
(e.g., the retrofit project is still underway), the designated 
representative shall include in the report detailed cost estimates and 
other projected or estimated data in lieu of the information that is not 
available.
    (2) The report under paragraph (c)(1) of this section is not 
required with regard to the following types of Group 1, Phase I units:
    (i) Units employing no new NOX emission control system after 
November 15, 1990;
    (ii) Units employing modifications to boiler operating parameters 
(e.g., burners out of service or fuel switching) without low NOX 
burners or other emission reduction equipment for reducing NOX 
emissions;
    (iii) Units with wall-fired boilers employing only overfire air and 
units with tangentially fired boilers employing only separated overfire 
air; or
    (iv) Units beginning installation of a new NOX emission control 
system after August 11, 1995.
    (3) The report under paragraph (c)(1) of this section shall be 
submitted to the Administrator by:
    (i) 120 days after completion of the low NOX burner technology 
retrofit project; or
    (ii) May 23, 1995, if the project was completed on or before January 
23, 1995.



Sec. 76.15  Test methods and procedures.

    (a) The owner or operator may use the following tests as a basis for 
the report required by Sec. 76.10(e)(7):
    (1) Conduct an ultimate analysis of coal using ASTM D 3176-89 
(incorporated by reference as specified in Sec. 76.4);
    (2) Conduct a proximate analysis of coal using ASTM D 3172-89 
(incorporated by reference as specified in Sec. 76.4); and

[[Page 359]]

    (3) Measure the coal mass flow rate to each individual burner using 
ASME Power Test Code 4.2 (1991), ``Test Code for Coal Pulverizers'' or 
ISO 9931 (1991), ``Coal--Sampling of Pulverized Coal Conveyed by Gases 
in Direct Fired Coal Systems'' (incorporated by reference as specified 
in Sec. 76.4).
    (b) The owner or operator may measure and record the actual NOX 
emission rate in accordance with the requirements of this part while 
varying the following parameters where possible to determine their 
effects on the emissions of NOX from the affected boiler:
    (1) Excess air levels;
    (2) Settings of burners or coal and air nozzles, including tilt and 
yaw, or swirl;
    (3) For tangentially fired boilers, distribution of combustion air 
within the NOX emission control system;
    (4) Coal mass flow rates to each individual burner;
    (5) Coal-to-primary air ratio (based on pound per hour) for each 
burner, the average coal-to-primary air ratio for all burners, and the 
deviations of individual burners' coal-to-primary air ratios from the 
average value; and
    (6) If the boiler uses varying types of coal, the type of coal. 
Provide the results of proximate and ultimate analyses of each type of 
as-fired coal.
    (c) In performing the tests specified in paragraph (a) of this 
section, the owner or operator shall begin the tests using the equipment 
settings for which the NOX emission control system was designed to 
meet the NOX emission rate guaranteed by the primary NOX 
emission control system vendor. These results constitute the ``baseline 
controlled'' condition.
    (d) After establishing the baseline controlled condition under 
paragraph (c) of this section, the owner or operator may:
    (1) Change excess air levels  5 percent from the 
baseline controlled condition to determine the effects on emissions of 
NOX, by providing a minimum of three readings (e.g., with a 
baseline reading of 20 percent excess air, excess air levels will be 
changed to 19 percent and 21 percent);
    (2) For tangentially fired boilers, change the distribution of 
combustion air within the NOX emission control system to determine 
the effects on NOX emissions by providing a minimum of three 
readings, one with the minimum, one with the baseline, and one with the 
maximum amounts of staged combustion air; and
    (3) Show that the combustion process within the boiler is optimized 
(e.g., that the burners are balanced).
Sec. 76.16  [Reserved]

 Appendix A to Part 76--Phase I Affected Coal-Fired Utility Units With 
                     Group 1 or Cell Burner Boilers

                                    Table 1--Phase I Tangentially Fired Units                                   
----------------------------------------------------------------------------------------------------------------
            State                          Plant                  Unit                    Operator              
----------------------------------------------------------------------------------------------------------------
ALABAMA......................  EC GASTON....................  5             ALABAMA POWER CO.                   
GEORGIA......................  BOWEN........................  1BLR          GEORGIA POWER CO.                   
GEORGIA......................  BOWEN........................  2BLR          GEORGIA POWER CO.                   
GEORGIA......................  BOWEN........................  3BLR          GEORGIA POWER CO.                   
GEORGIA......................  BOWEN........................  4BLR          GEORGIA POWER CO.                   
GEORGIA......................  JACK MCDONOUGH...............  MB1           GEORGIA POWER CO.                   
GEORGIA......................  JACK MCDONOUGH...............  MB2           GEORGIA POWER CO.                   
GEORGIA......................  WANSLEY......................  1             GEORGIA POWER CO.                   
GEORGIA......................  WANSLEY......................  2             GEORGIA POWER CO.                   
GEORGIA......................  YATES........................  Y1BR          GEORGIA POWER CO.                   
GEORGIA......................  YATES........................  Y2BR          GEORGIA POWER CO.                   
GEORGIA......................  YATES........................  Y3BR          GEORGIA POWER CO.                   
GEORGIA......................  YATES........................  Y4BR          GEORGIA POWER CO.                   
GEORGIA......................  YATES........................  Y5BR          GEORGIA POWER CO.                   
GEORGIA......................  YATES........................  Y6BR          GEORGIA POWER CO.                   
GEORGIA......................  YATES........................  Y7BR          GEORGIA POWER CO.                   
ILLINOIS.....................  BALDWIN......................  3             ILLINOIS POWER CO.                  
ILLINOIS.....................  HENNEPIN.....................  2             ILLINOIS POWER CO.                  
ILLINOIS.....................  JOPPA........................  1             ELECTRIC ENERGY INC.                
ILLINOIS.....................  JOPPA........................  2             ELECTRIC ENERGY INC.                
ILLINOIS.....................  JOPPA........................  3             ELECTRIC ENERGY INC.                
ILLINOIS.....................  JOPPA........................  4             ELECTRIC ENERGY INC.                
ILLINOIS.....................  JOPPA........................  5             ELECTRIC ENERGY INC.                

[[Page 360]]

                                                                                                                
ILLINOIS.....................  JOPPA........................  6             ELECTRIC ENERGY INC.                
ILLINOIS.....................  MEREDOSIA....................  5             CEN ILLINOIS PUB SER.               
ILLINOIS.....................  VERMILION....................  2             ILLINOIS POWER CO.                  
INDIANA......................  CAYUGA.......................  1             PSI ENERGY INC.                     
INDIANA......................  CAYUGA.......................  2             PSI ENERGY INC.                     
INDIANA......................  EW STOUT.....................  50            INDIANAPOLIS PWR & LT.              
INDIANA......................  EW STOUT.....................  60            INDIANAPOLIS PWR & LT.              
INDIANA......................  EW STOUT.....................  70            INDIANAPOLIS PRW & LT.              
INDIANA......................  HT PRITCHARD.................  6             INDIANAPOLIS PWR & LT.              
INDIANA......................  PETERSBURG...................  1             INDIANAPOLIS PWR & LT.              
INDIANA......................  PETERSBURG...................  2             INDIANAPOLIS PWR & LT.              
INDIANA......................  WABASH RIVER.................  6             PSI ENERGY INC.                     
IOWA.........................  BURLINGTON...................  1             IOWA SOUTHERN UTL.                  
IOWA.........................  ML KAPP......................  2             INTERSTATE POWER CO.                
IOWA.........................  RIVERSIDE....................  9             IOWA-ILL GAS & ELEC.                
KENTUCKY.....................  ELMER SMITH..................  2             OWENSBORO MUN UTIL.                 
KENTUCKY.....................  EW BROWN.....................  2             KENTUCKY UTL CO.                    
KENTUCKY.....................  EW BROWN.....................  3             KENTUCKY UTL CO.                    
KENTUCKY.....................  GHENT........................  1             KENTUCKY UTL CO.                    
MARYLAND.....................  MORGANTOWN...................  1             POTOMAC ELEC PWR CO.                
MARYLAND.....................  MORGANTOWN...................  2             POTOMAC ELEC PWR CO.                
MICHIGAN.....................  JH CAMPBELL..................  1             CONSUMERS POWER CO.                 
MISSOURI.....................  LABADIE......................  1             UNION ELECTRIC CO.                  
MISSOURI.....................  LABADIE......................  2             UNION ELECTRIC CO.                  
MISSOURI.....................  LABADIE......................  3             UNION ELECTRIC CO.                  
MISSOURI.....................  LABADIE......................  4              UNION ELECTRIC CO.                 
MISSOURI.....................  MONTROSE.....................  1             KANSAS CITY PWR & LT.               
MISSOURI.....................  MONTROSE.....................  2             KANSAS CITY PWR & LT.               
MISSOURI.....................  MONTROSE.....................  3             KANSAS CITY PWR & LT.               
NEW YORK.....................  DUNKIRK......................  3             NIAGARA MOHAWK PWR.                 
NEW YORK.....................  DUNKIRK......................  4             NIAGARA MOHAWK PWR.                 
NEW YORK.....................  GREENIDGE....................  6             NY STATE ELEC & GAS.                
NEW YORK.....................  MILLIKEN.....................  1             NY STATE ELEC & GAS.                
NEW YORK.....................  MILLIKEN.....................  2             NY STATE ELEC & GAS.                
OHIO.........................  ASHTABULA....................  7             CLEVELAND ELEC ILLUM.               
OHIO.........................  AVON LAKE....................  11            CLEVELAND ELEC ILLUM.               
OHIO.........................  CONESVILLE...................  4             COLUMBUS STHERN PWR.                
OHIO.........................  EASTLAKE.....................  1             CLEVELAND ELEC ILLUM.               
OHIO.........................  EASTLAKE.....................  2             CLEVELAND ELEC ILLUM.               
OHIO.........................  EASTLAKE.....................  3             CLEVELAND ELEC ILLUM.               
OHIO.........................  EASTLAKE.....................  4             CLEVELAND ELEC ILLUM.               
OHIO.........................  MIAMI FORT...................  6             CINCINNATI GAS & ELEC.              
OHIO.........................  WC BECKJORD..................  5             CINCINNATI GAS & ELEC.              
OHIO.........................  WC BECKJORD..................  6             CINCINNATI GAS & ELEC.              
PENNSYLVANIA.................  BRUNNER ISLAND...............  1             PENNSYLVANIA PWR & LT.              
PENNSYLVANIA.................  BRUNNER ISLAND...............  2             PENNSYLVANIA PWR & LT.              
PENNSYLVANIA.................  BRUNNER ISLAND...............  3             PENNSYLVANIA PWR & LT.              
PENNSYLVANIA.................  CHESWICK.....................  1             DUQUESNE LIGHT CO.                  
PENNSYLVANIA.................  CONEMAUGH....................  1             PENNSYLVANIA ELEC CO.               
PENNSYLVANIA.................  CONEMAUGH....................  2             PENNSYLVANIA ELEC CO.               
PENNSYLVANIA.................  PORTLAND.....................  1             METROPOLITAN EDISON.                
PENNSYLVANIA.................  PORTLAND.....................  2             METROPOLITAN EDISON.                
PENNSYLVANIA.................  SHAWVILLE....................  3             PENNSYLVANIA ELEC CO.               
PENNSYLVANIA.................  SHAWVILLE....................  4             PENNSYLVANIA ELEC CO.               
TENNESSEE....................  GALLATIN.....................  1             TENNESSEE VAL AUTH.                 
TENNESSEE....................  GALLATIN.....................  2             TENNESSEE VAL AUTH.                 
TENNESSEE....................  GALLATIN.....................  3             TENNESSEE VAL AUTH.                 
TENNESSEE....................  GALLATIN.....................  4             TENNESSEE VAL AUTH.                 
TENNESSEE....................  JOHNSONVILLE.................  1             TENNESSEE VAL AUTH.                 
TENNESSEE....................  JOHNSONVILLE.................  2             TENNESSEE VAL AUTH.                 
TENNESSEE....................  JOHNSONVILLE.................  3             TENNESSEE VAL AUTH.                 
TENNESSEE....................  JOHNSONVILLE.................  4             TENNESSEE VAL AUTH.                 
TENNESSEE....................  JOHNSONVILLE.................  5             TENNESSEE VAL AUTH.                 
TENNESSEE....................  JOHNSONVILLE.................  6             TENNESSEE VAL AUTH.                 
WEST VIRGINIA................  ALBRIGHT.....................  3             MONONGAHELA POWER CO.               
WEST VIRGINIA................  FORT MARTIN..................  1             MONONGAHELA POWER CO.               
WEST VIRGINIA................  MOUNT STORM..................  1             VIRGINIA ELEC & PWR.                
WEST VIRGINIA................  MOUNT STORM..................  2             VIRGINIA ELEC & PWR.                
WEST VIRGINIA................  MOUNT STORM..................  3             VIRGINIA ELEC & PWR.                
WISCONSIN....................  GENOA........................  1             DAIRYLAND POWER COOP.               
WISCONSIN....................  SOUTH OAK CREEK..............  7             WISCONSIN ELEC POWER.               
WISCONSIN....................  SOUTH OAK CREEK..............  8             WISCONSIN ELEC POWER.               
----------------------------------------------------------------------------------------------------------------


[[Page 361]]


                                     Table 2--Phase I Dry Bottom-Fired Units                                    
----------------------------------------------------------------------------------------------------------------
             State                           Plant                   Unit                   Operator            
----------------------------------------------------------------------------------------------------------------
ALABAMA.......................  COLBERT.......................  1               TENNESSEE VAL AUTH.             
ALABAMA.......................  COLBERT.......................  2               TENNESSEE VAL AUTH.             
ALABAMA.......................  COLBERT.......................  3               TENNESSEE VAL AUTH.             
ALABAMA.......................  COLBERT.......................  4               TENNESSEE VAL AUTH.             
ALABAMA.......................  COLBERT.......................  5               TENNESSEE VAL AUTH.             
ALABAMA.......................  EC GASTON.....................  1               ALABAMA POWER CO.               
ALABAMA.......................  EC GASTON.....................  2               ALABAMA POWER CO.               
ALABAMA.......................  EC GASTON.....................  3               ALABAMA POWER CO.               
ALABAMA.......................  EC GASTON.....................  4               ALABAMA POWER CO.               
                                                                                                                
FLORIDA.......................  CRIST.........................  6               GULF POWER CO.                  
FLORIDA.......................  CRIST.........................  7               GULF POWER CO.                  
                                                                                                                
GEORGIA.......................  HAMMOND.......................  1               GEORGIA POWER CO.               
GEORGIA.......................  HAMMOND.......................  2               GEORGIA POWER CO.               
GEORGIA.......................  HAMMOND.......................  3               GEORGIA POWER CO.               
GEORGIA.......................  HAMMOND.......................  4               GEORGIA POWER CO.               
                                                                                                                
ILLINOIS......................  GRAND TOWER...................  9               CEN ILLINOIS PUB SER.           
                                                                                                                
INDIANA.......................  CULLEY........................  2               STHERN IND GAS & EL.            
INDIANA.......................  CULLEY........................  3               STHERN IND GAS & EL.            
INDIANA.......................  GIBSON........................  1               PSI ENERGY INC.                 
INDIANA.......................  GIBSON........................  2               PSI ENERGY INC.                 
INDIANA.......................  GIBSON........................  3               PSI ENERGY INC.                 
INDIANA.......................  GIBSON........................  4               PSI ENERGY INC.                 
INDIANA.......................  RA GALLAGHER..................  1               PSI ENERGY INC.                 
INDIANA.......................  RA GALLAGHER..................  2               PSI ENERGY INC.                 
INDIANA.......................  RA GALLAGHER..................  3               PSI ENERGY INC.                 
INDIANA.......................  RA GALLAGHER..................  4               PSI ENERGY INC.                 
INDIANA.......................  FRANK E RATTS.................  1SG1            HOOSIER ENERGY REC.             
INDIANA.......................  FRANK E RATTS.................  2SG1            HOOSIER ENERGY REC.             
INDIANA.......................  WABASH RIVER..................  1               PSI ENERGY INC.                 
INDIANA.......................  WABASH RIVER..................  2               PSI ENERGY INC.                 
INDIANA.......................  WABASH RIVER..................  3               PSI ENERGY INC.                 
INDIANA.......................  WABASH RIVER..................  5               PSI ENERGY INC.                 
                                                                                                                
IOWA..........................  DES MOINES....................  11              IOWA PWR & LT CO.               
IOWA..........................  PRAIRIE CREEK.................  4               IOWA ELEC LT & PWR.             
                                                                                                                
KANSAS........................  QUINDARO......................  2               KS CITY BD PUB UTIL.            
                                                                                                                
KENTUCKY......................  COLEMAN.......................  C1              BIG RIVERS ELEC CORP.           
KENTUCKY......................  COLEMAN.......................  C2              BIG RIVERS ELEC CORP.           
KENTUCKY......................  COLEMAN.......................  C3              BIG RIVERS ELEC CORP.           
KENTUCKY......................  EW BROWN......................  1               KENTUCKY UTL CO.                
KENTUCKY......................  GREEN RIVER...................  5               KENTUCKY UTL CO.                
KENTUCKY......................  HMP&L STATION 2...............  H1              BIG RIVERS ELEC CORP.           
KENTUCKY......................  HMP&L STATION 2...............  H2              BIG RIVERS ELEC CORP.           
KENTUCKY......................  HL SPURLOCK...................  1               EAST KY PWR COOP.               
KENTUCKY......................  JS COOPER.....................  1               EAST KY PWR COOP.               
KENTUCKY......................  JS COOPER.....................  2               EAST KY PWR COOP.               
                                                                                                                
MARYLAND......................  CHALK POINT...................  1               POTOMAC ELEC PWR CO.            
MARYLAND......................  CHALK POINT...................  2               POTOMAC ELEC PWR CO.            
                                                                                                                
MINNESOTA.....................  HIGH BRIDGE...................  6               NORTHERN STATES PWR.            
                                                                                                                
MISSISSIPPI...................  JACK WATSON...................  4               MISSISSIPPI PWR CO.             
MISSISSIPPI...................  JACK WATSON...................  5               MISSISSIPPI PWR CO.             
                                                                                                                
MISSOURI......................  JAMES RIVER...................  5               SPRINGFIELD UTL.                
                                                                                                                
OHIO..........................  CONESVILLE....................  3               COLUMBUS STHERN PWR.            
OHIO..........................  EDGEWATER.....................  13              OHIO EDISON CO.                 
OHIO..........................  MIAMI FORT \1\................  5-1             CINCINNATI GAS&ELEC.            
OHIO..........................  MIAMI FORT \1\................  5-2             CINCINNATI GAS&ELEC.            
OHIO..........................  PICWAY........................  9               COLUMBUS STHERN PWR.            
OHIO..........................  RE BURGER.....................  7               OHIO EDISON CO.                 
OHIO..........................  RE BURGER.....................  8               OHIO EDISON CO.                 
OHIO..........................  WH SAMMIS.....................  5               OHIO EDISON CO.                 
OHIO..........................  WH SAMMIS.....................  6               OHIO EDISON CO.                 
                                                                                                                
PENNSYLVANIA..................  ARMSTRONG.....................  1               WEST PENN POWER CO.             
PENNSYLVANIA..................  ARMSTRONG.....................  2               WEST PENN POWER CO.             
PENNSYLVANIA..................  MARTINS CREEK.................  1               PENNSYLVANIA PWR & LT.          
PENNSYLVANIA..................  MARTINS CREEK.................  2               PENNSYLVANIA PWR & LT.          
PENNSYLVANIA..................  SHAWVILLE.....................  1               PENNSYLVANIA ELEC CO.           
PENNSYLVANIA..................  SHAWVILLE.....................  2               PENNSYLVANIA ELEC CO.           
PENNSYLVANIA..................  SUNBURY.......................  3               PENNSYLVANIA PWR & LT.          
PENNSYLVANIA..................  SUNBURY.......................  4               PENNSYLVANIA PWR & LT.          
                                                                                                                

[[Page 362]]

                                                                                                                
TENNESSEE.....................  JOHNSONVILLE..................  7               TENNESSEE VAL AUTH.             
TENNESSEE.....................  JOHNSONVILLE..................  8               TENNESSEE VAL AUTH.             
TENNESSEE.....................  JOHNSONVILLE..................  9               TENNESSEE VAL AUTH.             
TENNESSEE.....................  JOHNSONVILLE..................  10              TENNESSEE VAL AUTH.             
                                                                                                                
WEST VIRGINIA.................  HARRISON......................  1               MONONGAHELA POWER CO.           
WEST VIRGINIA.................  HARRISON......................  2               MONONGAHELA POWER CO.           
WEST VIRGINIA.................  HARRISON......................  3               MONONGAHELA POWER CO.           
WEST VIRGINIA.................  MITCHELL......................  1               OHIO POWER CO.                  
WEST VIRGINIA.................  MITCHELL......................  2               OHIO POWER CO.                  
                                                                                                                
WISCONSIN.....................  JP PULLIAM....................  8               WISCONSIN PUB SER CO.           
WISCONSIN.....................  NORTH OAK CREEK \2\...........  1               WISCONSIN ELEC PWR.             
WISCONSIN.....................  NORTH OAK CREEK \2\...........  2               WISCONSIN ELEC PWR.             
WISCONSIN.....................  NORTH OAK CREEK \2\...........  3               WISCONSIN ELEC PWR.             
WISCONSIN.....................  NORTH OAK CREEK \2\...........  4               WISCONSIN ELEC PWR.             
WISCONSIN.....................  SOUTH OAK CREEK \2\...........  5               WISCONSIN ELEC PWR.             
WISCONSIN.....................  SOUTH OAK CREEK \2\...........  6               WISCONSIN ELEC PWR.             
----------------------------------------------------------------------------------------------------------------
\1\ Vertically fired boiler.                                                                                    
\2\ Arch-fired boiler.                                                                                          


                                  Table 3--Phase I Cell Burner Technology Units                                 
----------------------------------------------------------------------------------------------------------------
             State                           Plant                 Unit                   Operator              
----------------------------------------------------------------------------------------------------------------
INDIANA.......................  WARRICK.......................          4  STHERN IND GAS & EL.                 
MICHIGAN......................  JH CAMPBELL...................          2  CONSUMERS POWER CO.                  
OHIO..........................  AVON LAKE.....................         12  CLEVELAND ELEC ILLUM.                
OHIO..........................  CARDINAL......................          1  CARDINAL OPERATING.                  
OHIO..........................  CARDINAL......................          2  CARDINAL OPERATING.                  
OHIO..........................  EASTLAKE......................          5  CLEVELAND ELEC ILLUM.                
OHIO..........................  GENRL JM GAVIN................          1  OHIO POWER CO.                       
OHIO..........................  GENRL JM GAVIN................          2  OHIO POWER CO.                       
OHIO..........................  MIAMI FORT....................          7  CINCINNATI GAS & EL.                 
OHIO..........................  MUSKINGUM RIVER...............          5  OHIO POWER CO.                       
OHIO..........................  WH SAMMIS.....................          7  OHIO EDISON CO.                      
PENNSYLVANIA..................  HATFIELDS FERRY...............          1  WEST PENN POWER CO.                  
PENNSYLVANIA..................  HATFIELDS FERRY...............          2  WEST PENN POWER CO.                  
PENNSYLVANIA..................  HATFIELDS FERRY...............          3  WEST PENN POWER CO.                  
TENNESSEE.....................  CUMBERLAND....................          1  TENNESSEE VAL AUTH.                  
TENNESSEE.....................  CUMBERLAND....................          2  TENNESSEE VAL AUTH.                  
WEST VIRGINIA.................  FORT MARTIN...................          2  MONONGAHELA POWER CO.                
----------------------------------------------------------------------------------------------------------------

 Appendix B to Part 76--Procedures and Methods for Estimating Costs of 
      Nitrogen Oxides Controls Applied to Group 1, Phase I Boilers

                      1. Purpose and Applicability

    This technical appendix specifies the procedures, methods, and data 
that the Administrator will use in establishing ``***the degree of 
reduction achievable through this retrofit application of the best 
system of continuous emission reduction, taking into account available 
technology, costs, and energy and environmental impacts; and which is 
comparable to the costs of nitrogen oxides controls set pursuant to 
subsection (b)(1) (of section 407 of the Act).'' In developing the 
allowable NOX emissions limitations for Group 2 boilers pursuant to 
subsection (b)(2) of section 407 of the Act, the Administrator will 
consider only those systems of continuous emission reduction that, when 
applied on a retrofit basis, are comparable in cost to the average cost 
in constant dollars of low NOX burner technology applied to Group 
1, Phase I boilers, as determined in section 3 below.
    The Administrator will evaluate the capital cost (in dollars per 
kilowatt electrical ($/kW)), the operating and maintenance costs (in $/
year), and the cost-effectiveness (in annualized $/ton NOX removed) 
of installed low NOX burner technology controls over a range of 
boiler sizes (as measured by the gross electrical capacity of the 
associated generator in megawatt electrical (MW)) and utilization rates 
(in percent gross nameplate capacity on an annual basis) to develop 
estimates of the average capital cost and cost-effectiveness for Group 
1, Phase I boilers. The following units will be excluded from these 
determinations of the average capital cost and cost-effectiveness of 
NOX controls set pursuant to subsection (b)(1) of section 407 of 
the Act: (1) Units employing an alternative technology, or only overfire 
air as applied to wall-fired boilers or only separated

[[Page 363]]

overfire air as applied to tangentially fired boilers, in lieu of low 
NOX burner technology for reducing NOX emissions; (2) units 
employing no controls, only controls installed before November 15, 1990, 
or only modifications to boiler operating parameters (e.g., burners out 
of service or fuel switching) for reducing NOX emissions; and (3) 
units that have not achieved the applicable emission limitation.

 2. Average Capital Cost for Low NOX Burner Technology Applied to 
                        Group 1, Phase I Boilers

    The Administrator will use the procedures, methods, and data 
specified in this section to estimate the average capital cost (in $/kW) 
of installed low NOX burner technology applied to Group 1, Phase I 
boilers.
    2.1  Using cost data submitted pursuant to the reporting 
requirements in section 4 below, boiler-specific actual or estimated 
actual capital costs will be determined for each unit in the population 
specified in section 1 above for assessing the costs of installed low 
NOX burner technology. The scope of installed low NOX burner 
technology costs will include the following capital costs for retrofit 
application: (1) For the burner portion--burners or air and coal 
nozzles, burner throat and waterwall modifications, and windbox 
modifications; and, where applicable, (2) for the combustion air staging 
portion--waterwall modifications or panels, windbox modifications, and 
ductwork, and (3) scope adders or supplemental equipment such as 
replacement or additional fans, dampers, or ignitors necessary for the 
proper operation of the low NOX burner technology. Capital costs 
associated with boiler restoration or refurbishment such as replacement 
of air heaters, asbestos abatement, and recasing will not be included in 
the cost basis for installed low NOX burner technology. The scope 
of installed low NOX burner technology retrofit capital costs will 
include materials, construction and installation labor, engineering, and 
overhead costs.
    2.2  Using gross nameplate capacity (in MW) for each unit as 
reported in the National Allowance Data Base (NADB), boiler-specific 
capital costs will be converted to a $/kW basis.
    2.3  Capital cost curves ($/kW versus boiler size in MW) or 
equations for installed low NOX burner technology retrofit costs 
will be developed for: (1) Dry bottom wall fired boilers (excluding 
units applying cell burner technology) and (2) tangentially fired 
boilers.
    2.4  The capital cost curves or equations defined above will be used 
to develop weighted average cost estimates of installed low NOX 
burner technology applied to Group 1, Phase I boilers. The weighting 
factor will be the unit gross nameplate generating capacity (in MW) as 
reported in the NADB.

3. Average Cost-Effectiveness for Low NOX Burner Technology Applied 
                       to Group 1, Phase I Boilers

    The Administrator will use the procedures, methods, and data 
specified in this section to estimate the average cost-effectiveness (in 
annualized $/ton NOX removed) of installed low NOX burner 
technology applied to Group 1, Phase I boilers.
    3.1  Boiler-specific estimates of annual tons NOX removed by 
the installed low NOX burner technology will be determined for each 
unit in the population specified in section 1 above.
    3.1.1  The baseline NOX emission rate (in lb/mmBtu, annual 
average basis) will be estimated prior to retrofitting any low NOX 
burner technology controls. For units that have installed and certified 
continuous emission monitoring systems for measuring the NOX 
emission rate pursuant to part 75 of this chapter at least 120 days 
prior to the low NOX burner technology retrofit, an estimate of the 
average annual uncontrolled NOX emission rate will be developed 
using continuous emission monitoring data for the 120 days immediately 
before the low NOX burner technology retrofit or another continuous 
120-day or longer period as approved by the Administrator. (In cases 
where 120 days of certified and quality-assured continuous emission 
monitoring data are not available prior to the low NOX burner 
technology retrofit, the Administrator may use continuous emission 
monitoring data over a shorter period or short-term test data to 
estimate the uncontrolled NOX emission rate.) Continuous emission 
monitoring data or other emission rate measurements will be extrapolated 
to one year of unit operation.
    3.1.2  The controlled NOX emission rate (in lb/mmBtu, annual 
average basis) will be estimated after installation, shakedown, and/or 
optimization of all low NOX burner technology controls have been 
completed and while the unit is complying with the applicable emission 
limitation (or alternative emission limitation). Continuous emission 
monitoring data submitted pursuant to part 75 of this chapter will be 
used for the 120 days immediately following installation and testing of 
the final low NOX burner technology, provided the unit is complying 
with the applicable emission limitation (or alternative emission 
limitation), or another continuous 120-day or shorter period as approved 
by the Administrator. Continuous emission monitoring data will be 
extrapolated to one year of unit operation.
    3.1.3  The NOX emission reduction (in lb/mmBtu, annual average 
basis) achieved by the installed low NOX burner technology will be 
estimated by subtracting the controlled NOX emission rate defined 
in section 3.1.2 from the uncontrolled NOX emission rate defined in 
section 3.1.1.

[[Page 364]]

    3.1.4  Annual estimates of the NOX emission reduction achieved 
by the installed low NOX burner technology will be converted to 
annual tons of NOX removed by multiplying it by the annual heat 
input (in mmBtu). Unit heat input data submitted pursuant to part 75 of 
this chapter for calendar year 1994 or for the year immediately 
following installation and testing of the final low NOX burner 
technology, will be used when such data are available prior to October 
30, 1995. Such data will be adjusted to an annual basis whenever a 
nonrecurrent extended outage at the affected unit during the period has 
taken place.
    3.2  The boiler-specific capital costs of installed low NOX 
burner technology developed in section 2.1 will be annualized by 
multiplying them by a constant dollar capital recovery factor based on a 
20-year economic life (e.g., 0.115).
    3.3  Using cost data submitted pursuant to the reporting 
requirements in section 4, boiler-specific annual operating and 
maintenance cost increases (or decreases) will be determined for each 
unit in the population specified in section 1 above. The scope of the 
operating and maintenance costs (or savings) attributable to the 
installed low NOX burner technology may, but not necessarily will, 
include incremental increases (or decreases) in: maintenance labor and 
materials costs, operating labor costs, operating fuel costs, and 
secondary air fan electricity costs.
    3.4  The average annual cost-effectiveness of installed low NOX 
burner technology applied to Group 1, Phase I boilers will be estimated 
as follows: (1) The annualized capital costs defined in section 3.2 and 
the annual operating and maintenance cost increases (or decreases) 
defined in section 3.3 will be summed for all units in the population 
specified in section 1; and (2) these annualized costs will be divided 
by the sum of the NOX emission reductions (in tons/year) achieved 
by the units in the population specified in section 1.

                        4. Reporting Requirements

    4.1  The following information is to be submitted by each designated 
representative of a Phase I affected unit subject to the reporting 
requirements of Sec. 76.14(c):
    4.1.1  Schedule and dates for baseline testing, installation, and 
performance testing of low NOX burner technology.
    4.1.2  Estimates of the annual average baseline NOX emission 
rate, as specified in section 3.1.1, and the annual average controlled 
NOX emission rate, as specified in section 3.1.2, including the 
supporting continuous emission monitoring or other test data.
    4.1.3  Copies of pre-retrofit and post-retrofit performance test 
reports.
    4.1.4  Detailed estimates of the capital costs based on actual 
contract bids for each component of the installed low NOX burner 
technology including the items listed in section 2.1. Indicate number of 
bids solicited. Provide a copy of the actual agreement for the installed 
technology.
    4.1.5  Detailed estimates of the capital costs of system 
replacements or upgrades such as coal pipe changes, fan replacements/
upgrades, or mill replacements/upgrades undertaken as part of the low 
NOX burner technology retrofit project.
    4.1.6  Detailed breakdown of the actual costs of the completed low 
NOX burner technology retrofit project where low NOX burner 
technology costs (section 4.1.4) are disaggregated, if feasible, from 
system replacement or upgrade costs (section 4.1.5).
    4.1.7  Description of the probable causes for significant 
differences between actual and estimated low NOX burner technology 
retrofit project costs.
    4.1.8  Detailed breakdown of the burner and, if applicable, 
combustion air staging system annual operating and maintenance costs for 
the items listed in section 3.3 before and after the installation, 
shakedown, and/or optimization of the installed low NOX burner 
technology. Include estimates and a description of the probable causes 
of the incremental annual operating and maintenance costs (or savings) 
attributable to the installed low NOX burner technology.
    4.2  All capital cost estimates are to be broken down into materials 
costs, construction and installation labor costs, and engineering and 
overhead costs. All operating and maintenance costs are to be broken 
down into maintenance materials costs, maintenance labor costs, 
operating labor costs, and fan electricity costs. All capital and 
operating costs are to be reported in dollars with the year of 
expenditure or estimate specified for each component.



PART 77--EXCESS EMISSIONS--Table of Contents




Sec.
77.1  Purpose and scope.
77.2  General.
77.3  Offset plans for excess emissions of sulfur dioxide.
77.4  Administrator's action on proposed offset plans.
77.5  Deduction of allowances to offset excess emissions of sulfur 
          dioxide.
77.6  Penalties for excess emissions of sulfur dioxide and nitrogen 
          oxides.

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

    Source: 58 FR 3757, Jan. 11, 1993, unless otherwise noted.



Sec. 77.1  Purpose and scope.

    (a) This part sets forth the excess emissions offset planning and 
offset

[[Page 365]]

penalty requirements under section 411 of the Clean Air Act, 42 U.S.C. 
7401, et seq., as amended by Public Law 101-549 (November 15, 1990). 
These requirements shall apply to the owners and operators and, to the 
extent applicable, the designated representative of each affected unit 
and affected source under the Acid Rain Program.
    (b) Nothing in this part shall limit or otherwise affect the 
application of sections 112(r)(9), 113, 114, 120, 303, 304, or 306 of 
the Act, as amended. Any allowance deduction, excess emission penalty, 
or interest required under this part shall not affect the liability of 
the affected unit's and affected source's owners and operators for any 
additional fine, penalty, or assessment, or their obligation to comply 
with any other remedy, for the same violation, as ordered under the Act.



Sec. 77.2  General.

    Part 72 of this chapter, including 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. The procedures for 
appeals of decisions of the Administrator under this part are contained 
in part 78 of this chapter.



Sec. 77.3  Offset plans for excess emissions of sulfur dioxide.

    (a) Applicability. The owners and operators of any affected unit 
that has excess emissions of sulfur dioxide in any calendar year shall 
be liable to offset the amount of such excess emissions by an equal 
amount of allowances from the unit's Allowance Tracking System account.
    (b) Deadline. Not later than 60 days after the end of any calendar 
year during which an affected unit had excess emissions of sulfur 
dioxide (except for any increase in excess emissions under Sec. 72.91(b) 
of this chapter), the designated representative for the unit shall 
submit to the Administrator a complete proposed offset plan to offset 
those emissions. Each day after the 60-day deadline that the designated 
representative fails to submit a complete proposed offset plan shall be 
a separate violation of this part.
    (c) Number of Plans. The designated representative shall submit a 
proposed offset plan for each affected unit with excess emissions of 
sulfur dioxide.
    (d) Contents of Plan. A complete proposed offset plan shall include 
the following elements in a format prescribed by the Administrator for 
the unit and for the calendar year for which the plan is submitted:
    (1) Identification of the unit.
    (2) If the unit had excess emissions for the calendar year prior to 
the year for which the plan is submitted, an explanation of how and why 
the excess emissions occurred for the year for which the plan is 
submitted and a description of any measures that were or will be taken 
to prevent excess emissions in the future.
    (3) The amount of excess emissions of sulfur dioxide (in tons/year) 
for the year for which the plan is submitted and the number of 
allowances required to be deducted from the unit's Allowance Tracking 
System account to offset the excess emissions.
    (4) At the designated representative's option, the serial numbers of 
the allowances that are to be deducted from the unit's Allowance 
Tracking System account.
    (5) Whether the allowances are to be deducted immediately from the 
unit's account or, if not, the date on which they are to be deducted.
    (6) If the proposed offset plan does not propose a deduction of the 
amount of allowances under paragraph (d)(3) of this section from the 
compliance subaccount during the year after the year for which the plan 
is submitted, a demonstration that such a deduction will interfere with 
electric reliability.



Sec. 77.4  Administrator's action on proposed offset plans.

    (a) Determination of Completeness. The Administrator will determine 
whether the proposed offset plan is complete within 30 days of receipt 
by the Administrator. The offset plan shall be deemed complete if the 
Administrator fails to notify the designated representative to the 
contrary within 30

[[Page 366]]

days of receipt or when the Administrator approves the offset plan and 
deducts allowances in accordance with paragraph (b)(1) of this section.
    (b) Review of proposed offset plans. (1) If the designated 
representative submits a complete proposed offset plan for immediate 
deduction, from the unit's compliance subaccount, of all allowances 
required to offset excess emissions of sulfur dioxide, the Administrator 
will approve the proposed offset plan without further review and will 
serve written notice of any approval on the designated representative 
and on any persons entitled to written notice under paragraphs (g)(2)(i) 
(B), (C) and (D) of this section. The Administrator will also give 
notice of any approval in the Federal Register. The plan will be 
incorporated into the unit's Acid Rain permit in accordance with 
Sec. 72.84 (automatic permit amendment) and will not be subject to the 
requirements of paragraphs (d) through (k) of this section.
    (2) Notwithstanding paragraph (b)(1) of this section, the 
Administrator may, in his or her discretion, require that the proposed 
offset plan under paragraph (b)(1) of this section be reviewed under 
paragraphs (c) through (k) of this section. The Administrator may 
exercise such discretion where he or she determines that review of the 
plan is necessary to ensure compliance with the emissions limitation and 
reduction goals or other purposes of title IV of the Act.
    (3) If the designated representative submits a complete proposed 
offset plan that does not meet the requirements of paragraph (b)(1) of 
this section, the Administrator will review the plan under paragraphs 
(c) through (k) of this section.
    (c) Supplemental Information. (1)(i) Regardless of whether the 
proposed offset plan is complete under paragraph (a) of this section, 
the Administrator may require submission of any additional information 
that the Administrator determines is necessary to approve an offset 
plan.
    (ii) Such supplemental information may include, but is not limited 
to:
    (A) A description of the measures that are proposed to be taken to 
ensure that the unit will have sufficient allowances to offset the 
excess emissions and to prevent excess emissions in future years;
    (B) A schedule of compliance with appropriate increments of progress 
for the proposed measures; and
    (C) A schedule for the submission of progress reports, and 
supporting documentation, describing actions taken and actions remaining 
to be taken under the schedule of compliance and any proposed 
adjustments to the schedule of compliance.
    (2)(i) The designated representative shall submit the information 
required under paragraph (c)(1) of this section within 30 days after he 
or she is notified of the requirement for supplemental information 
unless the Administrator allows for additional time to collect and 
submit the information.
    (ii) If the designated representative fails to submit the 
supplemental information within the required time period, the 
Administrator may disapprove the proposed offset plan.
    (d) Draft Offset Plan. (1) After the Administrator receives a 
complete proposed offset plan and any supplemental information, the 
Administrator will prepare a draft offset plan that incorporates in 
whole, in part, or with changes or conditions as appropriate, the 
proposed offset plan or disapprove a draft offset plan for the affected 
unit. Regardless of whether the Administrator required the submission of 
the information set forth in paragraph (c)(1)(ii) of this section, the 
draft offset plan may include, among other requirements and conditions 
as determined to be appropriate by the Administrator, the submission of 
schedules of compliance, progress reports, and monitoring and other 
information.
    (2) The draft offset plan will be based on the information submitted 
by the designated representative for the affected unit and other 
relevant information.
    (3) The Administrator will serve a copy of the draft offset plan and 
the statement of basis on the designated representative of the affected 
unit.
    (4) The Administrator will provide a 30-day period for public 
comment, and

[[Page 367]]

opportunity to request a public hearing, on the draft offset plan or 
disapproval of a draft offset plan in accordance with the public notice 
required under paragraph (g)(1)(i)(A) of this section.
    (e) Offset Plan Administrative Record. (1) The Administrator will 
prepare an administrative record for an offset plan or disapproval of an 
offset plan. The administrative record will contain:
    (i) The proposed offset plan and any supporting or supplemental 
information submitted by the designated representative;
    (ii) The draft offset plan;
    (iii) The statement of basis;
    (iv) Copies of all documents relied on by the Administrator in 
approving or disapproving the draft offset plan (including any records 
of discussions or conferences with owners, operators or the designated 
representative of the unit or interested persons regarding the draft 
offset plan) or, for any such documents that are readily available, a 
statement of their location;
    (v) Copies of all written public comments submitted on the draft 
offset plan or disapproval of a draft offset plan;
    (vi) The record of any public hearing on the draft offset plan or 
disapproval of a draft offset plan;
    (vii) The offset plan approved by the Administrator; and
    (viii) Any response to public comments submitted on the draft offset 
plan or disapproval of a draft offset plan, including any documents 
cited in the response and any other documents relied on by the 
Administrator or, for any such documents that are readily available, a 
statement of their location.
    (2) The Administrator will approve or disapprove an offset plan 
within 6 months of receipt of a complete proposed offset plan.
    (f) Statement of Basis. (1) The statement of basis will briefly set 
forth significant factual, legal, and policy considerations on which the 
Administrator relied in approving or disapproving the draft offset plan.
    (2) The statement of basis will include:
    (i) The reasons, and supporting authority, for approval or 
disapproval of any proposed offset plan that does not require deduction 
of allowances during the year after the year for which the plan is 
submitted, including references to applicable statutory or regulatory 
provisions and to the administrative record; and
    (ii) The name, address, and telephone and facsimile number of the 
EPA office processing the approval or disapproval of the offset plan.
    (g) Opportunities for Public Comment on Draft Offset Plans.
    (1) Generally. (i) The Administrator will give public notice of the 
following:
    (A) The draft offset plan or disapproval of a draft offset plan and 
the opportunity for public comment and to request a public hearing; and
    (B) Date, time, location, and procedures for any scheduled hearing 
on the draft offset plan or the disapproval of a draft offset plan.
    (ii) Any public notice given under this section may be for the 
approval or disapproval of one or more draft offset plans.
    (2) Methods. The Administrator will give the public notice required 
by this section by:
    (i) Serving written notice on the following persons (except to the 
extent any such person has waived his or her right to receive such 
notice):
    (A) The designated representative;
    (B) The State or local air pollution agency and any utility 
regulatory authority with jurisdiction over the owners of the unit 
covered by the proposed offset plan;
    (C) The State or local air pollution agency for any contiguous State 
whose air quality may be affected by, or for any State located within a 
50-mile radius of, the unit covered by the proposed offset plan; and
    (D) Any interested person.
    (ii) Giving notice by publication in the Federal Register and in a 
newspaper of general circulation in the area where the unit is located 
or in a State publication designed to give general public notice.
    (3) Contents. All public notices issued under this part will contain 
the following information:
    (i) Identification of the EPA office processing the approval or 
disapproval

[[Page 368]]

of the draft offset plan for which the notice is being given.
    (ii) Identification of the designated representative for the 
affected unit.
    (iii) Identification of each affected unit covered by the proposed 
offset plan.
    (iv) The amount of excess emissions that must be offset and the date 
on which the allowances are proposed to be deducted.
    (v) The address and office hours of a public location where the 
administrative record is available for public inspection and a statement 
that all information submitted by the designated representative and not 
protected as confidential pursuant to section 114(c) of the Act is 
available for public inspections as part of the administrative record.
    (vi) For public notice under paragraph (g)(1)(i)(A) of this section, 
a brief description of the public comment procedures, including:
    (A) A 30-day public comment period beginning the date of publication 
of the notice or, in the case of an extension or reopening of the public 
comment period, such period as the Administrator deems appropriate;
    (B) The address where public comments should be sent;
    (C) Required formats and contents for public comment;
    (D) An opportunity to request a public hearing to occur not earlier 
than 15 days after public notice is given and the location, date, time, 
and procedures of any scheduled public hearing; and
    (E) Any other means by which the public may participate.
    (4) Extensions and Reopenings of the Public Comment Period. On the 
Administrator's own motion, or on the request for any person, the 
Administrator may, at his or her discretion, extend or reopen the public 
comment period where he or she finds that doing so will contribute to 
the decision-making process by clarifying one or more significant issues 
affecting the draft offset plan or disapproval of a draft offset plan. 
Notice of any such extension or reopening will be given under paragraph 
(g)(1)(i)(A) of this section.
    (h) Public comments. (1) General. During the public comment period, 
any person may submit written comments on the draft offset plan or 
disapproval of a draft offset plan.
    (2) Form. (i) Comments shall be submitted in duplicate.
    (ii) The submission shall clearly indicate the draft offset plan 
approval or disapproval to which the comments apply.
    (iii) The submission shall clearly indicate the name of the 
commenter, his or her interest, and his or her affiliation, if any, to 
owners and operators of any unit covered by the proposed offset plan.
    (3) Contents. Timely comments on any aspect of a draft offset plan 
or disapproval of a draft offset plan will be considered unless they 
concern issues that are not relevant, such as:
    (i) The environmental effects of acid rain, acid deposition, sulfur 
dioxide, or nitrogen oxides generally; and
    (ii) Offset plan approval procedures or actions on other proposed 
offset plans that are not relevant to approval or disapproval of the 
draft offset plan in question.
    (4) Persons who do not wish to raise issues on the draft offset plan 
or denial of a draft offset plan, but who wish to be notified of any 
subsequent actions concerning such matter, may so indicate during the 
public comment period or at any other time. The Administrator will place 
their names on a list of interested persons.
    (i) Opportunity for Public Hearing. (1) During the public comment 
period, any person may request a public hearing. A request for a public 
hearing shall be made in writing and shall state the issues proposed to 
be raised in the hearing.
    (2) On the Administrator's own motion or on the request of any 
person, the Administrator may, at his or her discretion, hold a public 
hearing whenever the Administrator finds that such a hearing will 
contribute to the decision-making process by clarifying one or more 
significant issues affecting the draft offset plan or disapproval of a 
draft offset plan. Public hearings will not be held on issues under 
paragraphs (h)(3) (i) and (ii) of this section.
    (3) During a public hearing under this section, any person may 
submit oral or written comments concerning the draft

[[Page 369]]

offset plan or disapproval of a draft offset plan. The Administrator may 
set reasonable limits on the time allowed for oral statements and will 
require the submission of written summaries of each oral statement.
    (4) The Administrator will assure that a record is made of the 
hearing.
    (j) Response to Comments. (1) The Administrator will consider 
comments on the draft offset plan or disapproval of a draft offset plan 
received during the public comment period and any public hearing. The 
Administrator is not required to consider comments otherwise received.
    (2) In approving or disapproving an offset plan, the Administrator 
will:
    (i) Identify any draft offset plan provision or portion of the 
statement of basis that has been changed and the reasons for the change; 
and
    (ii) Briefly describe and respond to relevant comments under 
paragraph (j)(1) of this section.
    (k) Approval and Effective Date of Excess Emissions Offset Plans. 
(1) After the close of the public comment period, the Administrator will 
approve an offset plan requiring allowance deductions in an amount equal 
to the unit's tons of excess emissions or disapprove an offset plan. The 
Administrator will serve a copy of any approved offset plan and the 
response to comment on the designated representative for the affected 
unit involved and serve written notice of the approval or disapproval of 
the offset plan on any persons who are entitled to written notice under 
paragraphs (g)(2)(i) (B), (C), and (D) of this section. The 
Administrator will also give notice in the Federal Register.
    (2) The Administrator will approve an offset plan requiring 
deduction from the unit's compliance subaccount, by December 31 of the 
year after the year for which the report is submitted, of all allowances 
necessary to offset the excess emissions except to the extent the 
designated representative of the unit demonstrates that such a deduction 
will interfere with electric reliability.
    (3) Upon approval of the offset plan by the Administrator, the 
offset plan will be incorporated into the Acid Rain permit in accordance 
with Sec. 72.84 (automatic permit amendment) and shall supersede any 
inconsistent provision of the permit.



Sec. 77.5  Deduction of allowances to offset excess emissions of sulfur dioxide.

    (a) The Administrator will deduct allowances to offset excess 
emissions in accordance with the offset plan approved under Sec. 77.4(b) 
(1) or (k) or in accordance with Sec. 72.91(b) of this chapter.
    (b) The designated representative shall hold enough allowances in 
the appropriate compliance subaccount to cover the deductions to be made 
in accordance with paragraph (a) or paragraph (c) of this section.
    (c) If the designated representative does not submit a timely and 
complete proposed offset plan, or if the Administrator disapproves a 
proposed offset plan under Sec. 77.4 (c) or (k), the Administrator will 
immediately deduct allowances, from the unit's compliance subaccount on 
a first-in, first-out basis in accordance with Sec. 73.35(c)(2) of this 
chapter, equal to the amount of the unit's excess emissions of sulfur 
dioxide.
    (d) If a compliance subaccount does not contain adequate allowances 
to offset the excess emissions, the Administrator will deduct the 
required allowances whenever allowances are recorded to that account.



Sec. 77.6  Penalties for excess emissions of sulfur dioxide and nitrogen oxides.

    (a) If excess emissions of sulfur dioxide or nitrogen oxides occur 
at an affected unit during any year, the owners and operators of the 
affected unit shall pay, without demand, an excess emissions penalty, as 
calculated under paragraph (b) of this section. Such payment shall be 
submitted to the Administrator no later than 60 days after the end of 
any year during which excess emissions occurred at an affected unit or, 
for any increase in excess emissions of sulfur dioxide determined after 
adjustments made under Sec. 72.91(b) of this chapter, or 
Sec. 74.44(c)(2) of this chapter, by July 31 of the year in which the 
adjustments are made.
    (b) Penalty formula. (1) The following formulas shall be used to 
determine the excess emissions penalty:


[[Page 370]]


Penalty for excess emissions of sulfur dioxide=$2000/ton  x  annual 
          adjustment factor  x  tons of excess emissions of sulfur 
          dioxide.
Penalty for excess emissions of nitrogen oxides=$2000/ton  x  annual 
          adjustment factor  x  tons of excess emissions of nitrogen 
          oxides.

    (i) The annual adjustment factor will be calculated as follows:

Annual adjustment factor=1+ {[CPI(year)-CPI(1990)]/CPI(1990)}

where:
(A) ``CPI(year)'' is the Consumer Price Index as defined in Sec. 72.2 of 
          this chapter and ``year'' is the year in which the unit had 
          excess emissions.
(B) ``CPI(1990)'' is the Consumer Price Index for 1990, as defined in 
          Sec. 72.2 of this chapter.

    (ii) The Administrator will publish the annual adjustment factor in 
the Federal Register by October 15 of each year beginning in 1995.
    (2) The penalty may be rounded to the nearest dollar after 
completing the calculation in paragraph (b)(1)(i) of this section.
    (3) The penalty for excess emissions of sulfur dioxide shall be paid 
separately from the payment for excess emissions of nitrogen oxides. 
Each payment shall be accompanied by a document, in a format prescribed 
by the Administrator, indicating the unit for which the payment is made, 
whether the payment is for excess emissions of sulfur dioxide or 
nitrogen oxides, the number of tons of excess emissions, the penalty 
amount, and the check or money order number of the payment.
    (c) If an excess emissions penalty due under this part is not paid 
on or before the applicable deadline under paragraph (a) of this 
section, the penalty shall be subject to interest charges in accordance 
with the Debt Collection Act (31 U.S.C. 3717). Interest shall begin to 
accrue on the date on which the Administrator mails, to the designated 
representative of the unit with excess emissions, a demand notice for 
the payment.
    (d)(1) Except for wire transfers made in accordance with paragraph 
(d)(2) of this section, payments of penalties shall be made by money 
order, cashier's check, certified check, or U.S. Treasury check made 
payable to the ``U.S. EPA.''
    (2) Payments made under paragraph (c)(1) of this section shall be 
mailed to the following address, unless the Administrator has notified 
the designated representative of a different address: U.S. EPA: 
Headquarters Accounting Operations Branch, Acid Rain Excess Emissions 
Penalties, P.O. Box 952491, St. Louis, MO 63195-2491.
    (3) Payments of penalties of $25,000 or more may be made by wire 
transfer to the U.S. Treasury at the Federal Reserve Bank of New York.
    (e) If the Administrator determines that overpayment has been made, 
he or she will refund the overpayment without interest, as promptly as 
administratively possible.
    (f) Excess emissions in any year resulting directly from an order 
issued in that year under section 110(f) of the Act shall not be subject 
to the penalty payment requirements of this section; provided that the 
designated representative of any unit subject to such order shall advise 
the Administrator within 30 days of issuance of the order that the order 
will result in such excess emissions.

[58 FR 3757, Jan. 11, 1993, as amended at 60 FR 17131, Apr. 4, 1995]



PART 78--APPEAL PROCEDURES FOR ACID RAIN PROGRAM--Table of Contents




Sec.
78.1  Purpose and scope.
78.2  General.
78.3  Petition for administrative review and request for evidentiary 
          hearing.
78.4  Filings.
78.5  Limitation on filing or presenting new evidence and raising new 
          issues.
78.6  Action on petition for administrative review.
78.7  Stays of contested Acid Rain requirements pending appeal.
78.8  Consolidation and severance of appeals proceedings.
78.9  Notice of the filing of petition for administrative review.
78.10  Ex parte communications during pendency of a hearing.
78.11  Intervenors.
78.12  Standard of review.
78.13  Scheduling orders and pre-hearing conferences.
78.14  Evidentiary hearing procedure.
78.15  Motions in evidentiary hearings.

[[Page 371]]

78.16  Record of appeal proceeding.
78.17  Proposed findings and conclusions and supporting brief.
78.18  Proposed decision.
78.19  Interlocutory appeal.
78.20  Appeal of decision of Administrator or proposed decision to the 
          Environmental Appeals Board.

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

    Source: 58 FR 3760, Jan. 11, 1993, unless otherwise noted.



Sec. 78.1  Purpose and scope.

    (a) This part shall govern appeals of any decision of the 
Administrator under the Acid Rain Program that, in the absence of an 
administrative appeal, will be final agency action; provided that 
matters listed in Sec. 78.3(d) and interim decisions, such as draft Acid 
Rain permits or proposed alternative monitoring systems, may not be 
appealed.
    (b) The decisions of the Administrator that may be appealed include 
but are not limited to:
    (1) Under part 72 of this chapter;
    (i) The determination of incompleteness of an Acid Rain permit 
application;
    (ii) The issuance or denial of an Acid Rain permit and approval or 
disapproval of a compliance option by the Administrator;
    (iii) The approval or disapproval of an early ranking application 
for Phase I extension under Sec. 72.42 of this chapter;
    (iv) The final determination of whether a technology is a qualified 
repowering technology under Sec. 72.44 of this chapter;
    (v) The issuance or denial of a written exemption for new units or 
retired units under Secs. 72.7 and 72.8 of this chapter;
    (vi) The approval or disapproval of a permit revision;
    (vii) The decision on the deduction or return of allowances under 
Secs. 72.41, 72.42, 72.43, 72.44, 72.91(b), and 72.92 (a) and (c) of 
this chapter; and
    (viii) The failure to issue an Acid Rain permit in accordance with 
the deadline under Sec. 72.74(b) of this chapter.
    (2) Under part 73 of this chapter,
    (i) The decision on a claim of error in a transfer recordation;
    (ii) The decision on the allocation of allowances from the 
Conservation and Renewal Energy Reserve;
    (iii) The decision on the allocation of allowances under regulations 
implementing sections 404(e), 405(g)(4), 405(i)(2), and 410(h) of the 
Act;
    (iv) The decision on the allocation of allowances under part 73, 
subpart F of this chapter;
    (v) The decision on the sale or return of allowances and transfer of 
proceeds under part 73, subpart E; and
    (vi) The decision on the deduction of allowances under Sec. 73.35(b) 
of this chapter.
    (3) Under part 74 of this chapter,
    (i) The determination of incompleteness of an opt-in permit 
application;
    (ii) The issuance or denial of an opt-in permit and approval or 
disapproval of the transfer of allowances for the replacement of thermal 
energy;
    (iii) The approval or disapproval of a permit revision to an opt-in 
permit;
    (iv) The decision on the deduction or return of allowances under 
subpart E of part 74 of this chapter;
    (4) Under part 75 of this chapter,
    (i) The decision on a petition for approval of an alternative 
monitoring system;
    (ii) The approval or disapproval of a monitoring system 
certification or recertification;
    (iii) The finalization of annual emissions data, including 
retroactive adjustment based on audit;
    (iv) The determination of the percentage of emissions reduction 
achieved by qualifying Phase I technology; and
    (v) The determination on the acceptability of parametric missing 
data procedures for a unit equipped with add-on controls for sulfur 
dioxide and nitrogen oxides in accordance with part 75 of this chapter.
    (5) Under part 77 of this chapter, the determination of 
incompleteness of an offset plan and the approval or disapproval of an 
offset plan under Sec. 77.4 of this chapter and the deduction of 
allowances under Sec. 77.5(c) of this chapter.
    (c) In order to appeal a decision under paragraph (a) of this 
section, a person shall file a petition for administrative review with 
the Environmental Appeals Board under Sec. 78.3. The Environmental 
Appeals Board will, consistent with Sec. 78.6, either:

[[Page 372]]

    (1) Issue an order deciding the appeal; or
    (2) Where there is a disputed issue of fact material to the 
contested portions of the decision, refer the proceeding to the Chief 
Administrative Law Judge, who will designate an Administrative Law Judge 
to conduct an evidentiary hearing to decide the disputed issue of fact. 
If the proposed decision is contested or the Environmental Appeals Board 
decides to review the proposed decision, the Environmental Appeals Board 
will issue an order deciding the appeal.
    (d) Questions arising at any stage of a proceeding that are not 
addressed in this part will be resolved at the discretion of the 
Environmental Appeals Board or the Presiding Officer.

[58 FR 3760, Jan. 11, 1993, as amended at 60 FR 17132, Apr. 4, 1995]



Sec. 78.2  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 units exemption), 72.9 (standard 
requirements), 72.10 (availability of information), and 72.11 
(computation of time), shall apply to this part.



Sec. 78.3  Petition for administrative review and request for evidentiary hearing.

    (a)(1) The following persons may petition for administrative review 
of a decision of the Administrator that is made under parts 72, 74, 75, 
76, and 77 of this chapter and that is appealable under Sec. 78.1(a) of 
this part:
    (i) The designated representative for the unit covered by the 
decision;
    (ii) The authorized account representative for an account covered by 
the decision; and
    (iii) Any interested person.
    (2) The following persons may petition for administrative review of 
a decision of the Administrator that is made under part 73 of this 
chapter and that is appealable under Sec. 78.1(a):
    (i) The authorized account representative for any Allowance Tracking 
System account covered by the decision; and
    (ii) With regard to the decision on the allocation of allowances 
from the Conservation and Renewable Energy Reserve, the certifying 
official whose application is covered by the decision.
    (b)(1) Within 60 days following issuance of a decision under 
Sec. 78.1 of this part by the Administrator, any person under paragraph 
(a) of this section may file a petition with the Environmental Appeals 
Board for administrative review of the decision. If no petition for 
administrative review of a decision under Sec. 78.1 of this part is 
filed within such period, the decision shall become final agency action.
    (2) The petition may include a request for an evidentiary hearing to 
resolve any disputed issue of material fact concerning the decision.
    (3) At the same time that the petition for administrative review is 
filed, the petitioner shall:
    (i) Serve a copy of the petition on the designated representative or 
authorized account representative under paragraph (a)(1) and (2) of this 
section (unless the designated representative or authorized account 
representative is the petitioner) and the Administrator; and
    (ii) Mail a notice of the petition to the persons entitled to 
written notice under Sec. 72.65(b)(1)(ii), (iii), and (iv) of this 
chapter.
    (c) The petition for administrative review under this part shall 
state with specificity:
    (1) Each material factual and legal issue alleged to be in dispute 
and any such factual issue for which an evidentiary hearing is sought;
    (2) A clear and concise statement of the nature and scope of the 
interest of the petitioner;
    (3) A clear and concise brief in support of the petition, explaining 
why the factual or legal issues are material and, if an evidentiary 
hearing is requested, why direct and cross-examination of witnesses is 
necessary to resolve such factual issues;
    (4) If an evidentiary hearing is requested, the time estimated to be 
necessary for an evidentiary hearing;
    (5) If an evidentiary hearing is requested, a certified statement 
that, in the event of an evidentiary hearing, and without cost or 
expense to any

[[Page 373]]

other party, any of the following persons shall be available to appear 
and testify:
    (i) The petitioner; and
    (ii) Any officer, director, employee, consultant, or agent of the 
petitioner.
    (6) Specific references to the contested portions of the decision;
    (7) Any revised or alternative action of the Administrator sought by 
the petitioner as necessary to implement the requirements, purposes, or 
policies of title IV of the Act; and
    (8) Identification of any portion of the decision that the 
petitioner believes should be stayed pending resolution of the appeal.
    (d) In no event shall a petition for administrative review be filed, 
or review be available under this part, with regard to:
    (1) A decision under part 73 of this chapter to which the claim of 
error procedure applies, but for which no claim of error notification 
was submitted, under part 73 of this chapter;
    (2) Any provision or requirement of part 72, 73, 74, 75, 76, or 77 
of this chapter, including any standard requirement under Sec. 72.9 of 
this chapter and any emissions monitoring or reporting requirements 
under part 75 of this chapter;
    (3) The reliance by the Administrator on a certificate of 
representation submitted by a designated representative or a 
certification statement submitted by an authorized account 
representative under the Acid Rain Program; and
    (4) Actions of the Administrator under sections 112(r), 113, 114, 
120, 301, and 303 of the Act.

[58 FR 3760, Jan. 11, 1993, as amended at 60 FR 17132, Apr. 4, 1995]



Sec. 78.4  Filings.

    (a) All original filings made under this part shall be signed by the 
person making the filing or by an attorney or authorized representative. 
Any filings on behalf of owners and operators of an affected unit or 
affected source shall be signed by the designated representative. Any 
filings on behalf of persons with an interest in allowances in a general 
account shall be signed by the authorized account representative. The 
name, address, telephone number, and facsimile number of the person 
making the filing shall be provided with the filing.
    (b)(1) All data and information referred to, or in any way relied 
upon, in any filings made under this part shall be included in full and 
may not be incorporated by reference, unless the data or information is 
contained in the administrative record for the decision being appealed.
    (2) Notwithstanding paragraph (b)(1) of this section, State or 
federal statutes, regulations, and judicial decisions published in a 
national reporter system, officially issued EPA documents of general 
applicability, and any other publicly and generally available reference 
material may be incorporated by reference. Any person incorporating such 
materials by reference shall provide copies of the materials as 
instructed by the Environmental Appeals Board or the Presiding Officer.
    (3) If any part of any filing is in a foreign language, it shall be 
accompanied by an English translation verified by the person making the 
translation, under oath, to be complete and accurate, together with the 
name, address, and a brief statement of the qualifications of the person 
making the translation. Translations filed of material originally 
produced in a foreign language shall be accompanied by copies of the 
original material.
    (4) Where relevant data or information is contained in a document 
also containing irrelevant matter, either the irrelevant matter shall be 
deleted or an index to the relevant portions of the document shall be 
included in the document.
    (c)(1) Failure to comply with the requirements of this section or 
any other requirement in this part may result in the noncomplying 
portions of the filing being excluded from consideration. If the 
Environmental Appeals Board or the Presiding Officer determines on 
motion by any party or sua sponte that a filing fails to meet any 
requirement of this part, the Environmental Appeals Board or Presiding 
Officer may return the filing, together with a reference to the 
applicable requirements on which the determination is based. A person 
whose filing has been rejected has 7 days, from the date the returned 
filing is mailed, to correct the filing in

[[Page 374]]

conformance with this part and refile it, unless the Environmental 
Appeals Board or Presiding Officer authorizes a longer time based on 
good cause shown.
    (2) The making of a filing shall not mean or imply that the filing, 
in fact, meets all applicable requirements, that the filing contains 
reasonable grounds for the action requested, or that the action 
requested is in accordance with law.
    (d) An original and two copies of any written filing under this part 
shall be filed with the Environmental Appeals Board unless a proceeding 
is pending before a Presiding Officer, in which case they shall be filed 
with the Hearing Clerk (except as provided under Sec. 78.19(d)) of this 
part.
    (e)(1) The party making any filing in a proceeding under this part 
shall also serve a copy of the filing on each party to the proceeding, 
or, with regard to a petition for administrative review, on the persons 
specified in Sec. 78.3(b)(3) of this part.
    (2) Every filing made under this part shall be accompanied by a 
certificate of service citing the date, place, time, and manner of 
service and the names of the persons served.
    (f) The Hearing Clerk will maintain and furnish, to any person upon 
request, the official service list containing the name, service address, 
telephone, and facsimile numbers of each party to a proceeding under 
this part and his or her attorney or duly authorized representative.
    (g) Affidavits filed under this part shall be made on personal 
knowledge and belief, set forth only those facts that are admissible 
into evidence under Sec. 78.5 of this part, and show affirmatively that 
the affiant is competent to testify to the matters stated therein.



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

    (a) Where there was an opportunity for public comment, or to submit 
a claim of error notification, prior to the decision that is subject to 
appeal, no evidence shall be filed or presented, and no issues raised, 
in a proceeding under this part that were not filed, presented, or 
raised during the public comment period, absent a showing of good cause 
explaining the party's failure to do so during the public comment period 
or in the claim of error notification. Good cause shall include any 
instance where the party seeking to file or present new evidence or 
raise a new issue shows that the evidence could not have reasonably been 
ascertained, filed, or presented, the issue could not have reasonably 
been ascertained or raised, or that the materiality of the new evidence 
or issue could not have reasonably been anticipated, prior to the close 
of the public comment period or the period for submitting a claim of 
error notification.
    (b) If an evidentiary hearing is granted, no evidence shall be filed 
or presented on questions of law or policy or on matters not subject to 
challenge in the evidentiary hearing.



Sec. 78.6   Action on petition for administrative review.

    (a) If no evidentiary hearing concerning the petition for review is 
requested or is to be held, the Environmental Appeals Board will issue 
an order under Sec. 78.20(c) of this part.
    (b)(1) The Environmental Appeals Board may grant a request for an 
evidentiary hearing, or schedule an evidentiary hearing sua sponte, if 
the Environmental Appeals Board finds that there are disputed issues of 
fact material to contested portions of the decision and determines, in 
its discretion, that an opportunity for direct- and cross-examination of 
witnesses may be necessary in order to resolve these factual issues.
    (2) To the extent the Environmental Appeals Board grants a request 
for an evidentiary hearing, in whole or in part, it will:
    (i) Identify the portions of the decision that have been contested, 
and the disputed factual issues that have been raised by the petitioner 
with regard to which the evidentiary hearing has been granted; and
    (ii) Refer the disputed factual issues to the Chief Administrative 
Law Judge for decision and, in its discretion, may also refer all or a 
portion of the remaining legal, policy, or factual issues to the Chief 
Administrative Law Judge for decision.

[[Page 375]]

    (3)(i) After issues are referred to the Chief Administrative Law 
Judge, he or she will designate an Administrative Law Judge as Presiding 
Officer to conduct the evidentiary hearing.
    (ii) Notwithstanding paragraph (b)(3)(i) of this section, if all 
parties waive in writing their right to have an Administrative Law Judge 
designated as the Presiding Officer, the Administrator may designate a 
lawyer permanently or temporarily employed by EPA and without any prior 
connection with the proceeding to serve as Presiding Officer.



Sec. 78.7   Stays of contested Acid Rain requirements pending appeal.

    (a) A contested decision of the Administrator may be stayed, in 
whole or in part consistent with paragraph (b) of this section, by the 
Environmental Appeals Board or the Presiding Officer upon request of a 
party during a proceeding under this part only to the extent necessary 
to prevent irreparable injury pending final agency action.
    (b) The following requirements shall in no event be stayed due to 
any appeal of a decision of the Administrator and shall be fully 
effective and enforceable:
    (1) The allowance allocations for any year during which the appeal 
proceeding is pending or is being conducted;
    (2) Any standard requirements under Sec. 72.9 of this chapter;
    (3) The emissions monitoring and reporting requirements applicable 
to the affected units at an affected source under part 75 of this 
chapter;
    (4) Uncontested provisions of the decision; and
    (5) The terms of a certificate of representation submitted by a 
designated representative under part 72, subpart B of this chapter or a 
certification statement submitted by an authorized account 
representative under part 73, subpart C of this chapter.
    (c) The permit shield under Sec. 72.51 of this chapter shall 
continue to be in effect.
    (d) The Environmental Appeals Board or Presiding Officer shall 
specify which provisions of the decision shall be stayed.



Sec. 78.8  Consolidation and severance of appeals proceedings.

    (a) The Environmental Appeals Board or Presiding Officer has the 
discretion to consolidate, in whole or in part, two or more proceedings 
under this part whenever it appears that a joint proceeding on any or 
all of the matters at issue in the proceedings will be in the interest 
of justice, will expedite or simplify consideration of the issues, and 
will not prejudice any party. Consolidation of proceedings under this 
paragraph (a) will not affect the right of any party to raise issues 
that might have been raised had there been no consolidation.
    (b) The Environmental Appeals Board or Presiding Officer has the 
discretion to sever issues or parties from a proceeding under this part 
whenever it appears that separate proceedings will be in the interest of 
justice, will expedite or simplify consideration of the issues, and will 
not prejudice any party.



Sec. 78.9  Notice of the filing of petition for administrative review.

    The Administrator will publish in the Federal Register a notice 
stating that a petition for administrative review of a decision of the 
Administrator has been filed and specifying any request in the petition 
for an evidentiary hearing.



Sec. 78.10  Ex parte communications during pendency of a hearing.

    (a)(1) No party or interested person outside EPA, representative of 
a party or interested person, or member of the EPA trial staff shall 
make, or knowingly cause to be made, to any member of the decisional 
body an ex parte communication on the merits of a proceeding under this 
part.
    (2) No member of the decisional body shall make, or knowingly cause 
to be made, to any party or interested person outside EPA, 
representative of a party or interested person, or member of the EPA 
trial staff, an ex parte communication on the merits of any proceeding 
under this part.
    (3) A member of the decisional body who receives, makes, or 
knowingly causes to be made an ex parte communication prohibited by this 
paragraph

[[Page 376]]

shall file with the Environmental Appeals Board (or, if the proceeding 
is pending before an Administrative Law Judge, with the Hearing Clerk) 
for inclusion in the record of the proceeding under this part any such 
written ex parte communications and memoranda stating the substance of 
any such oral ex parte communication.
    (b) Whenever any member of the decisional body receives an ex parte 
communication made, or knowingly caused to be made by a party or 
representative of a party to a proceeding under this part, the person 
presiding over the proceedings then in progress may, to the extent 
consistent with justice, require the party to show good cause why its 
claim or interest in the proceedings should not be dismissed, denied, 
disregarded, or otherwise adversely affected on account of these ex 
parte communications.
    (c) The prohibitions of paragraph (a) of this section shall begin to 
apply upon publication by the Administrator of the notice of the filing 
of a petition under Sec. 78.9 of this part. This prohibition terminates 
on the date of final agency action.



Sec. 78.11  Intervenors.

    (a) Within 30 days after notice is given under Sec. 78.9 of this 
part that the petition for administrative review has been filed, any 
person listed in Sec. 78.3(a) of this part may file a motion for leave 
to intervene in the proceeding. A motion for leave to intervene under 
this section shall set forth the grounds for the proposed intervention 
and may respond to the petition for administrative review. Late motions 
to intervene may be granted only for good cause shown.
    (b) The Environmental Appeals Board of Presiding Officer will grant 
a motion to intervene only upon an express finding that:
    (1) The motion to intervene raises matters relevant to the factual 
or legal issues to be reviewed;
    (2) The intervenor consented to be bound by all stipulations 
previously entered into by the existing parties, and all orders 
previously issued, in the proceeding; and
    (3) The intervention will promote the interests of justice and will 
not cause undue delay or prejudice to the rights of the existing 
parties.



Sec. 78.12  Standard of review.

    (a) On appeal of a decision of the Administrator prior to which 
there was an opportunity for public comment, or to submit a claim of 
error notification:
    (1) Except as provided under paragraph (a)(2) of this section, the 
petitioner shall have the burden of going forward and of persuasion to 
show that a finding of fact or conclusion of law underlying the decision 
is clearly erroneous or that an exercise of discretion or policy 
determination underlying the decision is arbitrary and capricious or 
otherwise warrants review.
    (2) The owners and operators of the source or unit involved shall 
have the burden of persuasion that an Acid Rain permit or a written 
exemption under Secs. 72.7 or 72.8 of this chapter was properly issued 
or should be issued.
    (b) On appeal of a decision of the Administrator not covered by 
paragraph (a) of this section, the Administrator shall have the burden 
of going forward to show the rational basis for the decision. The 
petitioner shall have the burden of persuasion to show that a finding of 
fact or conclusion of law underlying the decision is clearly erroneous 
or that an exercise of discretion or policy determination underlying the 
decision is arbitrary and capricious or otherwise warrants review.



Sec. 78.13  Scheduling orders and pre-hearing conferences.

    (a) If a request for an evidentiary hearing is granted, the 
Presiding Officer will issue an order scheduling the following:
    (1) The filing by each party of a narrative statement of position on 
each factual issue in controversy.
    (2) The identification of any witness that a party expects to call 
and of any written testimony, documents, papers, exhibits, or other 
materials that a party expects to introduce into evidence. At the 
request of the Presiding Officer, the party shall include a brief 
narrative summary of any witness' expected testimony and of any such 
materials.
    (3) The filing of written testimony, in accordance with 
Sec. 78.14(b) of this part,

[[Page 377]]

and other evidence in support of a narrative statement.
    (4) The filing of any motions by any party, including motions for 
the production of documentation, data, or other information material to 
the disputed facts to be addressed at the hearing.
    (b) The Presiding Officer may also, on motion or sua sponte, 
schedule one or more pre-hearing conferences on the record to address 
any of the following:
    (1) Simplification, clarification, amplification, or limitation of 
the issues.
    (2) Admissions and stipulations of facts and determinations of the 
genuineness of documents.
    (3) Objections to the introduction into evidence at the hearing of 
any written testimony or other submissions proposed by a party; provided 
that at any time before the end of the hearing, any party may make, and 
the Presiding Officer may consider and rule upon, a motion to strike 
testimony or other evidence (other than evidence included in the 
administrative record (if any) under Sec. 72.63 of this chapter) on the 
grounds of relevance, competency, or materiality.
    (4) Taking official notice of any matters.
    (5) Grouping of parties with substantially similar interests to 
eliminate redundant evidence, motions, objections, and briefs.
    (6) Such other matters that may expedite the hearing or aid in the 
disposition of matters in dispute.
    (c) The Presiding Officer will issue an order (which may be in the 
form of a transcript) reciting the actions taken at any pre-hearing 
conferences, setting the schedule for any hearing, and stating any areas 
of factual and legal agreement and disagreement and the methods and 
procedures to be used in developing any evidence.



Sec. 78.14  Evidentiary hearing procedure.

    (a) If a request for an evidentiary hearing is granted, the 
Presiding Officer will conduct a fair and impartial hearing on the 
record, take action to avoid unnecessary delay in the disposition of the 
proceedings, and maintain order. For theses purposes, the Presiding 
Officer may:
    (1) Administer oaths and affirmations.
    (2) Regulate the course of the hearings and prehearing conferences 
and govern the conduct of participants.
    (3) Examine witnesses.
    (4) Identify and refer issues for interlocutory decision under 
Sec. 78.19 of this part.
    (5) Rule on, admit, exclude, or limit evidence.
    (6) Establish the time for filing motions, testimony and other 
written evidence, and briefs and making other filings.
    (7) Rule on motions and other pending procedural matters, including 
but not limited to motions for summary disposition in accordance with 
Sec. 78.15 of this part.
    (8) Order that the hearing be conducted in stages whenever the 
number of parties is large or the issues are numerous and complex.
    (9) Allow direct and cross-examination of witnesses only to the 
extent the Presiding Officer determines that such direct and cross-
examination may be necessary to resolve disputed issues of material 
fact; provided that no direct or cross-examination shall be allowed on 
questions of law or policy or regarding matters that are not subject to 
challenge in the evidentiary hearing.
    (10) Limit public access to the hearing where necessary to protect 
confidential business information. The Presiding Officer will provide 
written notice of the hearing to the parties, and where the hearing will 
be open to the public, notice in the Federal Register no later than 15 
days prior to commencement of the hearings.
    (11) Take any other action not inconsistent with the provisions of 
this part for the maintenance of order at the hearing and for the 
expeditious, fair and impartial conduct of the proceeding.
    (b) All direct and rebuttal testimony at an evidentiary hearing 
shall be filed in written form, unless, upon motion and good cause 
shown, the Presiding Officer, in his or her discretion, determines that 
oral presentation of such evidence on any particular factual issue will 
materially assist in the efficient resolution of the issue.

[[Page 378]]

    (c)(1) The Presiding Officer will admit all evidence that is not 
irrelevant, immaterial, unduly repetitious, or otherwise unreliable or 
of little probative value. Evidence relating to settlement that would be 
excluded in the federal courts under Rule 408 of the Federal Rules of 
Evidence shall not be admissible.
    (2) Whenever any evidence or testimony is excluded by the Presiding 
Officer as inadmissible, all such evidence will remain a part of the 
record as an offer of proof. The party seeking the admission of oral 
testimony may make an offer of proof by means of a brief statement on 
the record describing the testimony excluded.
    (3) When two or more parties have substantially similar interests 
and positions, the Presiding Officer may limit the number of attorneys 
or authorized representatives who will be permitted to examine witnesses 
and to make and argue motions and objections on behalf of those parties.
    (4) Rulings of the Presiding Officer on the admissibility of 
evidence or testimony, the propriety of direct and cross-examination, 
and other procedural matters will appear in the record of the hearing 
and control further proceedings unless reversed by the Presiding Officer 
or as a result of an interlocutory appeal taken under Sec. 78.19 of this 
part.
    (5) All objections shall be made promptly or be deemed waived; 
provided that parties shall be presumed to have taken exception to an 
adverse ruling. No objection shall be deemed waived by further 
participation in the hearing.



Sec. 78.15  Motions in evidentiary  hearings.

    (a) Any party may make a motion to the Presiding Officer on any 
matter relating to the evidentiary hearing in accordance with the 
scheduling orders issued under Sec. 78.13 of this part. All motions 
shall be in writing and served as provided in Sec. 78.4 of this part, 
except those made on the record during an oral hearing before the 
Presiding Officer.
    (b) Any party may make a motion for a summary disposition in its 
favor on any factual issue on the basis that there is no genuine issue 
of material fact. When a motion for summary disposition is made and 
supported, any party opposing the motion may not rest upon mere 
allegations or denials, but must show, by affidavit or by other 
materials subject to consideration by the Presiding Officer, that there 
is a genuine issue of material fact.
    (c) Within 10 days after a motion made on the record or service of 
any written motion, any party may file a response to the motion. The 
time for response may be shortened or extended by the Presiding Officer 
for good cause shown.
    (d) The Presiding Officer may schedule an oral argument and call for 
the filing of briefs on any motion. The Presiding Officer will rule on 
the motion within a reasonable time after the date that responses to the 
motion may be filed under paragraph (c) of this section and that any 
oral argument or filing of briefs is completed.
    (e) If all factual issues are decided by summary disposition prior 
to the hearing, no hearing will be held and the Presiding Officer will 
issue a proposed decision under Sec. 78.18 of this part. If a summary 
disposition is denied or if partial summary disposition is granted, the 
hearing shall proceed on the remaining issues.



Sec. 78.16  Record of appeal proceeding.

    (a) The proposed decision issued by the Presiding Officer, 
transcripts of oral hearings or oral arguments, written direct and 
rebuttal testimony, and any other written materials of any kind filed in 
the proceeding will be part of the record and will be available to the 
public in the office of the Hearing Clerk, subject to the requirements 
of part 2 of this chapter.
    (b) Hearings and oral arguments shall be recorded as specified by 
the Presiding Officer, and thereupon transcribed. After the hearing or 
oral argument, the reporter will certify and file with the Hearing 
Clerk.
    (1) The original transcript; and
    (2) Any exhibits received or offered into evidence at the hearing.
    (c) The Hearing Clerk will promptly give written notice to the 
parties when any transcript is available. Any party that desires a copy 
of the transcript

[[Page 379]]

may obtain a copy upon payment of costs.
    (d) The Presiding Officer will allow witnesses, parties, and their 
counsel or representatives:
    (1) Up to 7 days from issuance of the notice under paragraph (c) of 
this section in order to file written proposed corrections of the 
transcript necessary to correct errors made in the transcribing; and
    (2) Up to 7 days from the submission of the corrections in order to 
file objections to the proposed corrections.
    (e) The Presiding Officer will determine which, if any, corrections 
should be made to the transcript and incorporate them into the record.



Sec. 78.17  Proposed findings and conclusions and supporting brief.

    Within 45 days after issuance of a notice under Sec. 78.16(c) of 
this part that the complete transcript of the evidentiary hearing is 
available, any party may file with the Hearing Clerk proposed findings 
and conclusions on the issues referred to the Presiding Officer and a 
brief in support thereof. Briefs shall contain appropriate references to 
the record. The Presiding Officer, for good cause shown, may shorten or 
extend the time for filing and may allow reply briefs.



Sec. 78.18  Proposed decision.

    (a) The Presiding Officer will review and evaluate the record, 
including the proposed findings and conclusions and any briefs filed by 
the parties, and issue a proposed decision on the factual, policy, and 
legal issues referred by the Environmental Appeals Board for decision 
under Sec. 78.6(b)(2)(ii) of this part, accompanied by findings of fact 
and proposed conclusions of law, as appropriate, within a reasonable 
time after the evidentiary hearing is completed. The Hearing Clerk will 
promptly serve copies of the proposed decision on all parties and on the 
Environmental Appeals Board.
    (b) The proposed decision of the Presiding Officer shall become the 
final agency action under section 307 of the Act 30 days after service 
unless within that time:
    (1) A party files objections with the Environmental Appeals Board 
pursuant to Sec. 78.20(a) of this part, or
    (2) The Environmental Appeals Board sua sponte files a notice that 
it will review the decision under Sec. 78.20(b) of this part.



Sec. 78.19  Interlocutory appeal.

    (a) Interlocutory appeal from orders or rulings of the Presiding 
Officer made during the course of a proceeding may be taken if the 
Presiding Officer certifies those orders or rulings to the Environmental 
Appeals Board for interlocutory appeal on the record. Any requests to 
the Presiding Officer to certify an interlocutory appeal shall be filed 
within 10 days of notice of the order or ruling and shall state briefly 
the grounds for the request.
    (b)(1) Within 15 days of the filing of any request for interlocutory 
appeal, the Presiding Officer may certify an order or ruling for 
interlocutory appeal to the Environmental Appeals Board if:
    (i) The order or ruling involves an important question on which 
there is substantial ground for difference of opinion, and
    (ii) Either:
    (A) An immediate appeal of the order or ruling will materially 
advance the ultimate completion of the proceeding, or
    (B) A review after the proceeding is completed will be inadequate or 
ineffective.
    (2) If the Presiding Officer takes no action within 15 days of the 
filing of a request for interlocutory appeal, the request shall be 
automatically dismissed without prejudice.
    (c) If the Presiding Officer grants certification, the Environmental 
Appeals Board may accept or decline the interlocutory appeal within 30 
days of certification. If the Environmental Appeals Board decides that 
certification was improperly granted, it will decline to hear the 
interlocutory appeal. If the Environmental Appeals Board takes no action 
within 30 days of certification, the interlocutory appeal shall be 
automatically dismissed without prejudice.
    (d) If the Presiding Officer declines to certify an order or ruling 
for an interlocutory appeal, the order or ruling may be reviewed by the 
Environmental

[[Page 380]]

Appeals Board only upon an appeal of the proposed decision following 
completion of the proceedings before the Presiding Officer, except when 
the Environmental Appeals Board determines, upon motion of a party and 
in exceptional circumstances, that to delay review would not be in the 
public interest. Such motion shall be filed with Environmental Appeals 
Board within 5 days after the earlier of automatic dismissal of the 
request for interlocutory appeal or receipt by the party of notification 
that the Presiding Officer declines to certify an order or ruling for 
interlocutory appeal.
    (e) The failure of a party to request an interlocutory appeal shall 
not prevent an appeal of an order or ruling as part of an appeal of a 
proposed decision under Sec. 78.20 of this part.



Sec. 78.20  Appeal of decision of Administrator or proposed decision to the Environmental Appeals Board.

    (a) Within 30 days after the issuance of a proposed decision by a 
Presiding Officer under this part, any party may appeal any matter set 
forth in the proposed decision, or any other order or ruling made during 
the proceeding to which the party objected during the proceeding before 
the Presiding Officer, by filing an objection with the Environmental 
Appeals Board. On appeal of an order, ruling, or proposed decision of a 
Presiding Officer:
    (1) The party filing the objection shall have the burden of going 
forward to show that the order, ruling, or proposed decision is based on 
a finding of fact or conclusion of law that is clearly erroneous; or a 
policy determination or exercise of discretion that is arbitrary and 
capricious or otherwise warrants review; and
    (2) The petitioner or the owners and operators shall have the burden 
of persuasion, as set forth in Sec. 78.12(a) (1) and (2) of this part.
    (b) Within 30 days after issuance of a proposed decision of a 
Presiding Officer, the Environmental Appeals Board may issue sua sponte 
in its discretion a notice of intent to review such proposed decision. 
The Environmental Appeals Board will serve such notice upon all parties 
to the proceeding.
    (c) Within a reasonable time following the filing of a petition for 
administrative review of a decision of the Administrator under Sec. 78.3 
of this part, or, if any issues raised by such petition are referred to 
the Presiding Officer, the filing of objections under paragraph (a) of 
this section or the issuance of a notice of intent to review under 
paragraph (b) of this section, the Environmental Appeals Board will 
issue an order affirming, reversing, modifying, or remanding the 
decision or proposed decision, as appropriate. Prior to issuing this 
order, the Environmental Appeals Board may provide an opportunity for 
parties to file additional briefs.
    (d) If the Environmental Appeals Board issues an order affirming, 
reversing, or modifying the decision of the Administrator, then the 
decision as supplemented or changed by the order, shall be final agency 
action.
    (e) If the Environmental Appeals Board issues an order affirming, 
reversing, or modifying the proposed decision, the proposed decision, as 
supplemented or changed by the order, shall be final agency action.
    (f) If the Environmental Appeals Board issues an order remanding the 
proceeding, then final agency action occurs upon completion of the 
remanded proceeding, including any appeals to the Environmental Appeals 
Board in the remanded proceeding.



PART 79--REGISTRATION OF FUELS AND FUEL ADDITIVES--Table of Contents




                      Subpart A--General Provisions

Sec.
79.1  Applicability.
79.2  Definitions.
79.3  Availability of information.
79.4  Requirement of registration.
79.5  Periodic reporting requirements.
79.6  Requirement for testing.
79.7  Samples for test purposes.
79.8  Penalties.

                 Subpart B--Fuel Registration Procedures

79.10  Application for registration by fuel manufacturer.
79.11  Information and assurances to be provided by the fuel 
          manufacturer.
79.12  Determination of noncompliance.
79.13  Registration.
79.14  Termination of registration of fuels.

[[Page 381]]

               Subpart C--Additive Registration Procedures

79.20  Application for registration by additive manufacturer.
79.21  Information and assurances to be provided by the additive 
          manufacturer.
79.22  Determination of noncompliance.
79.23  Registration.
79.24  Termination of registration of additives.

              Subpart D--Designation of Fuels and Additives

79.30  Scope.
79.31  Additives.
79.32  Motor vehicle gasoline.
79.33  Motor vehicle diesel fuel.

                          Subpart E--[Reserved]

            Subpart F--Testing Requirements for Registration

79.50  Definitions.
79.51  General requirements and provisions.
79.52  Tier 1.
79.53  Tier 2.
79.54  Tier 3.
79.55  Base fuel specifications.
79.56  Fuel and fuel additive grouping system.
79.57  Emission generation.
79.58  Special provisions.
79.59  Reporting requirements.
79.60  Good laboratory practice (GLP) standards for inhalation exposure 
          health effects testing.
79.61  Vehicle emissions inhalation exposure guideline.
79.62  Subchronic toxicity study with specific health effect 
          assessments.
79.63  Fertility assessment/teratology.
79.64  In vivo micronucleus assay.
79.65  In vivo sister chromatid exchange assay.
79.66  Neuropathology assessment.
79.67  Glial fibrillary acidic protein assay.
79.68  Salmonella typhimurium reverse mutation assay.

    Authority: 42 U.S.C. 7414, 7524, 7545 and 7601.

    Source: 40 FR 52011, Nov. 7, 1975, unless otherwise noted.



                      Subpart A--General Provisions



Sec. 79.1   Applicability.

    The regulations of this part apply to the registration of fuels and 
fuel additives designated by the Administrator, pursuant to section 211 
of the Clean Air Act (42 U.S.C. 1857f-6c, as amended by section 9, Pub. 
L. 91-604).



Sec. 79.2   Definitions.

    As used in this part, all terms not defined herein shall have the 
meaning given them in the Act:
    (a) Act means the Clean Air Act (42 U.S.C. 1857 et seq., as amended 
by Pub. L. 91-604).
    (b) Administrator means the Administrator of the Environmental 
Protection Agency.
    (c) Fuel means any material which is capable of releasing energy or 
power by combustion or other chemical or physical reaction.
    (d) Fuel manufacturer means any person who, for sale or introduction 
into commerce, produces, manufactures, or imports a fuel or causes or 
directs the alteration of the chemical composition of, or the mixture of 
chemical compounds in, a bulk fuel by adding to it an additive.
    (e) Additive means any substance that is intentionally added to a 
fuel named in the designation (including any added to a motor vehicle's 
fuel system) and that is not intentionally removed prior to sale or use.
    (f) Additive manufacturer means any person who produces, 
manufactures, or imports an additive for use as an additive and/or sells 
or imports for sale such additive under the person's own name.
    (g) Range of concentration means the highest concentration, the 
lowest concentration, and the average concentration of an additive in a 
fuel.
    (h) Chemical composition means the name and percentage by weight of 
each compound in an additive and the name and percentage by weight of 
each element in an additive.
    (i) Chemical structure means the molecular structure of a compound 
in an additive.
    (j) Impurity means any chemical element present in an additive that 
is not included in the chemical formula or identified in the breakdown 
by element in the chemical composition of such additive.

[40 FR 52011, Nov. 7, 1975, as amended at 59 FR 33092, June 27, 1994]

[[Page 382]]



Sec. 79.3  Availability of information.

    The availability to the public of information provided to, or 
otherwise obtained by, the Administrator under this part shall be 
governed by part 2 of this chapter except as expressly noted in subpart 
F of this part.

[59 FR 33092, June 27, 1994]



Sec. 79.4   Requirement of registration.

    (a) Fuels. (1) No manufacturer of any fuel designated under this 
part shall, after the date prescribed for such fuel in this part, sell, 
offer for sale, or introduce into commerce such fuel unless the 
Administrator has registered such fuel.
    (2) No manufacturer of a registered fuel shall add or direct the 
addition to it of an additive which he has not previously reported 
unless he has notified the Administrator of such intended use, including 
the expected or estimated range of concentration. If necessary to meet 
an unforeseen production problem, however, a fuel manufacturer may use 
an additive that he has not previously reported provided that (i) the 
additive is on the current list of registered additives and (ii) the 
fuel manufacturer notifies the Administrator within 30 days regarding 
such unforeseen use and his plans regarding continued use, including the 
expected or estimated range of concentration.
    (3) Any designated fuel that is (i) in a research, development, or 
test status; (ii) sold to automobile, engine, or component manufacturers 
for research, development, or test purposes; or (iii) sold to automobile 
manufacturers for factory fill, and is not in any case offered for 
commercial sale to the public, shall be exempt from registration.
    (4) A domestic fuel manufacturer may purchase and offer for 
commercial sale foreign-produced fuel containing unidentified additives 
provided that within 30 days of his offer for sale he notifies the 
Administrator of the purchase, the source of purchase, the quantity 
purchased, and summarized results of any tests performed to determine 
the acceptability of the purchased fuel to the fuel manufacturer.
    (b) Additives. (1) No manufacturer of any fuel additive designated 
under this part shall, after the date by which the additive must be 
registered under this part, sell, offer for sale, or introduce into 
commerce such additive for use in any type of fuel designated under this 
part unless the Administrator has registered that additive for use in 
that type of fuel.
    (2) Any designated additive that is either (i) in a research, 
development, or test status or (ii) sold to petroleum, automobile, 
engine, or component manufacturers for research, development, or test 
purposes, and in either case is not offered for commercial sale to the 
public, shall be exempt from registration.
    (3) Process chemicals used by refineries during the refinery process 
are exempted from the requirement for registration.
    (4) If an additive manufacturer prepares for sale only to fuel 
manufacturers (i) a blend or mixture of two or more registered additives 
or (ii) a blend or mixture of one or more registered additives with one 
or more substances containing only carbon and/or hydrogen, he will not 
be required to register such blend or mixture provided he will, upon 
request, furnish the Administrator with the names and percentages by 
weight of all components of such blend or mixture.

[40 FR 52011, Nov. 7, 1975, as amended at 41 FR 21324, May 25, 1976; 59 
FR 33092, June 27, 1994]



Sec. 79.5   Periodic reporting requirements.

    (a) Fuel manufacturers. (1) For each calendar quarter (January 
through March, April through June, July through September, October 
through December) commencing after the date prescribed for a particular 
fuel in subpart D, fuel manufacturers shall submit to the Administrator 
a report for each registered fuel showing (i) the range of concentration 
of each additive reported under Sec. 79.11(a) and (ii) the volume of 
such fuel produced in the quarter. Reports shall be submitted within 45 
days after the close of the reporting period on forms supplied by the 
Administrator upon request.
    (2) Fuel manufacturers shall submit to the Administrator a report 
annually

[[Page 383]]

for each registered fuel providing additional data and information as 
specified in Sec. 79.31(c) and (d) in the designation of the fuel in 
subpart D. Reports shall be submitted on or before March 31 for the 
preceding year or part thereof on forms supplied by the Administrator 
upon request. If the date prescribed for a particular fuel in subpart D 
or the later registration of a fuel is between October 1 and December 
31, no report will be required for the period to the end of that year.
    (b) Additive manufacturers. Additive manufacturers shall submit to 
the Administrator a report annually for each registered additive 
providing additional data and information as specified in paragraphs (c) 
and (d) in the designation of the additive in subpart D. Additive 
manufacturers shall also report annually the volume of each additive 
produced. Reports shall be submitted on or before March 31 for the 
preceding year or part thereof on forms supplied by the Administrator 
upon request. If the date prescribed for a particular additive in 
subpart D or the later registration of an additive is between October 1 
and December 31, no report will be required for the period to the end of 
that year. These periodic reports shall not, however, be required for 
any additive that is:
    (1) An additive registered under another name,
    (2) A blend or mixture of two or more registered additives, or
    (3) A blend or mixture of one or more registered additives with one 
or more substances containing only carbon and/or hydrogen.



Sec. 79.6  Requirement for testing.

    Provisions regarding testing that is required for registration of a 
designated fuel or fuel additive are contained in subpart F of this 
part.

[59 FR 33092, June 27, 1994]



Sec. 79.7   Samples for test purposes.

    When the Administrator requires for test purposes a fuel or additive 
which is not readily available in the open market, he may request the 
manufacturer of such fuel or additive to furnish a sample in a 
reasonable quantity. The fuel or additive manufacturer shall comply with 
such request within 30 days.



Sec. 79.8   Penalties.

    Any person who violates section 211(a) of the Act or who fails to 
furnish any information or conduct any tests required under this part 
shall be liable to the United States for a civil penalty of not more 
than the sum of $25,000 for every day of such violation and the amount 
of economic benefit or savings resulting from the violation. Civil 
penalties shall be assessed in accordance with paragraphs (b) and (c) of 
section 205 of the Act.

[58 FR 65554, Dec. 15, 1993]



                 Subpart B--Fuel Registration Procedures



Sec. 79.10  Application for registration by fuel manufacturer.

    Any manufacturer of a designated fuel who wishes to register that 
fuel shall submit an application for registration including all of the 
information set forth in Sec. 79.11. If the manufacturer produces more 
than one grade or brand of a designated fuel, a manufacturer may include 
more than one grade or brand in a single application, provided that the 
application includes all information required for registration of each 
such grade or brand by this part. Each application shall be signed by 
the fuel manufacturer and shall be submitted on such forms as the 
Administrator will supply on request.

[59 FR 33092, June 27, 1994]



Sec. 79.11   Information and assurances to be provided by the fuel manufacturer.

    Each application for registration submitted by the manufacturer of a 
designated fuel shall include the following:
    (a) The commercial identifying name of each additive that will or 
may be used in a designated fuel subsequent to the date prescribed for 
such fuel in subpart D;
    (b) The name of the additive manufacturer of each additive named;
    (c) The range of concentration of each additive named, as follows:

[[Page 384]]

    (1) In the case of an additive which has been or is being used in 
the designated fuel, the range during any 3-month or longer period prior 
to the date of submission;
    (2) In the case of an additive which has not been used in the 
designated fuel, the expected or estimated range;
    (d) The purpose-in-use of each additive named;
    (e) The description (or identification, in the case of a generally 
accepted method) of a suitable analytical technique (if one is known) 
that can be used to detect the presence of each named additive in the 
designated fuel and/or to measure its concentration therein;
    (f) Such other data and information as are specified in the 
designation of the fuel in subpart D;
    (g) Assurances that the fuel manufacturer will notify the 
Administrator in writing and within a reasonable time of any change in:
    (1) The name of any additive previously reported;
    (2) The name of the manufacturer of any additive being used;
    (3) The purpose-in-use of any additive;
    (4) Information submitted pursuant to paragraph (e) of this section;
    (h) Assurances that the fuel manufacturer will not represent, 
directly or indirectly, in any notice, circular, letter, or other 
written communication, or any written, oral, or pictorial notice or 
other announcement in any publication or by radio or television, that 
registration of the fuel constitutes endorsement, certification, or 
approval by any agency of the United States;
    (i) The manufacturer of any fuel which will be sold, offered for 
sale, or introduced into commerce for use in motor vehicles manufactured 
after model year 1974 shall demonstrate that the fuel is substantially 
similar to any fuel utilized in the certification of any 1975 or 
subsequent model year vehicle or engine, or that the manufacturer has 
obtained a waiver under 42 U.S.C. 7545(f)(4); and
    (j) The manufacturer shall submit, or shall reference prior 
submissions, including all of the test data and other information 
required prior to registration of the fuel by the provisions of subpart 
F of this part.

[40 FR 52011, Nov. 7, 1975, as amended at 59 FR 33092, June 27, 1994]



Sec. 79.12  Determination of noncompliance.

    If the Administrator determines that an applicant for registration 
of a designated fuel has failed to submit all of the information 
required by Sec. 79.11, or determines within the applicable period 
provided for Agency review that the applicant has not satisfactorily 
completed any testing which is required prior to registration of the 
fuel by any provision of subpart F of this part, he shall return the 
application to the manufacturer, along with an explanation of all 
deficiencies in the required information.

[59 FR 33093, June 27, 1994]



Sec. 79.13   Registration.

    (a) If the Administrator determines that a manufacturer has 
submitted an application for registration of a designated fuel which 
includes all of the information and assurances required by Sec. 79.11 
and has satisfactorily completed all of the testing required by subpart 
F of this part, the Administrator shall promptly register the fuel and 
notify the fuel manufacturer of such registration.
    (b) The Administrator shall maintain a list of registered fuels, 
which shall be available to the public upon request.

[40 FR 52011, Nov. 7, 1975, as amended at 41 FR 21324, May 25, 1976; 59 
FR 33093, June 27, 1994]



Sec. 79.14   Termination of registration of fuels.

    Registration may be terminated by the Administrator if the fuel 
manufacturer requests such termination in writing.



               Subpart C--Additive Registration Procedures



Sec. 79.20  Application for registration by additive manufacturer.

    Any manufacturer of a designated fuel additive who wishes to 
register that additive shall submit an application for registration 
including all of

[[Page 385]]

the information set forth in Sec. 79.21. Each application shall be 
signed by the fuel additive manufacturer and shall be submitted on such 
forms as the Administrator will supply on request.

[59 FR 33093, June 27, 1994]



Sec. 79.21   Information and assurances to be provided by the additive manufacturer.

    Each application for registration submitted by the manufacturer of a 
designated fuel additive shall include the following:
    (a) The chemical composition of the additive with the methods of 
analysis identified, except that
    (1) If the chemical composition is not known, full disclosure of the 
chemical process of manufacture will be accepted in lieu thereof;
    (2) In the case of an additive for engine oil, only the name, 
percentage by weight, and method of analysis of each element in the 
additive are required provided, however, that a percentage figure 
combining the percentages of carbon, hydrogen, and/or oxygen may be 
provided unless the breakdown into percentages for these individual 
elements is already known to the registrant.
    (3) In the case of a purchased component, only the name, 
manufacturer, and percent by weight of such purchased component are 
required if the manufacturer of the component will, upon request, 
furnish the Administrator with the chemical composition thereof.
    (b) The chemical structure of each compound in the additive if such 
structure is known and is not adequately specified by the name given 
under ``chemical composition.'' Nominal identification is adequate if 
mixed isomers are present.
    (c) The description (or identification, in the case of a generally 
accepted method) of a suitable analytical technique (if one is known) 
that can be used to detect the presence of the additive in any fuel 
named in the designation and/or to measure its concentration therein.
    (d) The specific types of fuels designated under Sec. 79.32 for 
which the fuel additive will be sold, offered for sale, or introduced 
into commerce, and the fuel additive manufacturer's recommended range of 
concentration and purpose-in-use for each such type of fuel.
    (e) Such other data and information as are specified in the 
designation of the additive in subpart D.
    (f) Assurances that any change in information submitted pursuant to 
(1) paragraphs (a), (b), (c), and (d) of this section will be provided 
to the Administrator in writing within 30 days of such change; and (2) 
paragraph (e) of this section as provided in Sec. 79.5(b).
    (g) Assurances that the additive manufacturer will not represent, 
directly or indirectly, in any notice, circular, letter, or other 
written communication or any written, oral, or pictorial notice or other 
announcement in any publication or by radio or television, that 
registration of the additive constitutes endorsement, certification, or 
approval by any agency of the United States.
    (h) The manufacturer of any fuel additive which will be sold, 
offered for sale, or introduced into commerce for use in any type of 
fuel intended for use in motor vehicles manufactured after model year 
1974 shall demonstrate that the fuel additive, when used at the 
recommended range of concentration, is substantially similar to any fuel 
additive included in a fuel utilized in the certification of any 1975 or 
subsequent model year vehicle or engine, or that the manufacturer has 
obtained a waiver under 42 U.S.C. 7545(f)(4).
    (i) The manufacturer shall submit, or shall reference prior 
submissions, including all of the test data and other information 
required prior to registration of the fuel additive by the provisions of 
subpart F of this part.

[40 FR 52011, Nov. 7, 1975, as amended at 41 FR 21324, May 25, 1976; 59 
FR 33093, June 27, 1994]



Sec. 79.22  Determination of noncompliance.

    If the Administrator determines that an applicant for registration 
of a designated fuel additive has failed to submit all of the 
information required by Sec. 79.21, or determines within the applicable 
period provided for Agency review that the applicant has not 
satisfactorily completed any testing which is required prior to 
registration of the

[[Page 386]]

fuel additive by any provision of subpart F of this part, he shall 
return the application to the manufacturer, along with an explanation of 
all deficiencies in the required information.

[59 FR 33093, June 27, 1994]



Sec. 79.23   Registration.

    (a) If the Administrator determines that a manufacturer has 
submitted an application for registration of a designated fuel additive 
which includes all of the information and assurances required by 
Sec. 79.21 and has satisfactorily completed all of the testing required 
by subpart F of this part, the Administrator shall promptly register the 
fuel additive and notify the fuel manufacturer of such registration.
    (b) The Administrator shall maintain a list of registered additives, 
which shall be available to the public upon request.

[40 FR 52011, Nov. 7, 1975, as amended at 41 FR 21324, May 25, 1976; 59 
FR 33093, June 27, 1994]



Sec. 79.24   Termination of registration of additives.

    Registration may be terminated by the Administrator if the additive 
manufacturer requests such termination in writing.



              Subpart D--Designation of Fuels and Additives



Sec. 79.30   Scope.

    Fuels and additives designated and dates prescribed by the 
Administrator for the registration of such fuels and additives, pursuant 
to section 211 of the Act, are listed in this subpart. In addition, 
specific informational requirements under Secs. 79.11(f) and 79.21(e) 
are set forth for each designated fuel or additive. Additional fuels 
and/or additives may be designated and pertinent dates and additional 
specific informational requirements prescribed as the Administrator 
deems advisable.



Sec. 79.31   Additives.

    (a) All additives produced or sold for use in motor vehicle gasoline 
and/or motor vehicle diesel fuel are hereby designated. The Act defines 
the term ``motor vehicle'' to mean any self-propelled vehicle designed 
for transporting persons or property on a street or highway. For 
purposes of this registration, however, additives specifically 
manufactured and marketed for use in motorcycle fuels are excluded.
    (b) All designated additives must be registered by July 7, 1976.
    (c) In accordance with Secs. 79.5(b) and 79.21(e), and to the extent 
such information is known to the additive manufacturer as a result of 
testing conducted for reasons other than additive registration or 
reporting purposes, the additive manufacturer shall furnish the highest, 
lowest, and average values of the impurities in each designated 
additive, if greater than 0.1 percent by weight. The methods of analysis 
in making the determinations shall also be given.
    (d) In accordance with Secs. 79.5(b) and 79.21(e), and to the extent 
such information is known to the additive manufacturer, he shall furnish 
summaries of any information developed by or specifically for him 
concerning the following items:
    (1) Mechanisms of action of the additive;
    (2) Reactions between the additive and the fuels listed in paragraph 
(a) of this section;
    (3) Identification and measurement of the emission products of the 
additive when used in the fuels listed in paragraph (a) of this section;
    (4) Effects of the additive on all emissions;
    (5) Toxicity and any other public health or welfare effects of the 
emission products of the additive;
    (6) Effects of the emission products of the additive on the 
performance of emission control devices/systems. Such submissions shall 
be accompanied by a description of the test procedures used in obtaining 
the information. Information will be considered to be known to the 
additive manufacturer if a report thereon has been prepared and 
circulated or distributed outside the research department or division.

(Secs. 211, 301(a), Clean Air Act as amended (40 U.S.C. 7545, 7601(a)))

[40 FR 52011, Nov. 7, 1975, as amended at 41 FR 21324, May 25, 1976; 43 
FR 28490, June 30, 1978; 59 FR 33093, June 27, 1994]

[[Page 387]]



Sec. 79.32   Motor vehicle gasoline.

    (a) The following fuels commonly or commercially known or sold as 
motor vehicle gasoline are hereby individually designated:
    (1) Motor vehicle gasoline, unleaded--motor vehicle gasoline that 
contains no more than 0.05 gram of lead per gallon;
    (2) Motor vehicle gasoline, leaded, premium--motor vehicle gasoline 
that contains more than 0.05 gram of lead per gallon and is sold as 
``premium;''
    (3) Motor vehicle gasoline, leaded, non-premium--motor vehicle 
gasoline that contains more than 0.05 gram of lead per gallon but is not 
sold as ``premium.''

The Act defines the term ``motor vehicle'' to mean any self-propelled 
vehicle designed for transporting persons or property on a street or 
highway. For purposes of this registration, however, gasoline 
specifically blended and marketed for motorcycles is excluded.
    (b) All designated motor vehicle gasolines must be registered by 
September 7, 1976.
    (c) In accordance with Secs. 79.5(a)(2) and 79.11(f), and to the 
extent such information is known to the fuel manufacturer as a result of 
testing conducted for reasons other than fuel registration or reporting 
purposes, the fuel manufacturer shall furnish the data listed below. The 
highest, lowest, and average values of the listed characteristics/
properties are to be reported. For initial registration, data shall be 
given for any 3-month or longer period prior to the date of submission. 
For annual reports thereafter, data shall be for the calendar year, 
except that if the first required annual report covers a period of less 
than a year, the data may be for such shorter period.
    (1) Hydrocarbon composition (aromatic content, olefin content, 
saturate content), with the methods of analysis identified;
    (2) Polynuclear organic material content, sulfur content, and trace 
element content, with the methods of analysis identified;
    (3) Reid vapor pressure;
    (4) Distillation temperatures (10 percent point, end point);
    (5) Research octane number and motor octane number.
    (d) In accordance with Secs. 79.5(a)(2) and 79.11(f), and to the 
extent such information is known to the fuel manufacturer, he shall 
furnish summaries of any information developed by or specifically for 
him concerning the following items:
    (1) Mechanisms of action of each additive he reports;
    (2) Reactions between such additives and motor vehicle gasoline;
    (3) Identification and measurement of the emission products of such 
additives when used in motor vehicle gasoline;
    (4) Effects of such additives on all emissions;
    (5) Toxicity and any other public health or welfare effects of the 
emission products of such additives;
    (6) Effects of the emission products of such additives on the 
performance of emission control devices/systems. Such submissions shall 
be accompanied by a description of the test procedures used in obtaining 
the information. Information will be considered to be known to the fuel 
manufacturer if a report thereon has been prepared and circulated or 
distributed outside the research department or division.

[40 FR 52011, Nov. 7, 1975, as amended at 41 FR 21324, May 25, 1976]



Sec. 79.33   Motor vehicle diesel fuel.

    (a) The following fuels commonly or commercially known or sold as 
motor vehicle diesel fuel are hereby individually designated:
    (1) Motor vehicle diesel fuel, grade 1-D;
    (2) Motor vehicle diesel fuel, grade 2-D.

The Act defines the term ``motor vehicle'' to mean any self-propelled 
vehicle designed for transporting persons or property on a street or 
highway.
    (b) All designated motor vehicle diesel fuels must be registered 
within 12 months after promulgation of this part.
    (c) In accordance with Secs. 79.5(a)(2) and 79.11(f), and to the 
extent such information is known to the fuel manufacturer

[[Page 388]]

as a result of testing conducted for reasons other than fuel 
registration or reporting purposes, the fuel manufacturer shall furnish 
the data listed below. The highest, lowest, and average values of the 
listed characteristics/properties are to be reported. For initial 
registration, data shall be given for any 3-month or longer period prior 
to the date of submission. For annual reports thereafter, data shall be 
for the calendar year, except that if the first required annual report 
covers a period of less than a year, the data may be for such shorter 
period.
    (1) Hydrocarbon composition (aromatic content, olefin content, 
saturate content), with the methods of analysis identified;
    (2) Polynuclear organic material content, sulfur content, and trace 
element content, with the methods of analysis identified;
    (3) Distillation temperatures (90 percent point, end point);
    (4) Cetane number or cetane index;
    (d) In accordance with Secs. 79.5(a)(2) and 79.11(f), and to the 
extent such information is known to the fuel manufacturer, he shall 
furnish summaries of any information developed by or specifically for 
him concerning the following items:
    (1) Mechanisms of action of each additive he reports;
    (2) Reactions between such additives and motor vehicle diesel fuel;
    (3) Identification and measurement of the emission products of such 
additives when used in motor vehicle diesel fuel;
    (4) Effects of such additives on all emissions;
    (5) Toxicity and any other public health or welfare effects of the 
emission products of such additives.

Such submission shall be accompanied by a description of the test 
procedures used in obtaining the information. Information will be 
considered to be known to the fuel manufacturer if a report thereon has 
been prepared and circulated or distributed outside the research 
department or division.



                          Subpart E--[Reserved]



            Subpart F--Testing Requirements for Registration

    Source: 59 FR 33093, June 27, 1994, unless otherwise noted.



Sec. 79.50  Definitions.

    The definitions listed in this section apply only to subpart F of 
this part.
    Additive/base fuel mixture means the mixture resulting when a fuel 
additive is added in specified proportion to the base fuel of the fuel 
family to which the additive belongs.
    Aerosol additive means a chemical mixture in aerosol form generally 
used as a motor vehicle engine starting aid or carburetor cleaner and 
not recommended to be placed in the fuel tank.
    Aftermarket fuel additive means a product which is added by the end-
user directly to fuel in a motor vehicle or engine to modify the 
performance or other characteristics of the fuel, the engine, or its 
emissions.
    Atypical element means any chemical element found in a fuel or 
additive product which is not allowed in the baseline category of the 
associated fuel family, and an ``atypical fuel or fuel additive'' is a 
product which contains such an atypical element.
    Base fuel means a generic fuel formulated from a set of 
specifications to be representative of a particular fuel family.
    Basic emissions means the total hydrocarbons, carbon monoxide, 
oxides of nitrogen, and particulates occurring in motor vehicle or 
engine emissions.
    Bulk fuel additive means a product which is added to fuel at the 
refinery as part of the original blending stream or after the fuel is 
transported from the refinery but before the fuel is purchased for 
introduction into the fuel tank of a motor vehicle.
    Emission characterization means the determination of the chemical 
composition of emissions.
    Emission generation means the operation of a vehicle or engine or 
the vaporization of a fuel or additive/fuel mixture under controlled 
conditions

[[Page 389]]

for the purpose of creating emissions to be used for testing purposes.
    Emission sampling means the removal of a fraction of collected 
emissions for testing purposes.
    Emission speciation means the analysis of vehicle or engine 
emissions to determine the individual chemical compounds which comprise 
those emissions.
    Engine Dynamometer Schedule (EDS) means the transient engine speed 
versus torque time sequence commonly used in heavy-duty engine 
evaluation. The EDS for heavy-duty diesel engines is specified in 40 CFR 
part 86, appendix I(f)(2).
    Evaporative Emission Generator (EEG) means a fuel tank or vessel to 
which heat is applied to cause a portion of the fuel to evaporate at a 
desired rate.
    Evaporative emissions means chemical compounds emitted into the 
atmosphere by vaporization of contents of a fuel or additive/fuel 
mixture.
    Evaporative fuel means a fuel which has a Reid Vapor Pressure (RVP, 
pursuant to 40 CFR part 80, appendix ``E'') of 2.0 pounds per square 
inch or greater and is not supplied to motor vehicle engines by way of 
sealed containment and delivery systems.
    Evaporative fuel additive means a fuel additive which, when mixed 
with its specified base fuel, causes an increase in the RVP of the base 
fuel by 0.4 psi or more relative to the RVP of the base fuel alone and 
results in an additive/base fuel mixture whose RVP is 2.0 psi, or 
greater. Excluded from this definition are fuel additives used with 
fuels which are supplied to motor vehicle engines by way of sealed 
containment and delivery systems.
    Federal Test Procedure (FTP) means the body of exhaust and 
evaporative emissions test procedures described in 40 CFR 86 for the 
certification of new motor vehicles to Federal motor vehicle emissions 
standards.
    Fuel family means a set of fuels and fuel additives which share 
basic chemical and physical formulation characteristics and can be used 
in the same engine or vehicle.
    Manufacturer means a person who is a fuel manufacturer or additive 
manufacturer as defined in Sec. 79.2 (d) and (f).
    Nitrated polycyclic aromatic hydrocarbons (NPAH) means the class of 
compounds whose molecular structure includes two or more aromatic rings 
and contains one or more nitrogen substitutions.
    Non-catalyzed emissions means exhaust emissions not subject to an 
effective aftertreatment device such as a functional catalyst or 
particulate trap.
    Oxygenate compound means an oxygen-containing, ashless organic 
compound, such as an alcohol or ether, which may be used as a fuel or 
fuel additive.
    Polycyclic aromatic hydrocarbons (PAH) means the class of 
hydrocarbon compounds whose molecular structure includes two or more 
aromatic rings.
    Relabeled additive means a fuel additive which is registered by its 
original manufacturer with EPA and is also registered and sold, 
unchanged in composition, under a different label and/or by a different 
entity.
    Semi-volatile organic compounds means that fraction of gaseous 
combustion emissions which consists of compounds with greater than 
twelve carbon atoms and can be trapped in sorbent polymer resins.
    Urban Dynamometer Driving Schedule (UDDS) means the 1372 second 
transient speed driving sequence used by EPA to simulate typical urban 
driving. The UDDS for light-duty vehicles is described in 40 CFR part 
86, appendix I(a).
    Vapor phase means the gaseous fraction of combustion emissions.
    Vehicle classes/subclasses means the divisions of vehicle groups 
within a vehicle type, including light-duty vehicles, light-duty trucks, 
and heavy-duty vehicles as specified in 40 CFR part 86.
    Vehicle type means the divisions of motor vehicles according to 
combustion cycle and intended fuel class, including, but not necessarily 
limited to, Otto cycle gasoline-fueled vehicles, Otto cycle methanol-
fueled vehicles, diesel cycle diesel-fueled vehicles, and diesel cycle 
methanol-fueled vehicles.
    Whole emissions means all components of unfiltered combustion 
emissions or evaporative emissions.

[[Page 390]]



Sec. 79.51  General requirements and provisions.

    (a) Overview of requirements. (1) All manufacturers of fuels and 
fuel additives that are designated for registration under this part are 
required to comply with the requirements of subpart F of this part 
either on an individual basis or as a participant in a group of 
manufacturers of the same or similar fuels and fuel additives, as 
defined in Sec. 79.56. If manufacturers elect to comply by participation 
in a group, each manufacturer continues to be individually subject to 
the requirements of subpart F of this part, and responsible for testing 
under this subpart. Each manufacturer, subject to the provisions for 
group applications in Sec. 79.51(b) and the special provisions in 
Sec. 79.58, shall submit all Tier 1 and Tier 2 information required by 
Secs. 79.52, 79.53 and 79.59 for each fuel or additive, except that the 
Tier 1 emission characterization requirements in Sec. 79.52(b) and/or 
the Tier 2 testing requirements in Sec. 79.53 may be satisfied by 
adequate existing information pursuant to the Tier 1 literature search 
requirements in Sec. 79.52(d). The adequacy of existing information to 
serve in compliance with specific Tier 1 and/or Tier 2 requirements 
shall be determined according to the criteria and procedures specified 
in Secs. 79.52(b) and 79.53 (c) and (d). In all cases, EPA reserves the 
right to require, based upon the information contained in the 
application or any other information available to the Agency, that 
manufacturers conduct additional testing of any fuel or additive (or 
fuel/additive group) if EPA determines that there is inadequate 
information upon which to base regulatory decisions for such product(s). 
In any case where EPA determines that the requirements of Tiers 1 and 2 
have been satisfied but that further testing is required, the provisions 
of Tier 3 (Sec. 79.54) shall apply.
    (2) Laboratory facilities shall perform testing in compliance with 
Good Laboratory Practice (GLP) requirements as those requirements apply 
to inhalation toxicology studies. All studies shall be monitored by the 
facilities' Quality Assurance units (as specified in Sec. 79.60).
    (b) Group Applications. Subject to the provisions of Sec. 79.56 (a) 
through (c), EPA will consider any testing requirements of this subpart 
to have been met for any fuel or fuel additive when a fuel or fuel 
additive which meets the criteria for inclusion in the same group as the 
subject fuel or fuel additive has met that testing requirement, provided 
that all fuels and additives must be individually registered as 
described in Sec. 79.59(b). For purposes of this subpart, a 
determination of which group contains a particular fuel or additive will 
be made pursuant to the provisions of Sec. 79.56 (d) and (e). Nothing in 
this subsection (b) shall be deemed to require a manufacturer to rely on 
another manufacturer's testing.
    (c) Application Procedures and Dates. Each application submitted in 
compliance with this subpart shall be signed by the manufacturer of the 
designated fuel or additive, or by the manufacturer's agent, and shall 
be submitted to the address and in the format prescribed in Sec. 79.59. 
A manufacturer who chooses to comply as part of a group pursuant to 
Sec. 79.56 shall be covered by the group's joint application. Subject to 
any modifications pursuant to the special provisions in Secs. 79.51(f) 
or 79.58, the schedule for compliance with the requirements of this 
subpart is as follows:
    (1) Fuels and fuel additives with existing registrations. (i) The 
manufacturer of a fuel or fuel additive product which, pursuant to 
subpart B or C of this part, is registered as of May 27, 1994 must 
submit the additional basic registration data specified in Sec. 79.59(b) 
before November 28, 1994.
    (ii) For these products, the manufacturer must also satisfy the 
requirements and time schedules in either of the following paragraphs 
(c)(1)(ii) (A) or (B) of this section:
    (A) Within May 27, 1997, all applicable Tier 1 and Tier 2 
requirements must be submitted to EPA, pursuant to Secs. 79.52, 79.53, 
and 79.59; or
    (B) Within May 27, 1997, all applicable Tier 1 requirements 
(pursuant to Secs. 79.52 and 79.59), plus evidence of a contract with a 
qualified laboratory (or other suitable arrangement) for completion of 
all applicable Tier 2 requirements, must be submitted to EPA. For

[[Page 391]]

this purpose, a qualified laboratory is one which can demonstrate the 
capabilities and credentials specified in Sec. 79.53(c)(1). In addition, 
within May 26, 2000, all applicable Tier 2 requirements (pursuant to 
Secs. 79.53 and 79.59) must be submitted to EPA.
    (iii) In the case of such fuels and fuel additives which, pursuant 
to applicable special provisions in Sec. 79.58, are not subject to Tier 
2 requirements, all other requirements (except Tier 3) must be submitted 
to EPA before May 27, 1997.
    (iv) In the event that Tier 3 testing is also required (under 
Sec. 79.54), EPA shall determine an appropriate timeline for completion 
of the additional requirements and shall communicate this schedule to 
the manufacturer according to the provisions of Sec. 79.54(b).
    (v) The manufacturer may at any time modify an existing fuel 
registration by submitting a request to EPA to add or delete a bulk 
additive to the existing registration information for such fuel product, 
provided that any additional additive must be registered by EPA for use 
in the specific fuel family to which the fuel product belongs. However, 
the addition or deletion of a bulk additive to a fuel registration may 
effect the grouping of such registered fuel under the criteria of 
Sec. 79.56, and thus may effect the testing responsibilities of the fuel 
manufacturer under this subpart.
    (2) Registrable fuels and fuel additives. (i) A fuel product which 
is not registered pursuant to subpart B of this part as of May 27, 1994 
shall be considered registrable if, under the criteria established by 
Sec. 79.56, the fuel can be enrolled in the same fuel/additive group 
with one or more currently registered fuels. A fuel additive product 
which is not registered for a specific type of fuel pursuant to subpart 
C of this part as of May 27, 1994 shall be considered registrable for 
that type of fuel if, under the criteria established by Sec. 79.56, the 
fuel/additive mixture resulting from use of the additive product in the 
specific type of fuel can be enrolled in the same fuel/additive group 
with one or more currently registered fuels or bulk fuel additives. For 
the purpose of this determination, currently registered fuels and bulk 
additives are those with existing registrations as of the date on which 
EPA receives the basic registration data (pursuant to Sec. 79.59(b)) for 
the product in question.
    (ii) A manufacturer seeking to register under subpart B of this part 
a fuel product which is deemed registrable under this section, or to 
register under subpart C of this part a fuel additive product for a 
specific type of fuel for which it is deemed registrable under this 
section, shall submit the basic registration data (pursuant to 
Sec. 79.59(b)) for that product as part of the application for 
registration. If the Administrator determines that the product is 
registrable under this section, then the Administrator shall promptly 
register the product, provided that the applicant has satisfied all of 
the other requirements for registration under subpart B or subpart C of 
this part, and contingent upon satisfactory submission of required 
information under paragraph (c)(2)(iii) of this section.
    (iii) Registration of a registrable fuel or additive shall be 
subject to the same requirements and compliance schedule as specified in 
paragraph (c)(1) of this section for existing fuels and fuel additives. 
Accordingly, manufacturers of registrable fuels or additives may be 
granted and may retain registration for such products only if any 
applicable and due Tier 1, 2, and 3 requirements have also been 
satisfied by either the manufacturer of the product or the fuel/additive 
group to which the product belongs.
    (3) New fuels and fuel additives. A fuel product shall be considered 
new if it is not registered pursuant to subpart B of this part as of May 
27, 1994 and if, under the criteria established by Sec. 79.56, it cannot 
be enrolled in the same fuel/additive group with one or more currently 
registered fuels. A fuel additive product shall be considered new with 
respect to a specific type of fuel if it is not expressly registered for 
that type of fuel pursuant to subpart C of this part as of May 27, 1994 
and if, under the criteria established by Sec. 79.56, the fuel/additive 
mixture resulting from use of the additive product in the specific type 
of fuel cannot be enrolled in the same fuel/additive group with one or 
more currently registered fuels or bulk fuel additives. For the purpose 
of this

[[Page 392]]

determination, currently registered fuels and bulk additives are those 
with existing registrations as of the date on which EPA receives the 
basic registration data (pursuant to Sec. 79.59(b)) for the product in 
question. For such new product, the manufacturer must satisfactorily 
complete all applicable Tier 1 and Tier 2 requirements, followed by any 
Tier 3 testing which the Administrator may require, before registration 
will be granted.
    (d) Notifications. Upon receipt of a manufacturer's (or group's) 
submittal in compliance with the requirements of this subpart, EPA will 
notify such manufacturer (or group) that the application has been 
received and what, if any, information, testing, or retesting is 
necessary to bring the application into compliance with the requirements 
of this subpart. EPA intends to provide such notification of receipt in 
a timely manner for each such application.
    (1) Registered fuel and fuel additive notification. (i) The 
manufacturer of a registered fuel or fuel additive product who is 
notified that the submittal for such product contains adequate 
information pursuant to the Tier 1 and Tier 2 testing and reporting 
requirements (Secs. 79.52, 79.53, and 79.59 (a) through (c)) may 
continue to sell, offer for sale, or introduce into commerce the 
registered product as permitted by the existing registration for the 
product under Sec. 79.4.
    (ii) If the manufacturer of a registered fuel or fuel additive 
product is notified that testing or retesting is necessary to bring the 
Tier 1 and/or Tier 2 submittal into compliance, the continued sale or 
importation of the product shall be conditional upon satisfactorily 
completing the requirements within the time frame specified in paragraph 
(c)(1) of this section.
    (iii) EPA intends to notify the manufacturer of the adequacy of the 
submitted data within two years of EPA's receipt of such data. However, 
EPA retains the right to require that adequate data be submitted to EPA 
if, upon subsequent review, EPA finds that the original Tier 1 and/or 
Tier 2 submittal is not consistent with the requirements of this 
subpart. If EPA does not notify the manufacturer of the adequacy of the 
Tier 1 and/or Tier 2 data within two years, EPA will not hold the 
manufacturer liable for penalties for violating this rule for the period 
beginning when the data was due until the time EPA notifies the 
manufacturer of the violation.
    (iv) If the manufacturer of a registered fuel or fuel additive 
product is notified (pursuant to Sec. 79.54(b)) that Tier 3 testing is 
required for its product, then the manufacturer may continue to sell, 
offer for sale, introduce into commerce the registered product as 
permitted by the existing registration for the product under Sec. 79.4. 
However, if the manufacturer fails to complete the specified Tier 3 
requirements within the specified time, the registration of the product 
will be subject to cancellation under Sec. 79.51(f)(6).
    (v) EPA retains the right to require additional Tier 3 testing 
pursuant to the procedures in Sec. 79.54.
    (2) New fuel and fuel additive notification. (i) Within six months 
following its receipt of the Tier 1 and Tier 2 submittal for a new 
product (as defined in paragraph (c)(3) of this section), EPA shall 
notify the manufacturer of the adequacy of such submittal in compliance 
with the requirements of Secs. 79.52, 79.53, and 79.59 (a) through (c).
    (A) If EPA notifies the manufacturer that testing, retesting, or 
additional information is necessary to bring the Tier 1 and Tier 2 
submittal into compliance, the manufacturer shall remedy all 
inadequacies and provide Tier 3 data, if required, before EPA shall 
consider the requirements for registration to have been met for the 
product in question.
    (B) If EPA does not notify the manufacturer of the adequacy of the 
Tier 1 and Tier 2 submittal within six months following the submittal, 
the manufacturer shall be deemed to have satisfactorily completed Tiers 
1 and 2.
    (ii) Within six months of the date on which EPA notifies the 
manufacturer of satisfactory completion of Tiers 1 and 2 for a new 
product, or within one year of the submittal of the Tier 1 and Tier 2 
data (whichever is earlier), EPA shall determine whether additional 
testing is currently needed under the provisions of Tier 3 and, pursuant 
to Sec. 79.54(b), shall notify the manufacturer of its determination.

[[Page 393]]

    (A) If the manufacturer of a new fuel or fuel additive product is 
notified that Tier 3 testing is required for such product, then EPA 
shall have the authority to withhold registration until the specified 
Tier 3 requirements have been satisfactorily completed. EPA shall 
determine whether the Tier 3 requirements have been met, and shall 
notify the manufacturer of this determination, within one year of 
receiving the manufacturer's Tier 3 submittal.
    (B) If EPA does not notify the manufacturer of potential Tier 3 
requirements within the prescribed timeframe, then additional testing at 
the Tier 3 level is deemed currently unnecessary and the manufacturer 
shall be considered to have complied with all current registration 
requirements for the new fuel or additive product.
    (iii) Upon completion of all current Tier 1, Tier 2, and Tier 3 
requirements, and submission of an application for registration which 
includes all of the information and assurances required by Sec. 79.11 or 
Sec. 79.21, the registration of the new fuel or additive shall be 
granted, and the registrant may then sell, offer for sale, or introduce 
into commerce the registered product as permitted by Sec. 79.4.
    (iv) Once the new product becomes registered, EPA reserves the right 
to require additional Tier 3 testing pursuant to the procedures 
specified in Sec. 79.54.
    (e) Inspection of a testing facility. (1) A testing facility, 
emissions analysis or health and/or welfare effects, shall permit an 
authorized employee or duly designated representative of EPA, at 
reasonable times and in a reasonable manner, to inspect the facility and 
to inspect (and in the case of records also to copy) all records and 
specimens required to be maintained regarding studies to which this rule 
applies. The records inspection and copying requirements shall not apply 
to quality assurance unit records of findings and problems, or to 
actions recommended and taken, except the EPA may seek production of 
these records in litigation or informal hearings.
    (2) EPA will not consider reliable for purposes of showing that a 
test substance does or does not present a risk of injury to health or 
the environment any data developed by a testing facility or sponsor that 
refuses to permit inspection in accordance with this section. The 
determination that a study will not be considered reliable does not, 
however, relieve the sponsor of a required test of any obligation under 
any applicable statute or regulation to submit the results of the study 
to EPA.
    (3) Effects of non-compliance. Pursuant to sections 114, 208, and 
211(d) of the CAA, it shall be a violation of this section and a 
violation of 40 CFR part 79, subpart F to deny entry to an authorized 
employee or duly designated representative of EPA for the purpose of 
auditing a testing facility or test data.
    (f) Penalties and Injunctive Relief. (1) Any person who violates 
these regulations shall be subject to a civil penalty of up to $25,000 
for each and every day of the continuance of the violation and the 
economic benefit or savings resulting from the violation. Action to 
collect such civil penalties shall be commenced in accordance with 
paragraph (b) of section 205 of the Clean Air Act or assessed in 
accordance with paragraph (c) of section 205 of the Clean Air Act, 42 
U.S.C. 7524 (b) and (c).
    (2) Under section 205(b) of the CAA, the Administrator may commence 
a civil action for violation of this subpart in the district court of 
the United States for the district in which the violation is alleged to 
have occurred or in which the defendant resides or has a principal place 
of business.
    (3) Under section 205(c) of the CAA, the Administrator may assess a 
civil penalty of $25,000 for each and every day of the continuance of 
the violation and the economic benefit or savings resulting from the 
violation, except that the maximum penalty assessment shall not exceed 
$200,000, unless the Administrator and the Attorney General jointly 
determine that a matter involving a larger penalty amount is appropriate 
for administrative penalty assessment. Any such determination by the 
Administrator and the Attorney General shall not be subject to judicial 
review.
    (4) The Administrator may, upon application by the person against 
whom any such penalty has been assessed, remit or mitigate, with or 
without conditions, any such penalty.

[[Page 394]]

    (5) The district courts of the United States shall have jurisdiction 
to compel the furnishing of information and the conduct of tests 
required by the Administrator under these regulations and to award other 
appropriate relief. Actions to compel such actions shall be brought by 
and in the name of the United States. In any such action, subpoenas for 
witnesses who are required to attend a district court in any district 
may run into any other district.
    (6) Cancellation.
    (i) The Administrator of EPA may issue a notice of intent to cancel 
a fuel or fuel additive registration if the Administrator determines 
that the registrant has failed to submit in a timely manner any data 
required to maintain registration under this part or under section 
211(b) or 211(e) of the Clean Air Act.
    (ii) Upon issuance of a notice of intent to cancel, EPA will forward 
a copy of the notice to the registrant by certified mail, return receipt 
requested, at the address of record given in the registration, along 
with an explanation of the reasons for the proposed cancellation.
    (iii) The registrant will be afforded 60 days from the date of 
receipt of the notice of intent to cancel to submit written comments 
concerning the notice, and to demonstrate or achieve compliance with the 
specific data requirements which provide the basis for the proposed 
cancellation. If the registrant does not respond in writing within 60 
days from the date of receipt of the notice of intent to cancel, the 
cancellation of the registration shall become final by operation of law 
and the Administrator shall notify the registrant of such cancellation. 
If the registrant responds in writing within 60 days from the date of 
receipt of the notice of intent to cancel, the Administrator shall 
review and consider all comments submitted by the registrant before 
taking final action concerning the proposed cancellation. The 
registrants' communications should be sent to the following address: 
Director, Field Operations and Support Division, 6406J--Fuel/Additives 
Registration, U.S. Environmental Protection Agency, 401 M Street SW., 
Washington, DC 20460.
    (iv) As part of a written response to a notice of intent to cancel, 
a registrant may request an informal hearing concerning the notice. Any 
such request shall state with specificity the information the registrant 
wishes to present at such a hearing. If an informal hearing is 
requested, EPA shall schedule such a hearing within 60 days from the 
date of receipt of the request. If an informal hearing is held, the 
subject matter of the hearing shall be confined solely to whether or not 
the registrant has complied with the specific data requirements which 
provide the basis for the proposed cancellation. If an informal hearing 
is held, the designated presiding officer may be any EPA employee, the 
hearing procedures shall be informal, and the hearing shall not be 
subject to or governed by 40 CFR part 22 or by 5 U.S.C. 554, 556, or 
557. A verbatim transcript of each informal hearing shall be kept and 
the Administrator shall consider all relevant evidence and arguments 
presented at the hearing in making a final decision concerning a 
proposed cancellation.
    (v) If a registrant who has received a notice of intent to cancel 
submits a timely written response, and the Administrator decides after 
reviewing the response and the transcript of any informal hearing to 
cancel the registration, the Administrator shall issue a final 
cancellation order, forward a copy of the cancellation order to the 
registrant by certified mail, and promptly publish the cancellation 
order in the Federal Register. Any cancellation order issued after 
receipt of a timely written response by the registrant shall become 
legally effective five days after it is published in the Federal 
Register.
    (g) Modification of Regulation. (1) In special circumstances, a 
manufacturer subject to the registration requirements of this rule may 
petition the Administrator to modify the mandatory testing requirements 
in the test standard for any test required by this rule by application 
to Director, Field Operations and Support Division, at the address in 
paragraph (f)(6)(iii) of this section.
    (i) Such request shall be made as soon as the test sponsor is aware 
that

[[Page 395]]

the modification is necessary, but in no event shall the request be made 
after 30 days following the event which precipitated the request.
    (ii) Upon such request, the Administrator may, in circumstances 
which are outside the control of the manufacturer(s) or his/their agent 
and which could not have been reasonably foreseen or avoided, modify the 
mandatory testing requirements in the rule if such requirements are 
infeasible.
    (iii) If the Administrator determines that such modifications would 
not significantly alter the scope of the test, EPA will not ask for 
public comment before approving the modification. The Administrator will 
notify the test sponsor by certified mail of the response to the 
request. EPA will place copies of each application and EPA response in 
the public docket. EPA will publish a notice in the Federal Register 
annually describing such changes which have occurred during the previous 
year. Until such Federal Register notice is published, any modification 
approved by EPA shall apply only to the person or group who requested 
the modification; EPA shall state the applicability of each modification 
in such notice.
    (iv) Where, in EPA's judgment, the requested modification of a test 
standard would significantly change the scope of the test, EPA will 
publish a notice in the Federal Register requesting comment on the 
request and proposed modification. However, EPA may approve a requested 
modification of a test standard without first seeking public comment if 
necessary to preserve the validity of an ongoing test undertaken in good 
faith.
    (2) [Reserved]
    (h) Special Requirements for Additives. An additive which is a 
direct test subject, either because it is the chosen representative of a 
group or because it is not a member of a group, is subject to the 
following rules:
    (1) All required emission characterization and health effects 
testing procedures shall be performed on the mixture which results when 
the additive is combined with the base fuel for the appropriate fuel 
family (as specified in Sec. 79.55) at the maximum concentration 
recommended by the additive manufacturer pursuant to Sec. 79.21(d). This 
combination shall be known as the additive/base fuel mixture.
    (i) The appropriate fuel family to be utilized for the additive/base 
fuel mixture is the fuel family which contains the specific type(s) of 
fuel for which the additive is presently registered or for which the 
manufacturer of the additive is seeking registration.
    (ii) Fuels and additives belonging to more than one fuel family.
    (A) If a fuel or additive product is registered in two or more fuel 
families as of May 27, 1994, then the manufacturer of that product is 
responsible for testing (or participating in group testing of) each 
formulation in compliance with the requirements of this subpart for each 
fuel family in which the manufacturer wishes to maintain a product 
registration for its fuel or additive.
    (B) If a fuel or additive manufacturer is seeking to register such 
product in two or more fuel families, then the product shall be 
considered, for testing and registration purposes, to be a member of 
each fuel family in which the manufacturer is seeking registration. The 
manufacturer is responsible for testing (or participating in group 
testing of) each formulation in compliance with the requirements of this 
subpart for each fuel family in which the manufacturer wishes to obtain 
a product registration for its fuel or additive.
    (iii) In the case of the methanol fuel family, which contains two 
base fuels (M100 and M85 base fuels, pursuant to Sec. 79.55(d)), the 
applicable base fuel is the one which represents the fuel/additive group 
(specified in Sec. 79.56(e)(4)(i)(C)) containing fuels of which the most 
gallons are sold annually.
    (iv) Aftermarket additives which are intended by the manufacturer to 
be added to the fuel tank only at infrequent intervals shall be applied 
according to the manufacturer's specifications during mileage 
accumulation, pursuant to Sec. 79.57(c). However, during emission 
generation and testing, each tankful of fuel used must contain the fuel 
additive at its maximum recommended level. If the additive manufacturer 
believes that this maximum treatment rate will cause adverse effects to 
the test engine and/or that the

[[Page 396]]

engine's emissions may be subject to artifacts due to overuse of the 
additive, then the manufacturer may submit a request to EPA for 
modification of this requirement and related test procedures. Such 
request must include objective evidence that the modification(s) are 
needed, along with data demonstrating the maximum concentration of the 
additive which may actually reach the fuel tanks of vehicles in use.
    (v) Additives produced exclusively for use in #1 diesel fuel shall 
be tested in the diesel base fuel specified in Sec. 79.55(c), even 
though that base fuel is formulated with #2 diesel fuel. If a 
manufacturer is concerned that emissions generated from this combination 
of fuel and additive are subject to artifacts due to this blending, then 
that manufacturer may submit a request for a modification in test 
procedure requirements to the EPA. Any such request must include 
supporting test results and suggested test modifications.
    (vi) Bulk additives which are used intermittently for the direct 
purpose of conditioning or treating a fuel during storage or transport, 
or for treating or maintaining the storage, pipeline, and/or other 
components of the fuel distribution system itself and not the vehicle/
engine for which the fuel is ultimately intended, shall, for purposes of 
this program, be added to the base fuel at the maximum concentration 
recommended by the additive manufacturer for treatment of the fuel or 
distribution system component. However, if the additive manufacturer 
believes that this treatment rate will cause adverse effects to the test 
engine and/or that the engine's emissions may be subject to artifacts 
due to overuse of the additive, then the manufacturer may submit a 
request to EPA for modification of this requirement and related test 
procedures. Such request must include objective evidence that the 
modification(s) are needed, along with data demonstrating the maximum 
concentration of the additive which may actually reach the fuel tanks of 
vehicles in use.
    (2) EPA shall use emissions speciation and health effects data 
generated in the analysis of the applicable base fuel as control data 
for comparison with data generated for the additive/base fuel mixture.
    (i) The base fuel control data may be:
    (A) Generated internally as an experimental control in conjunction 
with testing done in compliance with registration requirements for a 
specific additive; or
    (B) Generated externally in the course of testing different 
additive(s) belonging to the same fuel family, or in the testing of a 
base fuel serving as representative of the baseline group for the 
respective fuel family pursuant to Sec. 79.56(e)(4)(i).
    (ii) Control data generated using test equipment (including vehicle 
model and/or engine, or Evaporative Emissions Generator specifications, 
as appropriate) and protocols identical or nearly identical to those 
used in emissions and health effects testing of the subject additive/
base fuel mixture would be most relevant for comparison purposes.
    (iii) If an additive manufacturer chooses the same vehicle/engine to 
independently test the base fuel as an experimental control prior to 
testing the additive/base fuel mixture, then the test vehicle/engine 
shall undergo two mileage accumulation periods, pursuant to 
Sec. 79.57(c). The initial mileage accumulation period shall be 
performed using the base fuel alone. After base fuel testing, and prior 
to testing of the additive/base fuel mixture, a second mileage 
accumulation period shall be performed using the additive/base fuel 
mixture. The procedures outlined in this paragraph shall not preclude a 
manufacturer from testing a base fuel and the manufacturer's additive/
base fuel mixture separately in identical, or nearly identical, 
vehicles/engines.
    (i) Multiple Test Potential for Non-Baseline Products. (1) When the 
composition information reported in the registration application or 
basic registration data for a gasoline or diesel product meets criteria 
for classification as a non-baseline product (pursuant to 
Sec. 79.56(e)(3)(i)(B) or Sec. 79.56(e)(3)(ii)(B)), then the 
manufacturer is responsible for testing (or participating in group 
testing) of a separate formulation for each reported oxygenating 
compound, specified class of oxygenating compounds, or other

[[Page 397]]

substance which defines a separate non-baseline fuel/additive group 
pursuant to Sec. 79.56(e)(4)(ii)(A) or (B). For each such substance, 
testing shall be performed on a mixture of the relevant substance in the 
appropriate base fuel, formulated according to the specifications for 
the corresponding group representatives in Sec. 79.56(e)(4)(ii).
    (2) When the composition information reported in the registration 
application or basic registration data for a non- baseline gasoline 
product contains a range of total oxygenate concentration-in-use which 
encompasses gasoline formulations with less than 1.5 weight percent 
oxygen as well as gasoline formulations with 1.5 weight percent oxygen 
or more, then the manufacturer is required to test (or participate in 
applicable group testing of) a baseline gasoline formulation as well as 
one or more non-baseline gasoline formulations as described in paragraph 
(h)(1) of this section.
    (3) When the composition information reported in the registration 
application or basic registration data for a non- baseline diesel 
product contains a range of total oxygenate concentration-in-use which 
encompasses diesel formulations with less than 1.0 weight percent oxygen 
as well as diesel formulations with 1.0 weight percent oxygen or more, 
then the manufacturer is required to test (or participate in applicable 
group testing) of a baseline diesel formulation as well as one or more 
non-baseline diesel formulations as described in paragraph (h)(1) of 
this section.
    (j) Multiple Test Potential for Atypical Fuel Formulations. When the 
composition information reported in the registration application or 
basic registration data for a fuel product includes more than one 
atypical bulk additive product (pursuant to Sec. 79.56(e)(2)(iii)), and 
when these additives belong to different fuel/additive groups (pursuant 
to Sec. 79.56(e)(4)(iii)), then:
    (1) When such disparate additive products are for the same purpose-
in-use and are not ordinarily used in the fuel simultaneously, the fuel 
manufacturer shall be responsible for testing (or participating in the 
group testing of) a separate formulation for each such additive product. 
Testing related to each additive product shall be performed on a mixture 
of the additive in the applicable base fuel, as described in paragraph 
(g)(1) of this section, or by participation in the costs of testing the 
designated representative of the fuel/additive group to which each 
separate atypical additive product belongs.
    (2) When the disparate additive products are not for the same 
purpose-in-use, the fuel manufacturer shall nevertheless be responsible 
for testing a separate formulation for each such additive product, as 
described in paragraph (g)(1) of this section, if these additives are 
not ordinarily blended together in the same commercial formulation of 
the fuel.
    (3) When the disparate additive products are ordinarily blended 
together in the same commercial formulation of the fuel, then the fuel 
manufacturer shall be responsible for the testing of a single test 
formulation containing all such simultaneously used atypical additive 
products. Alternatively, this responsibility can be satisfied by 
enrolling such fuel product in a group which includes other fuel or 
additive products with the same total combination of atypical elements 
as that occurring in the fuel product in question. If the basic 
registration data for the subject fuel includes any alternative 
additives which contain atypical elements not represented in the test 
formulation, then the fuel manufacturer is also responsible for testing 
a separate formulation for each such additional disparate additive 
product.
    (k) Emission Control System Testing. If any information submitted in 
accordance with this subpart or any other information available to EPA 
shows that a fuel or fuel additive may have a deleterious effect on the 
performance of any emission control system or device currently in use or 
which has been developed to a point where in a reasonable time it would 
be in general use were such effect avoided, EPA may, in its judgment, 
require testing to determine whether such effects in fact exist. Such 
testing will be required in accordance with such protocols and schedules 
as the Administrator shall reasonably require and shall be paid for by 
the fuel or fuel additive manufacturer.

[[Page 398]]



Sec. 79.52  Tier 1.

    (a) General Specifications. Tier 1 requires manufacturers of 
designated fuels or fuel additives (or groups of manufacturers pursuant 
to Sec. 79.56) to supply to the Administrator: the identity and 
concentration of certain emission products of such fuels or additives; 
an analysis of potential emissions exposures; and any available 
information regarding the health and welfare effects of the whole and 
speciated emissions. In addition to any information required under 
Sec. 79.59 and in conformance with the reporting requirements thereof, 
manufacturers shall provide, pursuant to the timing provisions of 
Sec. 79.51(c), the following information.
    (b) Emissions Characterization. Manufacturers must provide a 
characterization of the emission products which are generated by 
evaporation (if required pursuant to Sec. 79.58(b)) and by combustion of 
the fuel or additive/base fuel mixture in a motor vehicle. For this 
purpose, manufacturers may perform the characterization procedures 
described in this section or may rely on existing emission 
characterization data. To be considered adequate in lieu of performing 
new emission characterization procedures, the data must be the result of 
tests using the product in question or using a fuel or additive/base 
fuel mixture meeting the same grouping criteria as the product in 
question. In addition, the emissions must be generated in a manner 
reasonably similar to those described in Sec. 79.57, and the 
characterization procedures must be adequately performed and documented 
and must give results reasonably comparable to those which would be 
obtained by performing the procedures described herein. Reports of 
previous tests must be sufficiently detailed to allow EPA to judge the 
adequacy of protocols, techniques, and conclusions. After the 
manufacturer's submittal of such data, if EPA finds that the 
manufacturer has relied upon inadequate test data, then the manufacturer 
will not be considered to be in compliance until the corresponding tests 
have been conducted and the results submitted to EPA.
    (1) General Provisions.
    (i) The emissions to be characterized shall be generated, collected, 
and stored according to the processes described in Sec. 79.57. 
Characterization of combustion and evaporative emissions shall be 
performed separately on each emission sample collected during the 
applicable emission generation procedure.
    (ii) As provided in Sec. 79.57(d), if the emission generation 
vehicle/engine is ordinarily equipped with an emission aftertreatment 
device, then all requirements in this section for the characterization 
of combustion emissions must be completed both with and without the 
aftertreatment device in a functional state. The emissions shall be 
generated three times (on three different days) without a functional 
aftertreatment device and, if applicable, three times (on three 
different days) with a functional aftertreatment device, and each such 
time shall be analyzed according to the remaining provisions in this 
paragraph (b) of this section.
    (iii) Measurement of background emissions. It is required that 
ambient/dilution air be analyzed for levels of background chemical 
species present at the time of emission sampling (for both combustion 
and evaporative emissions) and that background chemical species profiles 
be reported with emissions speciation data. Background chemical species 
measurement/analysis during the FTP is specified in Secs. 86.109-
94(c)(5) and 86.135-94 of this chapter.
    (iv) Concentrations of emission products shall be reported in units 
of grams (g) per mile and in units of weight percent of measured total 
hydrocarbons.
    (v) Laboratory practice must be of high quality and must be 
consistent with state-of-the-art methods as presented in current 
environmental and analytical chemistry literature. Examples of 
analytical procedures which may be used in conducting the emission 
characterization/speciation requirements of this section can be found 
among the references in paragraph (b)(5) of this section.
    (2) Characterization of the combustion emissions shall include, for 
products in all fuel families (except when expressly noted in this 
section):
    (i) Determination of the concentration of the basic emissions as 
follows: total hydrocarbons, carbon monoxide,

[[Page 399]]

oxides of nitrogen, and particulates. Manufacturers are referred to the 
vehicle certification procedures in 40 CFR part 86, subparts B and D 
(Secs. 86.101 through 86.145 and Secs. 86.301 through 86.348) for 
guidance on the measurement of the basic emissions of interest to this 
subpart.
    (ii) Characterization of the vapor phase of combustion emissions, as 
follows:
    (A) Determination of the identity and concentration of individual 
species of hydrocarbon compounds containing 12 or fewer carbon atoms. 
Such characterization shall begin within 30 minutes after emission 
collection is completed.
    (B) Determination of the identity and concentration of individual 
species of aldehyde and ketone compounds containing eight or fewer 
carbon atoms. Characterization of these emissions captured in cartridges 
shall be performed within two weeks if the cartridge is stored at room 
temperature, and one month if the cartridge is stored at 0  deg.C or 
less. If the emissions are sampled using the impinger method, the sample 
must be stored in a capped sample vial at 0  deg.C or less and 
characterized within one week.
    (C) Determination of the identity and concentration of individual 
species of alcohol and ether compounds containing six or fewer carbon 
atoms, for those fuels and additive/base fuel mixtures which contain 
alcohol and/or ether compounds containing from one to six carbon atoms 
in the uncombusted state. For fuel and additive formulations containing 
alcohols or ethers with more than six carbon atoms in the uncombusted 
state, alcohol and ether species with that higher number of carbon atoms 
or less must be identified and measured in the emissions. Such 
characterization shall begin within four hours after emission collection 
is completed.
    (iii) Characterization of the semi-volatile and particulate phases 
of combustion emissions to identify and measure polycyclic aromatic 
compounds, as follows:
    (A) Analysis for polycyclic aromatic compounds shall not be 
conducted at or soon after the start of a recommended engine lubricant 
change interval.
    (B) Analysis for polycyclic aromatic hydrocarbons (PAHs) and 
nitrated polycyclic aromatic hydrocarbons (NPAHs), specified in 
paragraph (b)(2)(iii)(D) of this section, need not be done for any fuels 
and additives in the methane or propane fuel families, nor for fuels and 
additives in the atypical categories of any other fuel families, 
pursuant to the definitions of such families and categories in 
Sec. 79.56.
    (C) Analysis for poly-chlorinated dibenzodioxins and dibenzofurans 
(PCDD/PCDFs), specified in paragraph (b)(2)(iii)(E) of this section, is 
required only for fuels and additives which contain chlorine as an 
atypical element, pursuant to paragraph (b)(2)(iv) of this section, 
which requires all individual emission products containing atypical 
elements to be determined for atypical fuels and additives. However, 
manufacturers of baseline and nonbaseline fuels and fuel additives in 
all fuel families, except those in the methane and propane fuel 
families, are strongly encouraged to conduct these analyses on a 
voluntary basis.
    (D) The analytical method used to measure species of PAHs and NPAHs 
should be capable of detecting at least 1 ppm (equivalent to 0.001 
microgram (g) of compound per milligram of organic extract) of 
these compounds in the extractable organic matter. The concentration of 
each individual PAH or NPAH compound identified shall be reported in 
units of microgram per mile. Each compound which is present at 0.001 
g per mile or more must be identified, measured, and reported. 
The following individual species shall be measured:
    (1) PAHs:
    (i) Benzo(a)anthracene;
    (ii) Benzo[b]fluoranthene;
    (iii) Benzo[k]fluoranthene;
    (iv) Benzo(a)pyrene;
    (v) Chrysene;
    (vi) Dibenzo[a,h]anthracene; and
    (vii) Indeno[1,2,3-c,d]pyrene.
    (2) NPAHs:
    (i) 7-Nitrobenzo[a]anthracene;
    (ii) 6-Nitrobenzo[a]pyrene;
    (iii) 6-Nitrochrysene;
    (iv) 2-Nitrofluorene; and
    (v) 1-Nitropyrene.
    (E) The analytical method used to measure species and classes of 
PCDD/

[[Page 400]]

PCDFs should be capable of detecting at least 1 part per trillion (ppt) 
(equivalent to 0.001 picogram (pg) of compound per milligram of organic 
extract) of these compounds in the extractable organic matter. The 
concentration of each individual PCDD/PCDF compound identified shall be 
reported in units of picograms (pg) per mile. Each compound which is 
present at 0.5 pg per mile or more must be identified, measured, and 
reported.
    (1) With respect to measurement of PCDD/PCDFs only, the liquid 
extracts from the particulate and semi-volatile emissions fractions may 
be combined into one sample for analysis.
    (2) The manufacturer is referred to 40 CFR part 60, appendix A, 
Method 23 for a protocol which may be used to identify and measure any 
potential PCDD/PCDFs which might be present in exhaust emissions from a 
fuel or additive/base fuel mixture.
    (3) The following individual compounds and classes of compounds of 
PCDD/PCDFs shall be identified and measured:
    (i) Individual tetra-chloro-substituted dibenzodioxins (tetra-CDDs);
    (ii) Individual tetra-chloro-substituted dibenzofurans (tetra-CDFs);
    (iii) Penta-CDDs and penta-CDFs, as one class;
    (iv) Hexa-CDDs and hexa-CDFs, as one class;
    (v) Hepta-CDDs and hepta-CDFs as one class; and
    (vi) Octo-CDDs and octo-CDFs as one class.
    (iv) With respect to all phases (vapor, semi-volatile, and 
particulate) of combustion emissions generated from those fuels and 
additive/base fuel mixtures classified in the atypical categories 
(pursuant to Sec. 79.56), the identity and concentration of individual 
emission products containing such atypical elements shall also be 
determined.
    (3) For evaporative fuels and evaporative fuel additives, 
characterization of the evaporative emissions shall include:
    (i) Determination of the concentration of total hydrocarbons for the 
applicable vehicle type and class in 40 CFR part 86, subpart B 
(Secs. 86.101 through 86.145).
    (ii) Determination of the identity and concentration of individual 
species of hydrocarbon compounds containing 12 or fewer carbon atoms. 
Such characterization shall begin within 30 minutes after emission 
collection is completed.
    (iii) In the case of those fuels and additive/base fuel mixtures 
which contain alcohol and/or ether compounds in the uncombusted state, 
determination of the identity and concentration of individual species of 
alcohol and ether compounds containing six or fewer carbon atoms. For 
fuel and additive formulations containing alcohols or ethers with more 
than six carbon atoms in the uncombusted state, alcohol and ether 
species with that higher number of carbon atoms or less must be 
identified and measured in the emissions. Such characterization shall 
begin within four hours after emission collection is completed.
    (iv) In the case of those fuels and additive/base fuel mixtures 
which contain atypical elements, determination of the identity and 
concentration of individual emission products containing such atypical 
elements.
    (4) Laboratory quality control. (i) At a minimum, laboratories 
performing the procedures specified in this section shall conduct 
calibration testing of their emissions characterization equipment before 
each new fuel/additive product test start-up. Known samples 
representative of the compounds potentially to be found in emissions 
from the product to be characterized shall be used to calibrate such 
equipment.
    (ii) Laboratories performing the procedures specified in this 
section shall agree to permit quality control inspections by EPA, and 
for this purpose shall admit any EPA Enforcement Officer, upon proper 
presentation of credentials, to any facility where vehicles are 
conditioned or where emissions are generated, collected, stored, 
sampled, or characterized in meeting the requirements of this section. 
Such laboratory audits may include EPA distribution of ``blind'' samples 
for analysis by participating laboratories.
    (5) References. For additional background information on the 
emission characterization procedures outlined in this paragraph, the 
following references may be consulted:

[[Page 401]]

    (i) ``Advanced Emission Speciation Methodologies for the Auto/Oil 
Air Quality Improvement Program--I. Hydrocarbons and Ethers,'' Auto Oil 
Air Quality Improvement Research Program, SP-920, 920320, SAE, February 
1992.
    (ii) ``Advanced Speciation Methodologies for the Auto/Oil Air 
Quality Improvement Research Program--II. Aldehydes, Ketones, and 
Alcohols,'' Auto Oil Air Quality Improvement Research Program, SP-920, 
920321, SAE, February 1992.
    (iii) ASTM D 5197-91, ``Standard Test Method for Determination of 
Formaldehyde and Other Carbonyl Compounds in Air (Active Sampler 
Methodology).''
    (iv) Johnson J. H., Bagley, S. T., Gratz, L. D., and Leddy, D. G., 
``A Review of Diesel Particulate Control Technology and Emissions 
Effects--1992 Horning Memorial Award Lecture,'' SAE Technical Paper 
Series, SAE 940233, 1994.
    (v) Keith et al., ACS Committee on Environmental Improvement, 
``Principles of Environmental Analysis,'' The Journal of Analytical 
Chemistry, Volume 55, pp. 2210-2218, 1983.
    (vi) Perez, J.M., Jabs, R.E., Leddy, D.G., eds. ``Chemical Methods 
for the Measurement of Unregulated Diesel Emissions (CRC-APRAC Project 
No. CAPI-1-64), Coordinating Research Council, CRC Report No. 551, 
August, 1987.
    (vii) Schuetzle, D., ``Analysis of Nitrated Polycyclic Aromatic 
Hydrocarbons in Diesel Particulates,'' Analytical Chemistry, Volume 54, 
pp. 265-271, 1982.
    (viii) Siegl, W.O., et al., ``Improved Emissions Speciation 
Methodology for Phase II of the Auto/Oil Air Quality Improvement 
Research Program--Hydrocarbons and Oxygenates'', SAE Technical Paper 
Series, SAE 930142, 1993.
    (ix) Tejada, S. B. et al., ``Analysis of Nitroaromatics in Diesel 
and Gasoline Car Emissions,'' SAE Paper No. 820775, 1982.
    (x) Tejada, S. B. et al., ``Fluorescence Detection and 
Identification of Nitro Derivatives of Polynuclear Aromatic Hydrocarbons 
by On-Column Catalytic Reduction to Aromatic Amines,'' Analytical 
Chemistry, Volume 58, pp. 1827-1834, July 1986.
    (xi) ``Test Method for Determination of C1-C4 Alcohols and MTBE in 
Gasoline by Gas Chromatography,'' 40 CFR part 80, appendix F.
    (c) Exposure Analysis. Using annual and projected production volume, 
marketing, and distribution data submitted as part of the basic 
registration data, specified in Sec. 79.59(b), manufacturers shall 
provide a qualitative discussion of the potential public health 
exposure(s) of the general population and any special at-risk 
populations to the emission products of their fuel or additive 
product(s). The analysis accompanying a group submission shall address 
the characteristics of the cumulative exposure resulting from the use of 
all fuel or additive products in the group. Modeling and other 
quantitative approaches to the analysis are encouraged when the 
appropriate data is available.
    (d) Literature Search. (1) Manufacturers of fuels and fuel additives 
shall conduct a literature search and compilation of information on the 
potential toxicologic, environmental, and other public welfare effects 
of the emissions of such fuels and additives. The literature search 
shall include all available relevant information from in-house, 
industry, government, and public sources pertaining to the emissions of 
the subject fuel or fuel additive or the emissions of similar fuels or 
additives, with such similarity determined according to the provisions 
of Sec. 79.56.
    (2) The literature search shall address the potential adverse 
effects of whole combustion emissions, evaporative emissions, relevant 
emission fractions, and individual emission products of the subject fuel 
or fuel additive except as specified in the following paragraph. The 
individual emission products to be included are those identified 
pursuant to the emission characterization procedures specified in 
paragraph (b) of this section, other than carbon monoxide, carbon 
dioxide, nitrogen oxides, benzene, 1,3-butadiene, acetaldehyde, and 
formaldehyde.
    (3) In the case of the individual emission products of non-baseline 
or atypical fuels and additives (pursuant to Sec. 79.56(e)(2)), the 
literature data need

[[Page 402]]

not be submitted for those emission products which are the same as the 
combustion emission products of the respective base fuel for the 
product's fuel family (pursuant to Sec. 79.55). For this purpose, data 
on the base fuel emission products for the product's fuel family:
    (i) May be found in the literature of previously-conducted, adequate 
emission speciation studies for the base fuel, or for a fuel or 
additive/fuel mixture capable of grouping with the base fuel (see, for 
example, the references in paragraph (b)(5) of this section).
    (ii) May be compiled while gathering internal control data during 
emissions characterization studies on the manufacturer's non-baseline or 
atypical product; or
    (iii) May be obtained from various manufacturers in the course of 
their testing different additive(s) belonging to the same fuel family, 
or in the testing of a base fuel serving as representative of the 
baseline group for the respective fuel family.
    (e) Data bases. The literature search must include the results of 
searching appropriate commercially available chemical, toxicologic, and 
environmental databases. The databases shall be searched using, at a 
minimum, CAS numbers (when applicable), chemical names, and common 
synonyms.
    (f) Search period. The literature search shall cover a time period 
beginning at least thirty years prior to the date of submission of the 
reports specified in Secs. 79.59(b) through (c) and ending no earlier 
than six months prior to the date on which testing is commenced or 
reports are submitted in compliance with this subpart.
    (g) References. Information on base fuel emission inventories may be 
found in references in paragraphs (b)(5)(i) through (xi) of this 
section, as well as in the following:
    (1) Auto/Oil Air Quality Improvement Research Program, Technical 
Bulletin #1, December 1990.
    (2) Keith et al., ACS Committee on Environmental Improvement, 
``Principles of Environmental Analysis,'' The Journal of Analytical 
Chemistry, Volume 55, pp. 2210-2218, 1983.
    (3) ``The Composition of Gasoline Engine Hydrocarbon Emissions--An 
Evaluation of Catalyst and Fuel Effects''--SAE 902074 and ``Speciated 
Hydrocarbon Emissions from Aromatic, Olefin, and Paraffinic Model 
Fuels''--SAE 930373.



Sec. 79.53  Tier 2.

    (a) Generally. Subject to the provisions of Sec. 79.53(b) through 
(d), the combustion emissions of each fuel or fuel additive subject to 
testing under this subpart must be tested in accordance with each of the 
testing guidelines in Secs. 79.60 through 79.68, except that fuels and 
additives in the methane and propane fuel families (pursuant to 
Sec. 79.56(e)(1)(v) and (vi)) need not undergo the Salmonella 
mutagenicity assay in Sec. 79.68). Similarly, subject to the provisions 
of Sec. 79.53(b) through (d), the evaporative emissions of each 
designated evaporative fuel and each designated evaporative fuel 
additive subject to testing under this subpart must be tested according 
to each of the testing guidelines in Secs. 79.60 through 79.67 
(excluding Sec. 79.68, Salmonella typhimurium Reverse Mutation Assay).
    (b) Manufacturer Determination. Manufacturers shall determine 
whether the information gathered pursuant to the literature search in 
Sec. 79.52(d) contains the results of adequately performed and 
adequately documented previous testing which provides information 
reasonably comparable to that supplied by the health tests described in 
Secs. 79.62 through 79.68 regarding the carcinogenicity, mutagenicity, 
neurotoxicity, teratogenicity, reproductive/fertility measures, and 
general toxicity effects of the emissions of the fuel or additive. When 
manufacturers make an affirmative determination, they need submit only 
the information gathered pursuant to Sec. 79.52(d) for such tests. EPA 
maintains final authority in judging whether the information is an 
adequate substitution in lieu of conducting the associated tests. EPA's 
determination of the adequacy of existing information shall be guided by 
the considerations described in paragraph (d) of this section. If EPA 
finds that the manufacturer has relied upon inadequate test data, then 
the manufacturer will not be considered to be in compliance until

[[Page 403]]

the corresponding tests have been conducted and the results submitted to 
EPA.
    (c) Testing. (1) All testing required pursuant to this section must 
be done in accordance with the procedures, equipment, and facility 
requirements described in Secs. 79.57, 79.60, and 79.61 regarding 
emissions generation, good laboratory practices, and inhalation exposure 
testing, respectively, as well as any other requirements described in 
this subpart. The laboratory conducting the animal studies shall be 
registered and in good standing with the United States Department of 
Agriculture and regularly inspected by United States Department of 
Agriculture veterinarians. In addition, the facility must be accredited 
by a generally recognized independent organization which sets laboratory 
animal care standards. Use of inadequate test protocols or substandard 
laboratory techniques in performing any testing required by this subpart 
may result in cancellation of all affected registrations.
    (2) Carcinogenic or mutagenic effects in animals from emissions 
exposures shall be determined pursuant to Sec. 79.64 In vivo 
Micronucleus Assay, Sec. 79.65 In vivo Sister Chromatid Exchange Assay, 
and Sec. 79.68 Salmonella typhimurium Reverse Mutation Assay. 
Teratogenic effects and reproductive toxicity shall be examined pursuant 
to Sec. 79.63 Fertility Assessment/Teratology. General toxicity and 
pulmonary effects shall be determined pursuant to Sec. 79.62 Subchronic 
Toxicity Study with Specific Health Effect Assessments. Neurotoxic 
effects shall be determined pursuant to Sec. 79.66 Neuropathology 
Assessment and Sec. 79.67 Glial Fibrillary Acidic Protein Assay.
    (d) EPA Determination. (1) After submission of all information and 
testing, EPA in its judgment shall determine whether previously 
conducted tests relied upon in the registration submission are 
adequately performed and documented and provide information reasonably 
comparable to that which would be provided by the tests described 
herein. Manufacturers' submissions shall be sufficiently detailed to 
allow EPA to judge the adequacy of protocols, techniques, experimental 
design, statistical analyses, and conclusions. Studies shall be 
performed using generally accepted scientific principles, good 
laboratory techniques, and the testing guidelines specified in these 
regulations.
    (2) EPA shall give appropriate weight when making this determination 
to the following factors:
    (i) The age of the data;
    (ii) The adequacy of documentation of procedures, findings, and 
conclusions;
    (iii) The extent to which the testing conforms to generally accepted 
scientific principles and practices;
    (iv) The type and number of test subjects;
    (v) The number and adequacy of exposure concentrations, i.e., 
emission dilutions;
    (vi) The degree to which the tested emissions were generated by 
procedures and under conditions reasonably comparable to those set forth 
in Sec. 79.57; and
    (vii) The degree to which the test procedures conform to the testing 
guidelines set forth in Secs. 79.60 through 79.68 and/or furnish 
information comparable to that provided by such testing.
    (3) The test animals shall be rodents, preferably a strain of rat, 
and testing shall include all of the endpoints covered in Secs. 79.62 
through 79.68. All studies shall be properly executed, with appropriate 
documentation, and in accord with the individual health testing 
guidelines (Secs. 79.60 through 79.68) of this part, e.g., 90-day, 6-
hour per day exposure, minimum.
    (4) In general, the data in a manufacturer's registration submittal 
shall be adequate if the duration of a test's exposure period is at 
least as long, in days and hours, as the inhalation exposure specified 
in the related health test guideline(s). Data from tests with shorter 
exposure durations than those specified in the guidelines may be 
acceptable if the test results are positive (i.e., exhibit adverse 
effects) and/or include a demonstrable concentration-response 
relationship.
    (5) Data in support of a manufacturer's registration submittal shall 
directly address the effects of inhalation exposure to the whole 
evaporative and exhaust emissions of the respective

[[Page 404]]

fuel or additive or to the whole evaporative and exhaust emissions of 
other fuels or additives which satisfy the criteria in Sec. 79.56 for 
classification into the same group as the subject fuel or fuel additive. 
Data obtained in the testing of a raw liquid fuel or additive/base fuel 
mixture or a raw, aerosolized fuel or additive/base fuel mixture shall 
not be adequate to support a manufacturer's registration submittal. Data 
from testing of evaporative emissions cannot substitute for test data on 
combustion emissions. Data from testing of combustion emissions cannot 
substitute for test data on evaporative emissions.



Sec. 79.54  Tier 3.

    (a) General Criteria for Requiring Tier 3 Testing. (1) Tier 3 
testing shall be required of a manufacturer or group of manufacturers at 
EPA's discretion when remaining uncertainties as to the significance of 
observed health effects, welfare effects, and/or emissions exposures 
from a fuel or fuel/additive mixture interfere with EPA's ability to 
make reasonable estimates of the potential risks posed by emissions from 
the fuel or additive products. Tier 3 testing may be conducted either on 
an individual basis or a group basis. If performed on a group basis, EPA 
may require either the same representative to be used in Tier 3 testing 
as was used in Tier 2 testing or may select a different member or 
members of the group to represent the group in the Tier 3 tests.
    (2) In addition to the criteria specific to particular tests as 
summarized and detailed in the testing guidelines (Secs. 79.62 through 
79.68), EPA may consider a number of factors (including, but not limited 
to):
    (i) The number of positive and negative outcomes related to each 
endpoint;
    (ii) The identification of concentration-effect relationships;
    (iii) The statistical sensitivity and significance of such studies;
    (iv) The severity of the observed effects (e.g., whether the effects 
would be likely to lead to incapacitating or irreversible conditions);
    (v) The type and number of species included in the reported tests;
    (vi) The consistency and clarity of apparent mechanisms, target 
organs, and outcomes;
    (vii) The presence or absence of effective health test control data 
for base-fuel-only versus additive/base fuel mixture comparisons;
    (viii) The nature and amount of known toxic agents in the emissions 
stream; and
    (ix) The observation of lesions which specifically implicate 
inhalation as an important exposure route.
    (3) Consideration of exposure. EPA retains discretion to consider, 
in addition to available toxicity data, any Tier 1 data on potential 
exposures to emissions from a particular fuel or fuel additive (or group 
of fuels and/or fuel additives) in determining whether to require Tier 3 
testing. EPA may consider, but is not limited to, the following factors:
    (i) Types and emission rates of speciated emission components;
    (ii) Types and emission rates of combinations of compounds or 
elements of concern;
    (iii) Historical and/or projected production volumes and market 
distributions; and
    (iv) Estimated population and/or environmental exposures obtained 
through extrapolation, modeling, or literature search findings on 
ambient, occupational, or epidemiological exposures.
    (b) Notice. (1) EPA will determine whether Tier 3 testing is 
necessary upon receipt of a manufacturer's (or group's) submittal as 
prescribed under Sec. 79.51(d). If EPA determines on the basis of the 
Tier 1 and 2 data submission and any other available information that 
further testing is necessary, EPA will require the responsible 
manufacturer(s) to conduct testing as described elsewhere in this 
section. EPA will notify the manufacturer (or group) by certified letter 
of the purpose and nature of any proposed testing and of the proposed 
deadline for completing the testing. A copy of the letter will be placed 
in the public record. EPA will provide the manufacturer a 60-day comment 
period after the manufacturer's receipt of such notice. EPA may extend 
the comment period if it appears from the nature of the issues

[[Page 405]]

raised that further discussion is warranted. In the event that no 
comment is received by EPA from the manufacturer (or group) within the 
comment period, the manufacturer (or group) shall be deemed to have 
consented to the adoption by EPA of the proposed Tier 3 requirements.
    (2) EPA will issue a notice in the Federal Register of its intent to 
require testing under Tier 3 for a particular fuel or additive 
manufacturer and that a copy of the letter to the manufacturer outlining 
the Tier 3 testing for that manufacturer is available in the public 
record for review and comment. The public shall have a minimum of thirty 
(30) days after the publication of this notice to comment on the 
proposed Tier 3 testing.
    (3) EPA will include in the public record a copy of any timely 
comments concerning the proposed Tier 3 testing requirements received 
from the affected manufacturer or group or from the public, and the 
responses of EPA to such comments. After reviewing all such comments 
received, EPA will adopt final Tier 3 requirements by sending a 
certified letter describing such final requirements to the manufacturer 
or group. EPA will also issue a notice in the Federal Register 
announcing that it has adopted such final Tier 3 requirements and that a 
copy of the letter adopting the requirements has been included in the 
public record.
    (4) Prior to beginning any required Tier 3 testing, the manufacturer 
shall submit detailed test protocols to EPA for approval. Once EPA has 
determined the Tier 3 testing requirements and approves the test 
protocols, any modification to the requirements shall be governed by 
Sec. 79.51(f).
    (c) Carcinogenicity and Mutagenicity Testing. (1) A potential need 
for Tier 3 carcinogenicity and/or mutagenicity testing may be indicated 
if the results of the In vivo Micronucleus Assay, required under 
Sec. 79.64, the In vivo Sister Chromatid Exchange Assay, required under 
Sec. 79.65, the Salmonella mutagenicity assay required under Sec. 79.68, 
or relevant pathologic findings under Sec. 79.62 demonstrate a 
statistically significant dose-related positive response as compared 
with appropriate controls. Alternatively, Tier 3 carcinogenicity testing 
and/or mutagenicity testing may be required if there are positive 
outcomes for at least one concentration in two or more of the tests 
required under Secs. 79.64, 79.65, and 79.68.
    (2) The testing for carcinogenicity required under this paragraph 
may, at EPA's discretion, be conducted in accordance with 40 CFR 
798.3300 or 798.3320, or their equivalents (see suggested references 
following each health effects testing guideline). The testing for 
mutagenicity required under this paragraph may likewise be conducted in 
accordance with 40 CFR 798.5195, 798.5500, 798.5955, 798.7100, and/or 
other suitable equivalent testing (see suggested references following 
each health effects testing guideline). EPA may supplement or modify 
guidelines as required to ensure that the prescribed testing addresses 
the identified areas of concern.
    (d) Reproductive and Teratological Effects Testing. (1) A potential 
need for Tier 3 testing may be indicated if the results of the Fertility 
Assessment/Teratology study required under Sec. 79.63 or relevant 
findings under Sec. 79.62 demonstrate, in comparison with appropriate 
controls, a statistically significant dose-related positive response in 
one or more of the possible test outcomes. Similarly, Tier 3 testing may 
be indicated if statistically significant positive results are confined 
to either sex, or to the fetus as opposed to the pregnant adult.
    (2) The testing for reproductive and teratological effects required 
under this paragraph may, at EPA's discretion, be conducted in 
accordance with 40 CFR 798.4700 and/or by performance of a reproductive 
assay by continuous breeding. These guidelines may be modified or 
supplemented by EPA as required to ensure that the prescribed testing 
addresses the identified areas of concern.
    (e) Neurotoxicity Testing. (1) A potential need for Tier 3 
neurotoxicity testing may be indicated if either the results of the 
Neuropathology Assessment required under Sec. 79.67 shows concentration-
related effects in exposed animals or the Glial Fibrillary Acidic 
Protein Assay required under Sec. 79.66

[[Page 406]]

demonstrates a statistically significant concentration-related positive 
response as compared with appropriate controls. Similarly, Tier 3 
neurotoxicity testing may be indicated if relevant results under 
Sec. 79.62 demonstrate a statistically significant positive response in 
comparison to appropriate controls.
    (2) The testing for neurotoxicity required under this paragraph may, 
at EPA's discretion, be conducted in accordance with 40 CFR 798.3260 and 
40 CFR part 798 subpart G. These guidelines may be modified or 
supplemented by EPA as required to ensure that the prescribed testing 
addresses the identified areas of concern.
    (f) General and Pulmonary Toxicity Testing. (1) A potential need for 
Tier 3 general and/or pulmonary toxicity testing may be indicated if, in 
comparison with appropriate controls, the results of the Subchronic 
Toxicity Study, pursuant to Sec. 79.62, demonstrate abnormal gross 
analysis or histopathological findings (especially as relates to lung 
pathology from whole-body preserved test animals) or persistence or 
delayed occurrence of toxic effects beyond the exposure period.
    (2) A potential need for Tier 3 testing with respect to other organ 
systems or endpoints not addressed by specific Tier 2 tests, e.g., 
hepatic, renal, or endocrine toxicity, may be demonstrated by findings 
in the Tier 2 Subchronic Toxicity Study (pursuant to Sec. 79.62) or by 
findings in the Tier 1 literature search of adverse functional, 
physiologic, metabolic, or histopathologic effects of fuel or additive 
emissions to such other organ systems or any other information available 
to EPA. In addition, findings in the Tier 1 emission characterization of 
significant levels of a known toxicant to such other organ systems and 
endpoints may also indicate a need for relevant health effects testing. 
The testing required under this paragraph may include tests conducted in 
accordance with 40 CFR 798.3260 or 798.3320. These guidelines may be 
modified or supplemented by EPA as necessary to ensure that the 
prescribed testing addresses the identified areas of concern.
    (3) The testing for general/pulmonary toxicity required under this 
paragraph may, at EPA's discretion, be conducted in accordance with 40 
CFR 798.2450 or 798.3260. These guidelines may be modified or 
supplemented by EPA as necessary to ensure that the prescribed testing 
addresses the identified areas of concern. Pulmonary function 
measurements, host defense assays, immunotoxicity tests, cell 
morphology/morphometry, and/or enzyme assays of lung lavage cells and 
fluids may be specifically required.
    (g) Other Tier 3 Testing. (1) A manufacturer or group may be 
required to use up-to-date modeling, sampling, monitoring, and/or 
analytic approaches at the Tier 3 level to provide:
    (i) Estimates of exposures to the emission products of a fuel or 
fuel additive or group of products;
    (ii) The expected atmospheric transformation products of such 
emissions; and
    (iii) The environmental partitioning of such emissions to the air, 
soil, water, and biota.
    (2) Additional emission characterization may be required if 
uncertainty over the identity of chemical species or rate of their 
emission interferes with reasonable judgments as to the presence and/or 
concentration of potentially toxic substances in the emissions of a fuel 
or fuel additive. The required tests may include characterization of 
additional classes of emissions, the characterization of emissions 
generated by additional vehicles/engines of various technology mixes 
(e.g., catalyzed versus non-catalyzed emissions), and/or other more 
precise analytic procedures for identification or quantification of 
emissions compounds. Additional emissions testing may also be required 
to evaluate concerns which may arise regarding the potential effects of 
a fuel or fuel additive on the performance of emission control 
equipment.
    (3) A manufacturer or group may be required to conduct biological 
and/or exposure studies at the Tier 3 level to evaluate directly the 
potential public welfare or environmental effects of the emissions of a 
fuel or additive, if significant concerns about such effects arise as a 
result of EPA's review of the

[[Page 407]]

literature search or emission characterization findings in Tier 1 or the 
results of the toxicological tests in Tier 2.
    (4) With regard to group submittals, Tier 3 studies on a fuel or 
additive product(s) other than the originally specified group 
representative may be required if specific differences in the product's 
composition indicate that its emissions may have different toxicologic 
properties from those of the original group representative.
    (5) Additional emission characterization and/or toxicologic tests 
may be required to evaluate the impact of different vehicle, engine, or 
emission control technologies on the observed composition or health or 
welfare effects of the emissions of a fuel or additive.
    (6) Toxicological tests on individual emission products may be 
required.
    (7) Upon review of information submitted for an aerosol product 
under Sec. 79.58(e), emissions characterization, exposure, and/or 
toxicologic testing at a Tier 3 level may be required.
    (8) A manufacturer which qualifies for and has elected to use the 
special provisions for the products of small businesses (pursuant to 
Sec. 79.58(d)) may be required to conduct emission characterization, 
exposure, and /or toxicologic studies at the Tier 3 level for such 
products, as specified in Sec. 79.58(d)(4).
    (9) The examples of potential Tier 3 tests described in this section 
do not in any way limit EPA's broad discretion and authority under Tier 
3.



Sec. 79.55  Base fuel specifications.

    (a) General Characteristics. (1) The base fuel(s) in each fuel 
family shall serve as the group representative(s) for the baseline 
group(s) in each fuel family pursuant to Sec. 79.56. Also, as specified 
in Sec. 79.51(h)(1), for fuel additives undergoing testing, the 
designated base fuel for the respective fuel family shall serve as the 
substrate in which the additive shall be mixed prior to the generation 
of emissions.
    (2) Base fuels shall contain a limited complement of the additives 
which are essential for the fuel's production or distribution and/or for 
the successful operation of the test vehicle/engine throughout the 
mileage accumulation and emission generation periods. Such additives 
shall be used at the minimum effective concentration-in-use for the base 
fuel in question.
    (3) Unless otherwise restricted, the presence of trace contaminants 
does not preclude the use of a fuel or fuel additive as a component of a 
base fuel formulation.
    (4) When an additive is the test subject, any additive normally 
contained in the base fuel which serves the same function as the subject 
additive shall be removed from the base fuel formulation. For example, 
if a corrosion inhibitor were the subject of testing and if this 
additive were to be tested in a base fuel which normally contained a 
corrosion inhibitor, this test additive would replace the corrosion 
inhibitor normally included as a component of the base fuel.
    (5) Additive components of the methanol, ethanol, methane, and 
propane base fuels in addition to any such additives included below 
shall be limited to those recommended by the manufacturers of the 
vehicles and/or engines used in testing such fuels. For this purpose, 
EPA will review requests from manufacturers (or their agents) to modify 
the additive specifications for the alternative fuels and, if necessary, 
EPA shall change these specifications based on consistency of those 
changes with the associated vehicle manufacturer's recommendations for 
the operation of the vehicle. EPA shall publish notice of any such 
changes to a base fuel and/or its base additive package specifications 
in the Federal Register.
    (b) Gasoline Base Fuel. (1) The gasoline base fuel is patterned 
after the reformulated gasoline summer baseline fuel as specified in CAA 
section 211(k)(10)(B)(i). The specifications and blending tolerances for 
the gasoline base fuel are listed in Table F94-1. The additive types 
which shall be required and/or permissible in the gasoline base fuel are 
listed in Table 1 as well.

               Table F94-1.--Gasoline Base Fuel Properties              
                                                                        
                                                                        
                                                                        
API Gravity..................................  57.40.3      
Sulfur, ppm..................................  33925        
Benzene, vol%................................  1.530.3      

[[Page 408]]

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


    (2) The additive components of the gasoline base fuel shall contain 
compounds comprised of no elements other than carbon, hydrogen, oxygen, 
nitrogen, and sulfur. Additives shall be used at the minimum 
concentration needed to perform effectively in the gasoline base fuel. 
In no case shall their concentration in the base fuel exceed the maximum 
concentration recommended by the additive manufacturer. The increment of 
sulfur contributed to the formulation by any additive shall not exceed 
15 parts per million sulfur by weight and shall not cause the gasoline 
base fuel to exceed the sulfur specifications in Table F94-1 of this 
section.
    (c) Diesel Base Fuel. (1) The diesel base fuel shall be a #2 diesel 
fuel having the properties and blending tolerances shown in Table F94-2 
of this section. The additive types which shall be permissible in diesel 
base fuel are presented in Table F94-2 as well.

                Table F94-2.--Diesel Base Fuel Properties               
                                                                        
                                                                        
                                                                        
API Gravity..................................  331          
Sulfur, wt%..................................  0.050.0025   
Cetane Number................................  45.22        
Cetane Index.................................  45.72        
Distillation Parameters:                                                
  10%,  deg.F................................  4335         
  50%,  deg.F................................  5165         
  90%,  deg.F................................  6065         
Aromatics, vol%..............................  38.42.7      
Olefins, vol%................................  1.50.4       
Saturates, vol%..............................  60.12.0      
Additive Types:                                                         
  Required...................................  Corrosion Inhibitor      
                                               Demulsifier              
                                               Anti-oxidant             
                                               Metal Deactivator        
  Permitted..................................  Anti-static              
                                               Flow Improver            
  Not Permitted..............................  Deposit Control          
                                                                        


    (2) The additive components of the diesel base fuel shall contain 
compounds comprised of no elements other than carbon, hydrogen, oxygen, 
nitrogen, and sulfur. Additives shall be used at the minimum 
concentration needed to perform effectively in the diesel base fuel. In 
no case shall their concentration in the base fuel exceed the maximum 
concentration recommended by the additive manufacturer. The increment of 
sulfur contributed to the base fuel by additives shall not cause the 
diesel base fuel to exceed the sulfur specifications in Table F94-2 of 
this section.
    (d) Methanol Base Fuels. (1) The methanol base fuels shall contain 
no elements other than carbon, hydrogen, oxygen, nitrogen, sulfur, and 
chlorine.
    (2) The M100 base fuel shall consist of 100 percent by volume 
chemical grade methanol.
    (3) The M85 base fuel is to contain 85 percent by volume chemical 
grade methanol, blended with 15 percent by volume gasoline base fuel 
meeting the gasoline base fuel specifications outlined in paragraph 
(b)(1) of this section. Manufacturers shall ensure the methanol 
compatibility of lubricating oils as well as fuel additives used in the 
gasoline portion of the M85 base fuel.
    (4) The methanol base fuels shall meet the specifications listed in 
Table F94-3.

               Table F94-3.--Methanol Base Fuel Properties              
M100:                                                                   
    Chemical Grade MeOH, vol%..................................      100
    Chlorine (as chlorides), wt%, max..........................   0.0001
    Water, wt%, max............................................      0.5
    Sulfur, wt%, max...........................................    0.002
M85                                                                     
    Chemical Grade MeOH, vol%,.................................       85
    Gasoline Base Fuel, vol%...................................       15
    Chlorine (as chlorides), wt%, max..........................   0.0001

[[Page 409]]

                                                                        
    Water, wt%, max............................................      0.5
    Sulfur, wt%, max...........................................    0.004
                                                                        

    (e) Ethanol Base Fuel. (1) The ethanol base fuel, E85, shall contain 
no elements other than carbon, hydrogen, oxygen, nitrogen, sulfur, 
chlorine, and copper.
    (2) The ethanol base fuel shall contain 85 percent by volume 
chemical grade ethanol, blended with 15 percent by volume gasoline base 
fuel that meets the specifications listed in paragraph (b)(1) of this 
section. Additives used in the gasoline component of E85 shall be 
ethanol-compatible.
    (3) The ethanol base fuel shall meet the specifications listed in 
Table F94-4.

               Table F94-4.--Ethanol Base Fuel Properties               
                                                                        
                                                                        
                                                                        
E85:                                                                    
    Chemical Grade EtOH, vol%, min.............................       85
    Gasoline Base Fuel, vol%...................................       15
    Chlorine (as chloride), wt%, max...........................   0.0004
    Copper, mg/L, max..........................................     0.07
    Water, wt%, max............................................      0.5
    Sulfur, wt%, max...........................................    0.004
                                                                        

    (f) Methane Base Fuel. (1) The methane base fuel is a gaseous motor 
vehicle fuel marketed commercially as compressed natural gas (CNG), 
whose primary constituent is methane.
    (2) The methane base fuel shall contain no elements other than 
carbon, hydrogen, oxygen, nitrogen, and sulfur. The fuel shall contain 
an odorant additive for leak detection purposes. The added odorant shall 
be used at a level such that, at ambient conditions, the fuel must have 
a distinctive odor potent enough for its presence to be detected down to 
a concentration in air of not over \1/5\ (one-fifth) of the lower limit 
of flammability. After addition of the odorant, the methane base fuel 
shall contain no more than 16 ppm sulfur by volume.
    (3) The methane base fuel shall meet the specifications listed in 
Table F94-5.

              Table F94-5.--Methane Base Fuel Specifications            
                                                                        
                                                                        
                                                                        
Methane, mole%, min..............................................   89.0
Ethane, mole%, max...............................................    4.5
Propane and higher HC, mole%, max................................    2.3
C6 and higher HC, mole%, max.....................................    0.2
Oxygen, mole%, max...............................................    0.6
Sulfur (including odorant additive) ppmv, max....................     16
Inert gases:                                                            
  Sum of CO2 and N2, mole%, max..................................    4.0
                                                                        

    (g) Propane Base Fuel. (1) The propane base fuel is a gaseous motor 
vehicle fuel, marketed commercially as liquified petroleum gas (LPG), 
whose primary constituent is propane.
    (2) The propane base fuel may contain no elements other than carbon, 
hydrogen, oxygen, nitrogen, and sulfur. The fuel shall contain an 
odorant additive for leak detection purposes. The added odorant shall be 
used at a level such that at ambient conditions the fuel must have a 
distinctive odor potent enough for its presence to be detected down to a 
concentration in air of not over \1/5\ (one-fifth) of the lower limit of 
flammability. After addition of the odorant, the propane base fuel shall 
contain no more than 120 ppm sulfur by weight.
    (3) The propane base fuel shall meet the specifications listed in 
Table F94-6.

             Table F94--6.--Propane Base Fuel Specifications            
                                                                        
                                                                        
                                                                        
Vapor pressure at 100-F, psig, max...............................    208
Evaporative temperature, 95%,  deg.F, max........................    -37
Propane, vol%, min...............................................   92.5
Propylene, vol%, max.............................................    5.0
Butane and heavier, vol%, max....................................    2.5
Residue-evaporation of 100mL, max, mL............................   0.05
Sulfur (including odorant additive) ppmw, max....................    123
                                                                        



Sec. 79.56  Fuel and fuel additive grouping system.

    (a) Manufacturers of fuels and fuel additives are allowed to satisfy 
the testing requirements in Secs. 79.52, 79.53, and 79.54 and the 
associated reporting requirements in Sec. 79.59 on an individual or 
group basis, provided that such 

[[Page 410]]

products meet the criteria in this section for enrollment in the same 
fuel/additive group. However, each manufacturer of a fuel or fuel 
additive must individually comply with the notification requirements of 
Sec. 79.59(b). Further, if a manufacturer elects to comply by 
participation in a group, each manufacturer continues to be individually 
subject to the information requirements of this subpart.
    (1) The use of the grouping provision to comply with Tier 1 and Tier 
2 testing requirements is voluntary. No manufacturer is prohibited from 
testing and submitting its own data for its own product registration, 
despite its qualification for membership in a particular group.
    (2) The only groups permitted are those established in this section.
    (b) Each manufacturer who chooses to enroll a fuel or fuel additive 
in a group of similar fuels and fuel additives as designated in this 
section may satisfy the registration requirements through a group 
submission of jointly-sponsored testing and analysis conducted on a 
product which is representative of all products in that group, provided 
that the group representative is chosen according to the specifications 
in this section.
    (1) The health effects information submitted by a group shall be 
considered applicable to all fuels and fuel additives in the group. A 
fuel or fuel additive manufacturer who has chosen to participate in a 
group may subsequently choose to perform testing of such fuel or fuel 
additive on an individual basis; however, until such independent 
registration information has been received and reviewed by EPA, the 
information initially submitted by the group on behalf of the 
manufacturer's fuel or fuel additive shall be considered applicable and 
valid for that fuel or fuel additive. It could therefore be used to 
support requirements for further testing under the provisions of Tier 3 
or to support regulatory decisions affecting that fuel or fuel additive.
    (2) Manufacturers are responsible for determining the appropriate 
groups for their products according to the criteria in this section and 
for enrolling their products into those groups under industry-sponsored 
or other independent brokering arrangements.
    (3) Manufacturers who enroll a fuel or fuel additive into a group 
shall share the applicable costs according to appropriate arrangements 
established by the group. The organization and administration of group 
functions and the development of cost-sharing arrangements are the 
responsibility of the participating manufacturers. If manufacturers are 
unable to agree on fair and equitable cost sharing arrangements and if 
such dispute is referred by one or more manufacturers to EPA for 
resolution, then the provisions in Sec. 79.56(c) (1) and (2) shall 
apply.
    (c) In complying with the registration requirements for a given fuel 
or fuel additive, notwithstanding the enrollment of such fuel or 
additive in a group, a manufacturer may make use of available 
information for any product which conforms to the same grouping criteria 
as the given product. If, for this purpose, a manufacturer wishes to 
rely upon the information previously submitted by another manufacturer 
(or group of manufacturers) for registration of a similar product (or 
group of products), then the previous submitter is entitled to 
reimbursement by the manufacturer for an appropriate portion of the 
applicable costs incurred to obtain and report such information. Such 
entitlement shall remain in effect for a period of fifteen years 
following the date on which the original information was submitted. 
Pursuant to Sec. 79.59(b)(4)(ii), the manufacturer who relies on 
previously-submitted registration data shall certify to EPA that the 
original submitter has been notified and that appropriate reimbursement 
arrangements have been made.
    (1) When private efforts have failed to resolve a dispute about a 
fair amount or method of cost-sharing or reimbursement for testing costs 
incurred under this subpart, then any party involved in that dispute may 
initiate a hearing by filing two signed copies of a request for a 
hearing with a regional office of the American Arbitration Association 
and mailing a copy of the request to EPA. A copy must also be sent to 
each person from whom the filing party seeks reimbursement or who seeks 
reimbursement from that 

[[Page 411]]

party. The information and fees to be included in the request for 
hearing are specified in 40 CFR 791.20(b) and (c).
    (2) Additional procedures and requirements governing the hearing 
process are those specified in 40 CFR 791.22 through 791.50, 791.60, 
791.85, and 791.105, excluding 40 CFR 791.39(a)(3) and 791.48(d).
    (d) Basis for Classification. (1) Rather than segregating fuels and 
fuel additives into separate groups, the grouping system applies the 
same grouping criteria and creates a single set of groups applicable 
both to fuels and fuel additives.
    (2) Fuels shall be classified pursuant to Sec. 79.56(e) into 
categories and groups of similar fuels and fuel additives according to 
the components and characteristics of such fuels in their uncombusted 
state. The classification of a fuel product must take into account the 
components of all bulk fuel additives which are listed in the 
registration application or basic registration data submitted for the 
fuel product.
    (3) Fuel additives shall be classified pursuant to Sec. 79.56(e) 
into categories and groups of similar fuels and fuel additives according 
to the components and characteristics of the respective uncombusted 
additive/base fuel mixture pursuant to Sec. 79.51(h)(1).
    (4) In determining the category and group to which a fuel or fuel 
additive belongs, impurities present in trace amounts shall be ignored 
unless otherwise noted. Impurities are those substances which are 
present through contamination or which remain in the fuel or additive 
naturally after processing is completed.
    (5) Reference Standards. (i) American Society for Testing and 
Materials (ASTM) standard D 4814-93a, ``Standard Specification for 
Automotive Spark-Ignition Engine Fuel'', used to define the general 
characteristics of gasoline fuels (paragraph (e)(3)(i)(A)(3) of this 
section) and ASTM standard D 975-93, ``Standard Specification for Diesel 
Fuel Oils'', used to define the general characteristics of diesel fuels 
(paragraph (e)(3)(ii)(A)(3) of this section) have been incorporated by 
reference.
    (ii) This incorporation by reference was approved by the Director of 
the Federal Register in accordance with 5 U.S.C. 552(a) and 1 CFR part 
51. Copies may be obtained from the American Society for Testing and 
Materials (ASTM), 1916 Race Street, Philadelphia, PA 19103. Copies may 
be inspected at U.S. EPA, OAR, 401 M Street SW., Washington, DC, 20460 
or at the Office of the Federal Register, 800 North Capitol Street NW., 
suite 700, Washington, DC.
    (e) Grouping Criteria. The grouping system is represented by a 
matrix of three fuel/additive categories within six specified fuel 
families (see Table F94-7, Grouping System for Fuels and Fuel 
Additives). Each category may include one or more groups. Within each 
group, a representative may be designated based on the criteria in this 
section and joint registration information may be developed and 
submitted for member fuels and fuel additives.

[[Page 412]]



                                               Table F94-7.--Grouping System for Fuels and Fuel Additives                                               
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                        Conventional Fuel Families                                   Alternative Fuel Families                          
                                 -----------------------------------------------------------------------------------------------------------------------
            Category                                                                                              Methane (CNG, LNG)                    
                                     Gasoline  (A)        Diesel  (B)        Methanol (C)         Ethanol (D)             (E)         Propane (LPG)  (F)
--------------------------------------------------------------------------------------------------------------------------------------------------------
Baseline........................  One group           One group           Two groups: (1)     One group           One group           One group         
                                   represented by      represented by      M100 group          (includes ethanol-  (includes both      represented by   
                                   gasoline base       diesel base fuel.   (includes           gasoline            CNG and LNG),       LPG base fuel.   
                                   fuel.                                   methanol-gasoline   formulations with   represented by                       
                                                                           formulations with   at least 50%        CNG base fuel.                       
                                                                           at least 96%        ethanol)                                                 
                                                                           methanol)           represented by                                           
                                                                           represented by      E85 base fuel.                                           
                                                                           M100 base fuel                                                               
                                                                           (2) M85 (includes                                                            
                                                                           methanol-gasoline                                                            
                                                                           formulations with                                                            
                                                                           50-95% methanol)                                                             
                                                                           represented by                                                               
                                                                           M85 base fuel.                                                               
Non-baseline....................  One group for each  One group for each  One group for each  One group for each  One group to        One group to      
                                   gasoline-           oxygen-             individual non-     individual non-     include methane     include propane  
                                   oxygenate blend     contributing        methanol, non-      ethanol, non-       formulations        formulations     
                                   or each gasoline-   compound or class   gasoline            gasoline            exceeding the       exceeding the    
                                   methanol/co-        of compounds; one   component and one   component and one   specified limit     specified limit  
                                   solvent blend;      group for each      group for each      group for each      for non-methane     for butane and   
                                   one group for       synthetic crude-    unique              unique              hydrocarbons.       higher           
                                   each synthetic      derived fuel.       combination of      combination of                          hydrocarbons.    
                                   crude-derived                           such components.    such components.                                         
                                   fuel.                                                                                                                
Atypical........................  One group for each  One group for each  One group for each  One group for each  One group for each  One group for each
                                   atypical element/   atypical element/   atypical element/   atypical element/   atypical element/   atypical element/
                                   characteristic,     characteristic,     characteristic,     characteristic,     characteristic,     characteristic,  
                                   or unique           or unique           or unique           or unique           or unique           or unique        
                                   combination of      combination of      combination of      combination of      combination of      combination of   
                                   atypical elements/  atypical elements/  atypical elements/  atypical elements/  atypical elements/  atypical elements/
                                   characteristics.    characteristics.    characteristics.    characteristics.    characteristics.    characteristics. 
--------------------------------------------------------------------------------------------------------------------------------------------------------


[[Page 413]]

    (1) Fuel Families. Each of the following six fuel families (Table 
F94-7, columns A-F) includes fuels of the type referenced in the name of 
the family as well as bulk and aftermarket additives which are intended 
for use in those fuels. When applied to fuel additives, the criteria in 
these descriptions refer to the associated additive/base fuel mixture, 
pursuant to Sec. 79.51(h)(1). One or more base fuel formulations are 
specified for each fuel family pursuant to Sec. 79.55.
    (i) The Gasoline Family includes fuels composed of more than 50 
percent gasoline by volume and their associated fuel additives. The base 
fuel for this family is specified in Sec. 79.55(b).
    (ii) The Diesel Family includes fuels composed of more than 50 
percent diesel fuel by volume and their associated fuel additives. The 
Diesel fuel family includes both Diesel #1 and Diesel #2 formulations. 
The base fuel for this family is specified in Sec. 79.55(c).
    (iii) The Methanol Family includes fuels composed of at least 50 
percent methanol by volume and their associated fuel additives. The M100 
and M85 base fuels are specified in Sec. 79.55(d).
    (iv) The Ethanol Family includes fuels composed of at least 50 
percent ethanol by volume and their associated fuel additives. The base 
fuel for this family is E85 as specified in Sec. 79.55(e).
    (v) The Methane Family includes compressed natural gas (CNG) and 
liquefied natural gas (LNG) fuels containing at least 50 mole percent 
methane and their associated fuel additives. The base fuel for the 
family is a CNG formulation specified in Sec. 79.55(f).
    (vi) The Propane Family includes propane fuels containing at least 
50 percent propane by volume and their associated fuel additives. The 
base fuel for this family is a liquefied petroleum gas (LPG) as 
specified in Sec. 79.55(g).
    (vii) A manufacturer seeking registration for formulation(s) which 
do not fit the criteria for inclusion in any of the fuel families 
described in this section shall contact EPA at the address in 
Sec. 79.59(a)(1) for further guidance in classifying and testing such 
formulation(s).
    (2) Fuel/Additive Categories. Fuel/additive categories (Table F94-7, 
rows 1-3) are subdivisions of fuel families which represent the degree 
to which fuels and fuel additives in the family resemble the base 
fuel(s) designated for the family. Three general category types are 
defined in this section. When applied to fuel additives, the criteria in 
these descriptions refer to the associated additive/base fuel mixture, 
pursuant to Sec. 79.51(h)(1).
    (i) Baseline categories consist of fuels and fuel additives which 
contain no elements other than those permitted in the base fuel for the 
respective fuel family and conform to specified limitations on the 
amounts of certain components or characteristics applicable to that fuel 
family.
    (ii) Non-Baseline Categories consist of fuels and fuel additives 
which contain no elements other than those permitted in the base fuel 
for the respective fuel family, but which exceed one or more of the 
limitations for certain specified components or characteristics 
applicable to baseline formulations in that fuel family.
    (iii) Atypical Categories consist of fuels and fuel additives which 
contain elements or classes of compounds other than those permitted in 
the base fuel for the respective fuel family or which otherwise do not 
meet the criteria for either baseline or non-baseline formulations in 
that fuel family. A fuel or fuel additive product having both non-
baseline and atypical characteristics pursuant to Sec. 79.56(e)(3), 
shall be considered to be an atypical product.
    (3) This section defines the specific categories applicable to each 
fuel family. When applied to fuel additives, the criteria in these 
descriptions refer to the associated additive/base fuel mixture, 
pursuant to Sec. 79.51(h)(1).
    (i) Gasoline Categories. (A) The Baseline Gasoline category contains 
gasoline fuels and associated additives which satisfy all of the 
following criteria:
    (1) Contain no elements other than carbon, hydrogen, oxygen, 
nitrogen, and/or sulfur.
    (2) Contain less than 1.5 percent oxygen by weight.
    (3) Sulfur concentration is limited to 1000 ppm per the 
specifications cited in the following paragraph.
    (4) Possess the physical and chemical characteristics of unleaded 
gasoline as

[[Page 414]]

specified by ASTM standard D 4814-93a (incorporated by reference, 
pursuant to paragraph (d)(5) of this section), in at least one Seasonal 
and Geographical Volatility Class.
    (5) Derived from conventional petroleum sources only.
    (B) The Non-Baseline Gasoline category is comprised of gasoline 
fuels and associated additives which conform to the specifications in 
paragraph (e)(3)(i)(A) of this section for the Baseline Gasoline 
category except that they contain 1.5 percent or more oxygen by weight 
and/or may be derived from synthetic crudes, such as those prepared from 
coal, shale and tar sands, heavy oil deposits, and other non-
conventional petroleum sources.
    (C) The Atypical Gasoline category is comprised of gasoline fuels 
and associated additives which contain one or more elements other than 
carbon, hydrogen, oxygen, nitrogen, and sulfur.
    (ii) Diesel Categories. (A) The Baseline Diesel category is 
comprised of diesel fuels and associated additives which satisfy all of 
the following criteria:
    (1) Contain no elements other than carbon, hydrogen, oxygen, 
nitrogen, and/or sulfur. Pursuant to 40 CFR 80.29, highway diesel sold 
after October 1, 1993 shall contain 0.05 percent or less sulfur by 
weight;
    (2) Contain less than 1.0 percent oxygen by weight;
    (3) Diesel formulations containing more than 0.05 percent sulfur by 
weight are precluded by 40 CFR 80.29;
    (4) Possess the characteristics of diesel fuel as specified by ASTM 
standard D 975-93 (incorporated by reference, pursuant to paragraph 
(d)(5) of this section); and
    (5) Derived from conventional petroleum sources only.
    (B) The Non-Baseline Diesel category is comprised of diesel fuels 
and associated additives which conform to the specifications in 
paragraph (e)(3)(ii)(A) of this section for the Baseline Diesel category 
except that they contain 1.0 percent or more oxygen by weight and/or may 
be derived from synthetic crudes, such as those prepared from coal, 
shale and tar sands, heavy oil deposits, and other non-conventional 
petroleum sources.
    (C) The Atypical Diesel category is comprised of diesel fuels and 
associated additives which contain one or more elements other than 
carbon, hydrogen, oxygen, nitrogen, and sulfur.
    (iii) Methanol Categories. (A) The Baseline Methanol category is 
comprised of methanol fuels and associated additives which contain at 
least 50 percent methanol by volume, no more than 4.0 percent by volume 
of substances other than methanol and gasoline, and no elements other 
than carbon, hydrogen, oxygen, nitrogen, sulfur, and/or chlorine. 
Baseline methanol shall contain no more than 0.004 percent by weight of 
sulfur or 0.0001 percent by weight of chlorine.
    (B) The Non-Baseline Methanol category is comprised of fuel blends 
which contain at least 50 percent methanol by volume, more than 4.0 
percent by volume of a substance(s) other than methanol and gasoline, 
and meet the baseline limitations on elemental composition in paragraph 
(e)(3)(iii)(A) of this section.
    (C) The Atypical Methanol category consists of methanol fuels and 
associated additives which do not meet the criteria for either the 
Baseline or the Non-Baseline Methanol category.
    (iv) Ethanol Categories. (A) The Baseline Ethanol category is 
comprised of ethanol fuels and associated additives which contain at 
least 50 percent ethanol by volume, no more than five (5) percent by 
volume of substances other than ethanol and gasoline, and no elements 
other than carbon, hydrogen, oxygen, nitrogen, sulfur, chlorine, and 
copper. Baseline ethanol formulations shall contain no more than 0.004 
percent by weight of sulfur, 0.0004 percent by weight of chlorine, and/
or 0.07 mg/L of copper.
    (B) The Non-Baseline Ethanol category is comprised of fuel blends 
which contain at least 50 percent ethanol by volume, more than five (5) 
percent by volume of a substance(s) other than ethanol and gasoline, and 
meet the baseline limitations on elemental composition in paragraph 
(e)(3)(iv)(A) of this section.
    (C) The Atypical Ethanol category consists of ethanol fuels and 
associated

[[Page 415]]

additives which do not meet the criteria for either the Baseline or the 
Non-Baseline Ethanol categories.
    (v) Methane Categories. (A) The Baseline Methane category is 
comprised of methane fuels and associated additives (including at least 
an odorant additive) which contain no elements other than carbon, 
hydrogen, oxygen, nitrogen, and/or sulfur, and contain no more than 20 
mole percent non-methane hydrocarbons. Baseline methane formulations 
shall not contain more than 16 ppm by volume of sulfur, including any 
sulfur which may be contributed by the odorant additive.
    (B) The Non-Baseline Methane category consists of methane fuels and 
associated additives which conform to the specifications in paragraph 
(e)(3)(v)(A) of this section for the Baseline Methane category except 
that they exceed 20 mole percent non-methane hydrocarbons.
    (C) The Atypical Methane category consists of methane fuels and 
associated additives which contain one or more elements other than 
carbon, hydrogen, oxygen, nitrogen, and/or sulfur, or exceed 16 ppm by 
volume of sulfur.
    (vi) Propane Categories. (A) The Baseline Propane category is 
comprised of propane fuels and associated additives (including at least 
an odorant additive) which contain no elements other than carbon, 
hydrogen, oxygen, nitrogen, and/or sulfur, and contain no more than 20 
percent by volume non-propane hydrocarbons. Baseline Propane 
formulations shall not contain more than 123 ppm by weight of sulfur, 
including any sulfur which may be contributed by the odorant additive.
    (B) The Non-Baseline Propane category consists of propane fuels and 
associated additives which conform to the specifications in paragraph 
(e)(3)(vi)(A) of this section for the Baseline Propane category, except 
that they exceed the 20 percent by volume limit for butane and higher 
hydrocarbons.
    (C) The Atypical Propane category consists of propane fuels and 
associated additives which contain elements other than carbon, hydrogen, 
oxygen, nitrogen, and/or sulfur, or exceed 123 ppm by weight of sulfur.
    (4) Fuel/Additive Groups. Fuel/additive groups are subdivisions of 
the fuel/additive categories. One or more group(s) are defined within 
each category in each fuel family according to the presence of differing 
characteristics in the fuel or additive/base fuel mixture. For each 
group, one formulation (either a base fuel or a member fuel or additive 
product) is chosen to represent all the member products in the group in 
any tests required under this subpart. The section which follows 
describes the fuel/additive groups.
    (i) Baseline Groups. (A) The Baseline Gasoline category comprises a 
single group. The gasoline base fuel specified in Sec. 79.55(b) shall 
serve as the representative of this group.
    (B) The Baseline Diesel category comprises a single group. The 
diesel base fuel specified in Sec. 79.55(c) shall serve as the 
representative of this group.
    (C) The Baseline Methanol category includes two groups: M100 and 
M85. The M100 group consists of methanol-gasoline formulations 
containing at least 96 percent methanol by volume. These formulations 
must contain odorants and bitterants (limited in elemental composition 
to carbon, hydrogen, oxygen, nitrogen, sulfur, and chlorine) for 
prevention of purposeful or inadvertent consumption. The M100 base fuel 
specified in Sec. 79.55(d) shall serve as the representative for this 
group. The M85 group consists of methanol-gasoline formulations 
containing at least 50 percent by volume but less than 96 percent by 
volume methanol. The M85 base fuel specified in Sec. 79.55(d) shall 
serve as the representative of this group.
    (D) The Baseline Ethanol category comprises a single group. The E85 
base fuel specified in Sec. 79.55(e) shall serve as the representative 
of this group.
    (E) The Baseline Methane category comprises a single group. The CNG 
base fuel specified in Sec. 79.55(f) shall serve as the representative 
of this group.
    (F) The Baseline Propane category comprises a single group. The LPG 
base fuel specified in Sec. 79.55(g) shall serve as the representative 
of this group.
    (ii) Non-Baseline Groups--(A) Non-Baseline Gasoline. The Non-
Baseline

[[Page 416]]

gasoline fuels and associated additives shall sort into groups according 
to the following criteria:
    (1) For gasoline fuel and additive products which contain 1.5 
percent oxygen by weight or more, a separate non-baseline gasoline group 
shall be defined by each oxygenate compound or methanol/co-solvent blend 
listed as a component in the registration application or basic 
registration data of any such fuel or additive.
    (i) Examples of oxygenates occurring in non-baseline gasoline 
formulations include ethanol, methyl tertiary butyl ether (MTBE), ethyl 
tertiary butyl ether (ETBE), tertiary amyl methyl ether (TAME), 
diisopropyl ether (DIPE), dimethyl ether (DME), tertiary amyl ethyl 
ether (TAEE), and any other compound(s) which increase the oxygen 
content of the gasoline formulation. A separate non-baseline gasoline 
group is defined for each such oxygenating compound.
    (ii) Each unique methanol and co-solvent combination (whether one, 
two, or more additional oxygenate compounds) used in a non-baseline fuel 
shall also define a separate group. An oxygenate compound used as a co-
solvent for methanol in a non-baseline gasoline formulation must be 
identified as such in its registration. If the oxygenate is not 
identified as a methanol co-solvent, then the compound shall be regarded 
by EPA as defining a separate non-baseline gasoline group. Examples of 
methanol/co-solvent combinations occurring in non-baseline gasoline 
formulations include methanol/isopropyl alcohol, methanol/butanol, and 
methanol with alcohols up to C8/octanol (Octamix).
    (iii) For each such group, the representative to be used in testing 
shall be a formulation consisting of the gasoline base fuel blended with 
the relevant oxygenate compound (or methanol/co-solvent combination) in 
an amount equivalent to the highest actual or recommended concentration-
in-use of the oxygenate (or methanol/co-solvent combination) recorded in 
the basic registration data of any member fuel or additive product. In 
the event that two or more products in the same group contain the same 
and highest amount of the oxygenate or methanol/co-solvent blend, then 
the representative shall be chosen at random for such candidate 
products.
    (2) An oxygenate compound or methanol/co-solvent combination to be 
blended with the gasoline base fuel for testing purposes shall be 
chemical-grade quality, at a minimum, and shall not contain a 
significant amount of other contaminating oxygenate compounds.
    (3) Separate non-baseline gasoline groups shall also be defined for 
gasoline formulations derived from each particular non-conventional 
petroleum source or process.
    (i) Such groups may include, but are not limited to, the following: 
coal-derived gasoline formulations; chemically-synthesized gasoline 
formulations (including those using recycled chemical/petrochemical 
products); tar sand-derived gasoline formulations; shale-derived 
gasoline formulations; and other types of soil-recovered products used 
in formulating gasolines.
    (ii) In any such group, the first product to be registered or to 
apply for EPA registration shall be the representative of that group. If 
two or more such products are registered or apply for first registration 
simultaneously, then the representative shall be chosen by a random 
method from among such candidate products.
    (4) Pursuant to Sec. 79.51(i), non-baseline gasoline products may 
belong to more than one fuel/additive group.
    (B) Non-Baseline Diesel. The Non-Baseline diesel fuels and 
associated additives shall sort into groups according to the following 
criteria:
    (1) For diesel fuel and additive products which contain 1.0 percent 
oxygen by weight or more, a separate non-baseline diesel group shall be 
defined by each individual alcohol or ether listed as a component in the 
registration application or basic registration data of any such fuel or 
additive. For each such group, the representative to be used in testing 
shall be a formulation consisting of the diesel base fuel blended with 
the relevant alcohol or ether in an amount equivalent to the highest 
actual or recommended concentration-in-use of the alcohol or ether 
recorded in the basic registration

[[Page 417]]

data of any member fuel or additive product.
    (2) A separate non-baseline diesel group is also defined for each of 
the following classes of oxygenating compounds: mixed nitroso- 
compounds; mixed nitro- compounds; mixed alkyl nitrates; mixed alkyl 
nitrites; peroxides; furans; mixed alkyl esters of plant origin; and 
mixed alkyl esters of animal origin. For each such group, the 
representative to be used in testing shall be formulated as follows:
    (i) From the class of compounds which defines the group, a 
particular oxygenate compound shall be chosen from among all such 
compounds recorded in the registration application or basic registration 
data of any fuel or additive in the group.
    (ii) The selected compound shall be the one recorded in any member 
product's registration application with the highest actual or 
recommended maximum concentration-in-use. This compound, when mixed into 
the diesel base fuel at the indicated maximum concentration, shall serve 
as the group representative.
    (iii) In the event that two or more oxygenate compounds in the 
relevant class have the highest recorded concentration-in-use, then the 
oxygenate compound to be used in the group representative shall be 
chosen at random from the qualifying candidate compounds.
    (3) A separate non-baseline diesel group shall also be defined for 
each diesel fuel derived from a particular synthetic petroleum source or 
process.
    (i) Such groups include, but shall not be limited to, the following: 
coal-derived diesel formulations; chemically-synthesized diesel 
formulations (including those using recycled chemical/petrochemical 
products); tar sand-derived diesel formulations; shale-derived diesel 
formulations; and other types of soil-recovered products used in 
formulating diesel fuel(s).
    (ii) In any such group, the first product to be registered or to 
apply for EPA registration shall be the representative of that group. If 
two or more products are registered or apply for first registration 
simultaneously, then the representative shall be chosen by a random 
method from among such candidate products.
    (4) Pursuant to Sec. 79.51(i), non-baseline diesel products may 
belong to more than one fuel/additive group.
    (C) Non-Baseline Methanol. The Non-Baseline methanol formulations 
are sorted into groups based on the non-methanol, non-gasoline 
component(s) of the blended fuel. Each such component occurring 
separately and each unique combination of such components shall define a 
separate group.
    (1) The representative of each such non-baseline methanol group 
shall be the group member with the highest percent by volume of non-
methanol, non-gasoline component(s).
    (2) In case two or more such members have the same and highest 
concentration of non-methanol, non-gasoline component(s), the 
representative of the group shall be chosen at random from among such 
equivalent member products.
    (D) Non-Baseline Ethanol. The Non-Baseline ethanol formulations are 
sorted into groups based on the non-ethanol, non-gasoline component(s) 
of the blended fuel. Each such component occurring separately and each 
unique combination of such components shall define a separate group.
    (1) The representative of each such non-baseline ethanol group shall 
be the group member with the highest percent by volume of non-ethanol, 
non-gasoline component(s).
    (2) In case two or more such members have the same and highest 
concentration of non-ethanol, non-gasoline component(s), the 
representative of the group shall be chosen at random from among such 
equivalent member products.
    (E) Non-Baseline Methane. The Non-Baseline methane category consists 
of one group. The group representative shall be the member fuel or fuel/
additive formulation containing the highest concentration-in-use of non-
methane hydrocarbons. If two or more member products have the same and 
the highest concentration-in-use, then the representative shall be 
chosen at random from such products.
    (F) Non-Baseline Propane. The Non-Baseline propane category consists 
of one group. The group representative

[[Page 418]]

shall be the member fuel or fuel/additive formulation containing the 
highest concentration-in-use of butane and higher hydrocarbons. If two 
or more products have the same and the highest concentration-in-use, 
then the representative shall be chosen at random from such products.
    (iii) Atypical groups.
    (A) As defined for each individual fuel family in Sec. 79.56(e)(3), 
fuels and additives meeting any one of the following criteria are 
considered atypical.
    (1) Gasoline Atypical fuels and additives contain one or more 
elements in addition to carbon, hydrogen, oxygen, nitrogen, and sulfur.
    (2) Diesel Atypical fuels and additives contain one or more element 
in addition to carbon, hydrogen, oxygen, nitrogen, and sulfur.
    (3) Methanol Atypical fuels and additives contain:
    (i) one or more element in addition to carbon, hydrogen, oxygen, 
nitrogen, sulfur, and chlorine, and/or
    (ii) sulfur in excess of 0.004 percent by weight, and/or
    (iii) chlorine in excess of 0.0001 percent by weight.
    (4) Ethanol Atypical fuels and additives contain:
    (i) one or more element in addition to carbon, hydrogen, oxygen, 
nitrogen, sulfur, chlorine, and copper, and/or
    (ii) sulfur in excess of 0.004 percent by weight, and/or
    (iii) contain chlorine (as chloride) in excess of 0.0004 percent by 
weight, and/or
    (iv) contain copper in excess of 0.07 mg/L.
    (5) Methane Atypical fuels and additives contain:
    (i) one or more element in addition to carbon, hydrogen, oxygen, 
nitrogen, and sulfur, and/or
    (ii) sulfur in excess of 16 ppm by volume.
    (6) Propane Atypical fuels and additives contain:
    (i) one or more element in addition to carbon, hydrogen, oxygen, 
nitrogen, and sulfur, and/or
    (ii) sulfur in excess of 123 ppm by weight.
    (B) General rules for sorting these atypical fuels and additives 
into separate groups are as follows:
    (1) Pursuant to Sec. 79.51(j), a given atypical product may belong 
to more than one atypical group.
    (2) Fuels and additives in different fuel families may not be 
grouped together, even if they contain the same atypical element(s) or 
other atypical characteristic(s).
    (3) A fuel or additive containing one or more atypical elements 
attached to a polymer compound must be sorted into a separate group from 
atypical fuels or fuel additives containing the same atypical element(s) 
in non-polymer form. However, the occurrence of a polymer compound which 
does not contain an atypical element does not affect the grouping of a 
fuel or additive.
    (C) Specific rules for sorting each family's atypical fuels and 
additives into separate groups, and for choosing each such group's 
representative for testing, are as follows:
    (1) A separate group is created for each atypical element (or other 
atypical characteristic) occurring separately, i.e., in the absence of 
any other atypical element or characteristic, in one or more fuels and/
or additives within a given fuel family.
    (i) Consistent with the basic grouping guidelines provided in 
Sec. 79.56(d), a fuel product which is classified as atypical because 
its basic registration data or application lists a bulk additive 
containing an atypical characteristic, may be grouped with that additive 
and/or with other fuels and additives containing the same atypical 
characteristic.
    (ii) Within a group of products containing only one atypical element 
or characteristic, the fuel or additive/base fuel mixture with the 
highest concentration-in-use or recommended concentration-in-use of the 
atypical element or characteristic shall be the designated 
representative of that group. In the event that two or more fuels or 
additive/base fuel mixtures within the group contain the same and 
highest concentration of the single atypical element or characteristic, 
then the group representative shall be selected by a random method from 
among such candidate products.
    (2) A separate group is also created for each unique combination of 
atypical elements (and/or other specified

[[Page 419]]

atypical characteristics) occurring together in one or more fuels and/or 
additives within a given fuel family.
    (i) Consistent with the basic grouping guidelines provided in 
Sec. 79.56(d), a fuel which is classified as atypical because its basic 
registration data lists one bulk additive containing two or more 
atypical characteristics, may be grouped with that additive and/or with 
other fuels and/or additives containing the same combination of atypical 
characteristics. Grouping of fuels containing more than one atypical 
additive shall be guided by provisions of Sec. 79.51(j).
    (ii) Within a group of such products containing a unique combination 
of two or more atypical elements or characteristics, the designated 
representative shall be the product within the group which contains the 
highest total concentration of the atypical elements or characteristics.
    (iii) In the event that two or more products within a given atypical 
group contain the same and highest concentration of the same atypical 
elements or characteristics then, among such candidate products, the 
designated representative shall be the product which, first, has the 
highest total concentration of metals, followed in order by highest 
total concentration of halogens, highest total concentration of other 
atypical elements (including sulfur concentration, as applicable), 
highest total concentration of polymers containing atypical elements, 
and, lastly, highest total concentration of oxygen.
    (iv) If two or more products have the same and highest concentration 
of the variable identified in the preceding paragraph, then, among such 
products, the one with the greatest concentration of the next highest 
variable on the list shall be the group representative.
    (v) This decision-making process shall continue until a single 
product is determined to be the representative. If two or more products 
remain tied at the end of this process, then the representative shall be 
chosen by a random method from among such remaining products.



Sec. 79.57  Emission generation.

    This section specifies the equipment and procedures that must be 
used in generating the emissions which are to be subjected to the 
characterization procedures and/or the biological tests specified in 
Secs. 79.52(b) and 79.53 of these regulations. When applicable, they may 
also be required in conjunction with testing under Secs. 79.54 and 
79.58(c). Additional requirements concerning emission generation, 
delivery, dilution, quality control, and safety practices are outlined 
in Sec. 79.61.
    (a) Vehicle and engine selection criteria. (1) All vehicles and 
engines used to generate emissions for testing a fuel or additive/fuel 
mixture must be new (i.e., never before titled) and placed into the 
program with less than 500 miles on the odometer or 12 hours on the 
engine chronometer. The vehicles and engines shall be unaltered from the 
specifications of the original equipment manufacturer.
    (2) The vehicle/engine type, vehicle/engine class, and vehicle/
engine subclass designated to generate emissions for a given fuel or 
additive shall be the same type, class, and subclass which, over the 
previous three years, has consumed the most gallons of fuel in the fuel 
family applicable to the given fuel or additive. No distinction shall be 
made between light-duty vehicles and light-duty trucks for purposes of 
this classification.
    (3) Within this vehicle/engine type, class, and subclass, the 
specific vehicles and engines acceptable for emission generation are 
those that represent the most common fuel metering system and the most 
common of the most important emission control system devices or 
characteristics with respect to emission reduction performance for the 
model year in which testing begins. These vehicles will be determined 
through a survey of the previous model year's vehicle/engine sales 
within the given subclass. These characteristics shall include, but need 
not be limited to, aftertreatment device(s), fuel aspiration, air 
injection, exhaust gas recirculation, and feedback type.
    (4) Within the applicable subclass, the five highest selling 
vehicle/engine models that contain the most common such equipment and 
characteristics

[[Page 420]]

shall be determined. Any of these five models of the current model year 
(at the time testing begins) may be selected for emission generation.
    (i) If one or more of the five models is not available for the 
current model year, the choice of model for emission generation shall be 
limited to those remaining among the five.
    (ii) If fewer than five models of the given vehicle/engine type are 
available for the current model year, all such models shall be eligible.
    (5) When the fuel or fuel additive undergoing testing is not 
commonly used or intended to be used in the vehicle/engine types 
prescribed by this selection procedure, or when rebuilding or alteration 
is required to obtain a suitable vehicle/engine for emission generation, 
the manufacturer may submit a request to EPA for a modification in test 
procedure requirements. Any such request must include objective test 
results which support the claim that a more appropriate vehicle/engine 
type is needed as well as a suggested substitute vehicle/engine type. 
The vehicle/engine selection in this case shall be approved by EPA prior 
to the start of testing.
    (6) Once a particular model has been chosen on which to test a fuel 
or additive product, all mileage accumulation and generation of 
emissions for characterization and biological testing of such product 
shall be conducted on that same model.
    (i) If the initial test vehicle/engine fails or must be replaced for 
any reason, emission generation shall continue with a second vehicle/
engine which is identical to, or resembles to the greatest extent 
possible, the initial test vehicle/engine. If more than one replacement 
vehicle/engine is necessary, all such vehicles/engines shall be 
identical, or resemble to the greatest extent possible, the initial test 
vehicle/engine.
    (ii) Manufacturers are encouraged to obtain, at the start of a test 
program, more than one emission generation vehicle/engine of the 
identical model, to ensure the availability of back-up emission 
generator(s). All backup vehicles/engines must be conditioned and must 
have their emissions fully characterized, as done for the initial test 
vehicle/engine, prior to their use as emission generators for biological 
testing. Alternating between such vehicles/engines regularly during the 
course of testing is permissible and advisable, particularly to allow 
regular maintenance on such vehicles/engines during prolonged health 
effects testing.
    (b) Vehicle/engine operation and maintenance. (1) For the purpose of 
generating combustion emissions from a fuel or additive/base fuel 
mixture for which the relevant class is light duty, either a light-duty 
vehicle shall be operated on a chassis dynamometer or a light-duty 
engine shall be operated on an engine dynamometer. When the relevant 
class is heavy duty, the emissions shall be generated on a heavy-duty 
engine operated on an engine dynamometer. In both cases, the vehicle or 
engine model shall be selected as described in paragraph (a) of this 
section and shall have all applicable fuel and emission control systems 
intact.
    (2) Except as provided in Sec. 79.51(h)(2)(iii), the fuel or 
additive/base fuel mixture being tested shall be used at all times 
during operation of the test vehicle or engine. No other fuels or 
additives shall be used in the test vehicle or engine once mileage 
accumulation has begun until emission generation for emission 
characterization and biological testing purposes is completed.
    (3) Scheduled and unscheduled vehicle/engine maintenance.
    (i) During emission generation, vehicles and engines must be 
maintained in good condition by following the recommendations of the 
original equipment manufacturer (OEM) for scheduled service and parts 
replacement, with repairs performed only as necessary. Modifications, 
adjustments, and maintenance procedures contrary to procedures found in 
40 CFR part 86 for the maintenance of test vehicles/engines or performed 
solely for the purpose of emissions improvement are not allowed.
    (ii) If unscheduled maintenance becomes necessary, the vehicle or 
engine must be repaired to OEM specifications, using OEM or OEM-approved 
parts. In addition, the tester is required to measure the basic 
emissions

[[Page 421]]

pursuant to Sec. 79.52(b)(2)(i) after the unscheduled maintenance and 
before resuming testing to ensure that the post-maintenance emissions 
shall be within 20 percent of pre-maintenance emissions levels. If the 
basic emissions cannot be brought within 20 percent of their previous 
levels, then the manufacturer shall restart the emissions 
characterization and health testing of its products combustion emissions 
using a new vehicle/engine.
    (c) Mileage accumulation. (1) A vehicle/engine break-in period is 
required prior to generating emissions for characterization and/or 
biological testing under this subpart. The required mileage accumulation 
may be accomplished on a test track, on the street, on a dynamometer, or 
using any other conventionally accepted method.
    (2) Vehicles to be used in the evaluation of baseline and non-
baseline fuels and fuel additives shall accumulate 4,000 miles prior to 
emission testing. Engines to be used in the evaluation of baseline and 
non-baseline fuels and fuel additives shall accumulate 125 hours of 
operation on an engine dynamometer prior to emission testing.
    (3) When the test formulation is classified as an atypical fuel or 
fuel additive formulation (pursuant to definitions in 
Sec. 79.56(e)(4)(iii)), the following additional mileage accumulation 
requirements apply:
    (i) The test vehicle/engine must be operated for a minimum of 4,000 
vehicle miles or 125 hours of engine operation.
    (ii) Thereafter, at intervals determined by the tester, all emission 
fractions (i.e., vapor, semi-volatile, and particulate) shall be sampled 
and analyzed for the presence and amount of the atypical element(s) and/
or other atypical constituents. Pursuant to paragraph (d) of this 
section, the sampled emissions must be generated in the absence of an 
intact aftertreatment device. Immediately before the samples are taken, 
a brief warmup period (at least ten miles or the engine equivalent) is 
required.
    (iii) Mileage accumulation shall continue until either 50 percent or 
more of the mass of each atypical element (or other atypical 
constituent) entering the engine can be measured in the exhaust 
emissions (all fractions combined), or the vehicle/engine has 
accumulated mileage (or hours) equivalent to 40 percent of the average 
useful life of the applicable vehicle/engine class (pursuant to 
regulations in 40 CFR part 86). For example, the maximum mileage 
required for light-duty vehicles is 40 percent of 100,000 miles (i.e., 
40,000 miles), while the maximum time of operation for heavy-duty 
engines is the equivalent of 40 percent of 290,000 miles (i.e., the 
equivalent in engine hours of 116,000 miles).
    (iv) When either condition in paragraph (c)(3)(iii) of this section 
has been reached, additional emission characterization and biological 
testing of the emissions may begin.
    (d) Use of exhaust aftertreatment devices. (1) If the selected test 
vehicle/engine, as certified by EPA, does not come equipped with an 
emissions aftertreatment device (such as a catalyst or particulate 
trap), such device shall not be used in the context of this program.
    (2) Except as provided in paragraph (d)(3) of this section for 
certain specialized additives, the following provisions apply when the 
test vehicle/engine, as certified by EPA, comes equipped with an 
emissions aftertreatment device.
    (i) For mileage accumulation:
    (A) When the test formulation does not contain any atypical elements 
(pursuant to definitions in Sec. 79.56(e)(4)(iii)), an intact 
aftertreatment device must be used during mileage accumulation.
    (B) When the test formulation does contain atypical elements, then 
the manufacturer may choose to accumulate the required mileage using a 
vehicle/engine equipped with either an intact aftertreatment device or 
with a non-functional aftertreatment device (e.g., a blank catalyst 
without its catalytic wash coat). In either case, sampling and analysis 
of emissions for measurement of the mass of the atypical element(s) (as 
described in Sec. 79.57(c)(3)) must be done on emissions generated with 
a non-functional (blank) aftertreatment device.
    (1) If the manufacturer chooses to accumulate mileage without a 
functional aftertreatment device, and if the manufacturer wishes to do 
this outside of a laboratory/test track setting, then a

[[Page 422]]

memorandum of exemption for product testing must be obtained by applying 
to the Director of the Field Operations and Support Division (see 
Sec. 79.59(a)(1)).
    (2) [Reserved]
    (ii) For Tier 1 (Sec. 79.52), the total set of requirements for the 
characterization of combustion emissions (Sec. 79.52(b)) must be 
completed two times, once using emissions generated with the 
aftertreatment device intact and a second time with the aftertreatment 
device rendered nonfunctional or replaced with a non-functional 
aftertreatment device as described in paragraph (d)(2)(i)(B) of this 
section.
    (iii) For Tier 2 (Sec. 79.53), the standard requirements for 
biological testing of combustion emissions shall be conducted using 
emissions generated with a non-functioning aftertreatment device as 
described in paragraph (d)(2)(i)(B) of this section.
    (iv) For alternative Tier 2 requirements (Sec. 79.58(c)) or Tier 3 
requirements (Sec. 79.54) which may be prescribed by EPA, the use of 
functional or nonfunctional aftertreatment devices shall be specified by 
EPA as part of the test guidelines.
    (v) In the case where an intact aftertreatment device is not in 
place, all other manufacturer-specified combustion characteristics 
(e.g., back pressure, residence time, and mixing characteristics) of the 
altered vehicle/engine shall be retained to the greatest extent 
possible.
    (3) Notwithstanding paragraphs (d)(1) and (d)(2) of this section, 
when the subject of testing is a fuel additive specifically intended to 
enhance the effectiveness of exhaust aftertreatment devices, the related 
aftertreatment device may be used on the emission generation vehicle/
engine during all mileage accumulation and testing.
    (e) Generation of combustion emissions--(1) Generating combustion 
emissions for emission characterization. (i) Combustion emissions shall 
be generated according to the exhaust emission portion of the Federal 
Test Procedure (FTP) for the certification of new motor vehicles, found 
in 40 CFR part 86, subpart B for light-duty vehicles/engines, and 
subparts D, M and N for heavy-duty vehicles/engines. The Urban 
Dynamometer Driving Schedule (UDDS), pursuant to 40 CFR part 86, 
appendix I(a), shall apply to light-duty vehicles/engines and the Engine 
Dynamometer Driving Schedule (EDS), pursuant to 40 CFR part 86, appendix 
I(f)(2), shall apply to heavy-duty vehicles/engines. The motoring 
portion of the heavy-duty test cycle may be eliminated, at the 
manufacturer's option, for the generation of emissions.
    (A) For light-duty engines operated on an engine dynamometer, the 
tester shall determine the speed-torque equivalencies (``trace'') for 
its test engine from valid FTP testing performed on a chassis 
dynamometer, using a test vehicle with an engine identical to that being 
tested. The test engine must then be operated under these speed and 
torque specifications to simulate the FTP cycle.
    (B) Special procedures not included in the FTP may be necessary in 
order to characterize emissions from fuels and fuel additives containing 
atypical elements or to collect some types of emissions (e.g., 
particulate emissions from light-duty vehicles/engines, semi-volatile 
emissions from both light-duty and heavy-duty vehicles/engines). Such 
alterations to the FTP are acceptable.
    (ii) Pursuant to Sec. 79.52(b)(1)(i) and Sec. 79.57(d)(2)(ii), 
emission generation and characterization must be repeated three times 
when the selected vehicle/engine is normally operated without an 
emissions aftertreatment device and six times when the selected vehicle/
engine is normally operated with an emissions aftertreatment device. In 
the latter case, the emission generation and characterization process 
shall be repeated three times with the intact aftertreatment device in 
place and three times with a non-functioning (blank) aftertreatment 
device in place.
    (iii) From both light-duty and heavy-duty vehicles/engines, samples 
of vapor phase, semi-volatile phase, and particulate phase emissions 
shall be collected, except that semi-volatile phase, and particulate 
emissions need not be sampled for fuels and additives in the methane and 
propane families (pursuant to Sec. 79.56(e)(1)(v) and (vi)). The number 
and type of samples to be collected and separately analyzed during one 
emission generation/characterization process are as follows:

[[Page 423]]

    (A) In the case of combustion emissions generated from light-duty 
vehicles/engines, the samples consist of three bags of vapor emissions 
(one from each segment of the light-duty exhaust emission cycle) plus 
one sample of particulate-phase emissions and one sample of semi-
volatile-phase emissions (collected over all segments of the exhaust 
emission cycle). If the mass of particulate emissions or semi-volatile 
emissions obtained during one driving cycle is not sufficient for 
characterization, then the driving cycle may be performed again and the 
extracted fractions combined prior to chemical analysis. Particulate-
phase emissions shall not be combined with semi-volatile-phase 
emissions.
    (B) In the case of combustion emissions generated from heavy-duty 
engines, the samples consist of one sample of each emission phase 
(vapor, particulate, and semi-volatile) collected over the entire cold-
start cycle and a second sample of each such phase collected over the 
entire hot-start cycle (see 40 CFR 86.334 through 86.342).
    (iv) Emission collection and storage. (A) Vapor phase emissions 
shall be collected and stored in Tedlar bags for subsequent chemical 
analysis. Storage conditions are specified in Sec. 79.52(b)(2).
    (B) Particulate phase emissions shall be collected on a particulate 
filter (or more than one, if required) using methods described in 40 CFR 
86.1301 through 86.1344. These methods, ordinarily applied only to 
heavy-duty emissions, are to be adapted and used for collection of 
particulates from light-duty vehicles/engines, as well. The particulate 
matter may be stored on the filter in a sealed container, or the soluble 
organic fraction may be extracted and stored in a separate sealed 
container. Both the particulate and the extract shall be shielded from 
ultraviolet light and stored at -20  deg.C or less. Particulate 
emissions shall be tested no later than six months from the date they 
were generated.
    (C) Semi-volatile emissions shall be collected immediately 
downstream from the particulate collection filters using porous polymer 
resin beds, or their equivalent, designed for their capture. The soluble 
organic fraction of semi-volatile emissions shall be extracted 
immediately and tested within six months of being generated. The extract 
shall be stored in a sealed container which is shielded from ultraviolet 
light and stored at -20  deg.C or less.
    (D) Particulate and semi-volatile phase emission collection, 
handling and extraction methods shall not alter the composition of the 
collected material, to the extent possible.
    (v) Additional requirements for combustion emission sampling, 
storage, and characterization are specified in Sec. 79.52(b).
    (2) Generating whole combustion emissions for biological testing. 
(i) Biological tests requiring whole combustion emissions shall be 
conducted using emissions generated from the test vehicle or engine 
operated in general accordance with the FTP procedures cited in this 
section. The emissions shall be generated continuously throughout the 
animal exposure periods, diluted by an amount appropriate for the test 
being performed as specified in Sec. 79.61(d)(3), passed through a 
mixing chamber, and routed to the biological test chamber.
    (ii) Light-duty test vehicles/engines shall be operated over the 
Urban Dynamometer Driving Schedule (or equivalent engine dynamometer 
trace, per paragraph (e)(1)(i)(A) of this section) and heavy-duty test 
engines shall be operated over the Engine Dynamometer Schedule (see 40 
CFR part 86, appendix I).
    (A) The tolerances of the driving cycle shall be two times those of 
the Federal Test Procedure and must be met 95 percent of the time.
    (B) The driving cycle shall be repeated as many times as required 
for the biological test session.
    (C) Light-duty dynamometers shall be calibrated prior to the start 
of a biological test (40 CFR 86.118-78), verified weekly (40 CFR 86.118-
78), and recalibrated as required. Heavy-duty dynamometers shall be 
calibrated and checked prior to the start of a biological test (40 CFR 
86.1318-84), recalibrated every two weeks (40 CFR 86.1318-84(a)) and 
checked as stated in 40 CFR 86.1318-84(b) and (c).
    (D) The fuel reservoir for the test vehicle/engine shall be large 
enough to operate the test vehicle/engine

[[Page 424]]

throughout the daily biological exposure period, avoiding the need for 
refueling during testing.
    (iii) An apparatus to integrate the large concentration swings 
typical of transient-cycle exhaust is to be used between the FTP-
Constant Volume Sampler (CVS) source of emissions and the exposure 
chamber containing the animal test cage(s). The purpose of such 
apparatus is to decrease the variability of the biological exposure 
atmosphere.
    (A) A large mixing chamber is suggested for this purpose. The mixing 
chamber would be charged from the CVS at a constant rate determined by 
the exposure chamber purge rate. Flow to the exposure chamber would 
begin at the conclusion of the initial transient cycle with the 
associated mixing chamber charge.
    (B) A potential alternative apparatus is a mini-diluter (see, for 
example, AIGER/CRADA, February, 1994 in Sec. 79.57(g)).
    (C) The mixing chamber (or any alternative emission moderation 
apparatus) must function such that the average concentration of total 
hydrocarbons leaving the apparatus shall be within 10 percent of the 
average concentration of hydrocarbons entering the chamber.
    (iv) Emission dilution. (A) Dilution air can be pre-dried to lower 
the relative humidity, thus permitting a lower dilution rate and a 
higher concentration of hydrocarbons to be achieved without condensation 
of water vapor.
    (B) With gasoline fuels, a minimum dilution ratio of about 1:5 raw 
exhaust (dewpoint about 125  deg.F) with dry, clean filtered air is 
required to reduce the water concentration to a dewpoint of about 68 
deg.F. The minimum dilution ratio (maximum exhaust flow rate) occurs at 
about 200 seconds into the UDDS transient driving cycle. Larger minimum 
dilution ratios are required if the dilution air includes water vapor. 
However, the minimum dilution ratio will vary with fuel composition. 
Fuels which generate greater engine exhaust water concentrations (e.g., 
alcohol and natural gas fuels) will require greater initial dilutions. 
Heated transfer ducts or tubing can be used to avoid water condensation 
in much of the system, but the mixing chamber described in paragraph 
(e)(2)(iii) of this section will generally be at or near laboratory 
temperature, and CVS dilution will have to be adequate to assure that 
the cumulative dew point in the chamber remains below laboratory 
temperature at all times (further guidance on this topic may be found in 
Black and Snow, 1994 in Sec. 79.57(g)).
    (C) After the initial exhaust dilution to preserve the character of 
the exhaust, the exhaust stream can be further diluted in the mixing 
chamber (and/or after leaving the chamber) to achieve the desired 
biological exposure concentrations.
    (v) Verification procedures. (A) The entire system used to dilute 
and transport whole combustion emissions (i.e., from exhaust pipe to 
outlet in the biological testing chamber) shall be verified before any 
animal exposures begin, and verified at least weekly during testing. 
(See procedures at 40 CFR 86.119-90 for light-duty vehicles and 
Sec. 86.1319-90 for heavy-duty engines.) Verification testing shall be 
accomplished by introducing a known sample at the end of the vehicle/
engine exhaust pipe into the dilution system and measuring the amount 
exiting the system. For example, an injected hydrocarbon sample could be 
detected with a gas chromatograph (GC) and flame ionization detector 
(FID) to determine the recovery factor.
    (B) Verification of the integrity of the mixing chamber (or 
alternative apparatus) shall be determined before animal exposures begin 
and at least weekly thereafter. Composite values for weight percent 
total hydrocarbons shall be determined for the test vehicle/engine's 
dilute exhaust stream entering and exiting the mixing chamber apparatus. 
These values must be within 10 percent of each other.
    (vi) Emission exposure quality control. (A) The tester shall 
incorporate the additional quality assurance and safety procedures 
outlined in Sec. 79.61(d) to control variability of emissions during the 
generation of exposure emissions during health effect testing.
    (B) These procedures include requirements that the mean exposure 
concentration in the inhalation test chamber shall be within 10 percent 
of the

[[Page 425]]

target concentration (established in the developmental phase of testing) 
on 90 percent or more of exposure days and that daily monitoring of CO, 
CO2, NOX, SOX, and total hydrocarbons in the exposure 
chamber shall be required. Analysis of the particle size distribution 
shall also be performed to establish the stability and consistency of 
particle size distribution in the test exposure.
    (C) The testing facility shall allow an audit of its premises, the 
qualifications, e.g., curriculum vitae, of its staff assigned to 
testing, and the specimens and records of the testing for registration 
purposes (as specified in Sec. 79.60).
    (vii) In order to allow for unforeseen problems with the emission 
generation or dilution equipment, emission generation may be interrupted 
for up to four hours on a maximum of two occasions in any four-week 
period of testing. The amount of time for which emission generation was 
interrupted shall subsequently be added after the equipment problem is 
corrected. If the equipment problem causes more than four consecutive 
hours of emission generation to be interrupted, or if more than two such 
occasions occurs in any four-week period during testing, the interrupted 
tests shall be void. Testers shall be aware of concerns for backup 
vehicles/engines cited in paragraph (a)(7)(ii) of this section.
    (3) Generating particulate and semi-volatile emissions for 
biological testing. (i) Salmonella mutagenicity testing, pursuant to 
Sec. 79.68, shall be conducted on extracts of the particulate and semi-
volatile emission phases separately. These emissions shall be generated 
by operating the test vehicle/engine over the appropriate FTP driving 
cycle (see paragraph (e)(2)(ii) of this section) and collected and 
analyzed according to methods described in 40 CFR 86.1301 through 1344 
(further information on this subject may be found in Perez, et al. CRC 
Report No. 551, 1987 listed in Sec. 79.57(g)).
    (A) Particulate emissions shall be collected on particulate filters 
and extracted from the collection equipment for use in biological tests. 
The particulate emissions from all segments of the FTP or from multiple 
FTP cycles may be collected on one or more filters, as necessary. The 
time spent collecting sufficient quantities of the test substances in 
emissions samples will vary, depending on the emission characteristics 
of the engine and fuel or additive/base fuel mixture and on the 
requirements of the biological test protocol.
    (B) Semi-volatile emissions shall be collected immediately 
downstream from the particulate collection filters using porous polymer 
resin beds, or their equivalent, designed for their capture. Semi-
volatile phase emissions shall be collected on one apparatus. The time 
spent collecting sufficient quantities of the test substances in 
emissions samples will vary, depending on the emission characteristics 
of the engine and fuel or additive/base fuel mixture and on the 
requirements of the biological test protocol.
    (ii) The extraction method shall be determined by the specifications 
of the biological test for which the emissions are used.
    (iii) Particulate and semi-volatile emission storage requirements 
are as specified in Sec. 79.57(e)(1)(iv).
    (iv) Particulate and semi-volatile phase emission collection, 
handling and extraction methods shall not alter the composition of the 
collected material, to the extent possible.
    (v) Particulate emissions shall not be combined with semi-volatile 
phase emissions.
    (f) Generation of evaporative emissions for characterization and 
biological testing. (1) Except as provided in paragraph (f)(5) of this 
section, an evaporative emissions generator shall be used to volatilize 
samples of a fuel or additive/base fuel mixture for evaporative 
emissions characterization and biological testing. Emissions shall be 
collected and sampled using equipment and methods appropriate for use 
with the compounds being characterized and the requirements of the 
emission characterization analysis. In the case of potentially explosive 
test substance concentrations, care must be taken to avoid generating 
explosive atmospheres. The tester is referred to Sec. 79.61(d)(8) for 
considerations involving explosivity.
    (2) Evaporative Emissions Generator (EEG) Description. An EEG is a 
fuel tank or vessel to which heat is applied

[[Page 426]]

causing a portion of the fuel to evaporate at a desired rate. The 
manufacturer has flexibility in designing an EEG for testing a 
particular fuel or fuel additive. The sample used to generate emissions 
in the EEG shall be renewed at least daily.
    (i) The evaporation chamber shall be made from materials compatible 
with the fuels and additives being tested and shall be equipped with a 
drain.
    (ii) The chamber shall be filled to 40 5 percent of its 
interior volume with the fuel or additive/base fuel mixture being 
tested, with the remainder of the volume containing air.
    (iii) The concentration of the evaporated fuel or additive/base fuel 
mixture in the vapor space of the evaporation chamber during the time 
emissions are being withdrawn for testing shall not vary by more than 10 
percent from the equilibrium concentration in the vapor space of 
emissions generated from the fresh fuel or additive/base fuel mixture in 
the chamber.
    (A) During the course of a day's emission generation period, the 
level of fuel in the EEG shall be maintained to within 7 percent of its 
height at the start of the daily exposure period.
    (B) The fuel used in the EEG shall be drained at the end of each 
daily exposure. The EEG shall be refilled with a fresh supply of the 
test formulation before the start of each daily exposure.
    (C) The vapor space of the evaporation chamber shall be well mixed 
throughout the time emissions are being withdrawn for testing.
    (iv) The size of the evaporation chamber shall be determined by the 
rate at which evaporative emissions shall be needed in the test animal 
exposure chambers and the rate at which the fuel or the additive/base 
fuel mixture evaporates. The rate of evaporative emissions may be 
adjusted by altering the size of the EEG or by using one or more 
additional EEG(s). Emission rate modifications shall not be adjusted by 
temperature control or pressure control.
    (v) The temperature of the fuel or additive/base fuel mixture in the 
evaporation chamber shall be 130  deg.F5 deg.F. The vapors 
shall maintain this temperature up to the point in the system where the 
vapors are diluted.
    (vi) The pressure in the vapor space of the evaporation chamber and 
the dilution and sampling apparatus shall stay within 10 percent of 
ambient atmospheric pressure.
    (vii) There shall be no controls or equipment on the evaporation 
chamber system that change the concentration or composition of the 
vapors generated for testing.
    (viii) Manufacturers shall perform verification testing of 
evaporative emissions in a manner analogous to the verification testing 
performed for combustion emissions.
    (3) For biological testing, vapor shall be withdrawn from the EEG at 
a constant rate, diluted with air as required for the particular study, 
and conducted immediately to the biological testing chamber(s) in a 
manner similar to the method used in Sec. 79.57(e), excluding the mixing 
chamber therein. The rate of emission generation shall be high enough to 
supply the biological exposure chamber with sufficient emissions to 
allow for a minimum of fifteen air changes per exposure chamber per 
hour. Interruption of evaporative emissions exposures during biological 
testing for more than four consecutive hours, or on more than two 
separate occasions within a four-week period for less than four 
consecutive hours, shall cause the affected test(s) to be void.
    (4) For characterization of evaporative emissions, samples of 
equilibrated emissions to the vapor space of the EEG shall be withdrawn 
into Tedlar bags, then stored and analyzed as specified in 
Sec. 79.52(b).
    (5) A manufacturer (or group of manufacturers) may submit to EPA a 
request for approval of an alternative method of generating evaporative 
emissions for use in emission characterization and biological tests 
required under this subpart.
    (i) To be approved by EPA, the request must fully explain the 
rationale for the proposed method as well as the technical procedures, 
quality control, and safety precautions to be used, and must demonstrate 
that the proposed method will meet the following criteria:
    (A) The emission mixture generated by the proposed procedures must 
be reasonably similar to the equilibrium

[[Page 427]]

composition of the vapor which occurs in the vehicle fuel tank head 
space when the subject fuel or additive/base fuel mixture is in use and 
near-maximum in-use temperatures are encountered.
    (B) The emissions mixture generated by the proposed method must be 
sufficiently concentrated to provide adequate exposure levels in the 
context of the required toxicologic tests.
    (C) The proposed method must include procedures to ensure that the 
emissions delivered to the biologic exposure chambers will provide a 
reasonably constant exposure atmosphere over time.
    (ii) If EPA approves the request, EPA will place in the public 
record a copy of the request, together with all supporting procedural 
descriptions and justifications, and will notify the public of its 
availability by publishing a notice in the Federal Register.
    (g) References. For additional background information on the 
emission generation procedures outlined in this paragraph (g), the 
following references may be consulted. Additional references can be 
found in Sec. 79.61(f).
    (1) AIGER/CRADA (American Industry/Government Emissions Research 
Cooperative Research and Development Agreement, ``Specifications for 
Advanced Emissions Test Instrumentation'' AIGER PD-94-1, Revision 5.0, 
February, 1994
    (2) Black, F. and R. Snow, ``Constant Volume Sampling System Water 
Condensation'' SAE #940970 in ``Testing and Instrumentation'' SP-1039, 
Society of Automotive Engineers, Feb. 28-Mar. 3, 1994.
    (3) Perez, J.M., Jass, R.E., Leddy, D.G., eds. ``Chemical Methods 
for the Measurement of Unregulated Diesel Emissions (CRC-APRAC Project 
No. CAPI-1-64), Coordinating Research Council, CRC Report No. 551, 
August, 1987.
    (4) Phalen, R.F., ``Inhalation Studies: Foundations and 
Techniques'', CRC Press, Inc., Boca Raton, Florida, 1984.



Sec. 79.58  Special provisions.

    (a) Relabeled Additives. Sellers of relabeled additives (pursuant to 
Sec. 79.50) are not required to comply with the provisions of 
Sec. 79.52, 79.53 or 79.59, except that such sellers are required to 
comply with Sec. 79.59(b).
    (b) Low Vapor Pressure Fuels and Additives. Fuels which are not 
designated as ``evaporative fuels'' and fuel additives which are not 
designated as ``evaporative fuel additives'' pursuant to the definitions 
in Sec. 79.50 need not undergo the emission characterization or health 
effects testing specified in Secs. 79.52 and 79.53 for evaporative 
emissions. At EPA's discretion, the evaporative emissions of such fuels 
and additives may be required to undergo Tier 3 testing, pursuant to 
Sec. 79.54.
    (c) Alternative Tier 2 Provisions. At EPA's discretion, EPA may 
modify the standard Tier 2 health effects testing requirements for a 
fuel or fuel additive (or group). Such modification may encompass 
substitution, addition, or deletion of Tier 2 studies or study 
specifications, and/or changes in underlying engine or equipment 
requirements, except that a Tier 2 endpoint will not be deleted in the 
absence of existing information deemed adequate by EPA or alternative 
testing requirements for such endpoint. If warranted by the particular 
requirements, EPA will allow additional time for completion of the 
alternative Tier 2 testing program.
    (1) When EPA intends to require testing in lieu of or in addition to 
standard Tier 2 health testing, EPA will notify the responsible 
manufacturer (or group) by certified letter of the specific tests which 
EPA is proposing to require in lieu of or in addition to Tier 2, and the 
proposed schedule for completion and submission of such tests. A copy of 
the letter will be placed in the public record. EPA intends to send the 
notification prior to November 27, 1995, or in the case of new fuels and 
additives (as defined in Sec. 79.51(c)(3)), within 18 months of EPA's 
receipt of an intent to register such product. However, EPA's 
notification to the manufacturer (or group) may occur at any time up to 
EPA's receipt of Tier 2 data for the product(s) in question. EPA will 
provide the manufacturer with 60 days from the date of receipt of the 
notice to comment on the tests which EPA is proposing to require and on 
the proposed schedule. If the manufacturer believes that undue costs or 
hardships will occur as a result of EPA's delay in

[[Page 428]]

providing notification of alternative Tier 2 requirements, then the 
manufacturer's comments should describe and include evidence of such 
hardship. In particular, if the standard Tier 2 toxicology testing for 
the fuel or additive in question has already begun at the time the 
manufacturer receives EPA's notification of proposed alternative Tier 2 
requirements, then EPA shall refrain from requiring alternative Tier 2 
tests provided that EPA receives the standard Tier 2 data and report 
(pursuant to Sec. 79.59(c)) within one year of the date on which the 
toxicology testing began.
    (2) EPA will issue a notice in the Federal Register announcing its 
intent to require special testing in lieu of or in addition to the 
standard Tier 2 testing for a particular fuel or additive manufacturer 
or group, and that a copy of the letter to the manufacturer or group 
describing the proposed alternative Tier 2 testing for that manufacturer 
or group is available in the public record for review and comment. The 
public shall have a minimum of 30 days after the publication of this 
notice to comment on the proposed alternative Tier 2 testing.
    (3) EPA will include in the public record a copy of any timely 
comments concerning the proposed alternative Tier 2 testing requirements 
received from the affected manufacturer or group or from the public, and 
the responses of EPA to such comments. After reviewing all such comments 
received, EPA may adopt final alternative Tier 2 requirements by sending 
a certified letter describing such final requirements to the 
manufacturer or group. In that event, EPA will also issue a notice in 
the Federal Register announcing that it has adopted final alternative 
Tier 2 requirements and that a copy of the letter adopting the 
requirements has been included in the public record.
    (4) After EPA's receipt of a manufacturer's (or group's) submittals, 
EPA will notify the responsible manufacturer (or group) regarding the 
adequacy of the submittal and potential Tier 3 testing requirements 
according to the same relative time intervals and by the same procedures 
as specified in Sec. 79.51 (c) and (d) for routine Tier 1 and Tier 2 
submittals.
    (d) Small Business Provisions. (1) For purposes of these provisions, 
when subsidiary, divisional, or other complex business arrangements 
exist, manufacturer is defined as the business entity with ultimate 
ownership of all related parents, subsidiaries, divisions, branches, or 
other operating units. Total annual sales means the average of the 
manufacturer's total sales revenue in each of the three years prior to 
such manufacturer's submittal to EPA of the basic registration 
information pursuant to Sec. 79.59 (b)(2) through (b)(5).
    (2) Provisions Applicable to Baseline and Non-baseline Products. A 
manufacturer with total annual sales less than $50 million is not 
required to meet the requirements of Tier 1 and Tier 2 (specified in 
Secs. 79.52 and 79.53) with regard to such manufacturer's fuel and/or 
additive products which meet the criteria for inclusion in a Baseline or 
Non-baseline group pursuant to Sec. 79.56. Upon such manufacturer's 
satisfactory completion and submittal to EPA of basic registration data 
specified in Sec. 79.59(b), the manufacturer may request and EPA shall 
issue a registration for such product, subject to Sec. 79.51(c) and 
paragraphs (d)(4) and (d)(5) of this section.
    (3) Provisions Applicable to Atypical Products. A manufacturer with 
total annual sales less than $10 million is not required to meet the 
requirements of Tier 2 (specified in Sec. 79.53) in regard to such 
manufacturer's fuel and/or additive products which meet the criteria for 
inclusion in an Atypical group pursuant to Sec. 79.56. Upon such 
manufacturer's satisfactory completion and submittal to EPA of basic 
registration data specified in Sec. 79.59(b) and Tier 1 information 
specified in Sec. 79.52 for an Atypical fuel or additive, the 
manufacturer may request and EPA shall issue a registration for such 
product, subject to Sec. 79.51(c) and paragraphs (d)(4) and (d)(5) of 
this section. Compliance with Tier 1 requirements under this paragraph 
may be accomplished by the individual manufacturer or as a part of a 
group pursuant to Sec. 79.56.
    (4) Any registration granted by EPA under the provisions of this 
section are conditional upon satisfactory completion of any Tier 3 
requirements which

[[Page 429]]

EPA may subsequently impose pursuant to Sec. 79.54. In such 
circumstances, the Tier 3 requirements might include (but would not 
necessarily be limited to) information which would otherwise have been 
required under the provisions of Tier 1 and/or Tier 2.
    (5) The provisions in paragraphs (d)(2) and (d)(3) of this section 
are voluntary on the part of qualifying small manufacturers. Such 
manufacturers may choose to fulfill the standard requirements for their 
fuels and additives, individually or as a part of a group, rather than 
satisfying only the requirements specified in paragraphs (d)(2) and/or 
(d)(3) of this section. If a qualifying small manufacturer elects these 
special provisions rather than the standard requirements for a product, 
then EPA will generally assume that any additional information submitted 
by other manufacturers, for fuels and additives meeting the same 
grouping criteria (under Sec. 79.56) as that of the small manufacturer's 
product, is pertinent to further testing and/or regulatory decisions 
that may affect the small manufacturer's product.
    (e) Aftermarket Aerosol Additives. (1) To obtain registration for an 
aftermarket aerosol fuel additive, the manufacturer shall provide 
existing information in the form of a literature search, a discussion of 
the potential exposure(s) to such product, and the basic registration 
data specified in Sec. 79.59(b).
     (2) The literature search shall include existing data on potential 
health and welfare effects due to exposure to the aerosol product itself 
and its raw (uncombusted) components. The analysis for potential 
exposures shall be based on the actual or anticipated production volume 
and market distribution of the particular aerosol product, and its 
estimated frequency of use. Other Tier 1 and Tier 2 requirements are not 
routinely required for aerosol products. EPA will review the submitted 
information and, at EPA's discretion, may require from the manufacturer 
further information and/or testing under Tier 3 on a case-by-case basis.



Sec. 79.59  Reporting requirements.

    (a) Timing. (1) The manufacturer of each designated fuel or fuel 
additive shall submit to EPA the basic registration data detailed in 
paragraph (b) of this section. Forms for submitting this data may be 
obtained from EPA at the following address: Director, Field Operations 
and Support Division, 6406J--Fuel/Additives Registration, U.S. 
Environmental Protection Agency, 401 M Street, S.W., Washington, DC 
20460.
    (i) For existing products (pursuant to Sec. 79.51(c)(1)), 
manufacturers shall submit the basic registration data as specified in 
Sec. 79.59(b) to EPA by November 28, 1994.
    (ii) For registrable products (pursuant to Sec. 79.51(c)(2)), 
manufacturers shall submit the basic registration data as specified in 
Sec. 79.59(b) to apply for registration for such product.
    (iii) For new products (pursuant to Sec. 79.51(c)(3)), manufacturers 
are strongly encouraged to notify EPA of an intent to obtain product 
registration by submitting the basic registration data as specified in 
Sec. 79.59(b) prior to starting Tiers 1 and 2.
    (2) The information specified in paragraph (c) of this section shall 
be submitted to the address in paragraph (a)(1) of this section at the 
conclusion of activities performed in compliance with Tiers 1 and 2 
under the provisions of Secs. 79.52 and 79.53, according to the time 
constraints specified in Sec. 79.51 (c) through (d).
    (3) The information specified in paragraph (d) of this section shall 
be submitted to EPA at the address in paragraph (a)(1) of this section 
at the conclusion of activities performed in compliance with Tier 3 
under the provisions of Sec. 79.54.
    (b) Basic Registration Data. Each manufacturer of a designated fuel 
or fuel additive shall submit the following data in regard to such fuel 
or fuel additive:
    (1) The information specified in Sec. 79.11 or Sec. 79.21. If such 
information has already been submitted to EPA in compliance with subpart 
B or C of this part, and if such previous information is accurate and 
up-to-date, the manufacturer need not resubmit this information.
    (2) Annual production volume of the fuel or fuel additive product, 
in units of gallons per year if most commonly sold in liquid form or 
kilograms per year if

[[Page 430]]

most commonly sold in solid form. For fuels and fuel additives already 
in production, the most recent annual production volume and the volume 
projected to be produced in the third subsequent year shall be provided. 
For products not yet in production, the best estimate of expected annual 
volume during the third year of production shall be provided.
    (3) Market distribution of the product. For fuels and bulk 
additives, this information shall be presented as the percent of total 
annual sales volume marketed in each Petroleum Administration for 
Defense District (PADD). The states comprising each PADD are listed in 
the following section. For aftermarket additives, the distribution data 
shall be presented as the percent of total annual sales volume marketed 
in each state. For a product not yet in production, the manufacturer 
shall present the distribution (by PADD or state, as applicable) 
projected to occur during the third year of production.
    (i) The following states and jurisdictions are included in PADD I:

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

    (ii) The following states are included in PADD II:

Illinois
Indiana
Iowa
Kansas
Kentucky
Michigan
Minnesota
Missouri
Nebraska
North Dakota
Ohio
Oklahoma
South Dakota
Tennessee
Wisconsin

    (iii) The following states are included in PADD III:

Alabama
Arkansas
Louisiana
Mississippi
New Mexico
Texas

    (iv) The following states are included in PADD IV:

Colorado
Idaho
Montana
Utah
Wyoming

    (v) The following states are included in PADD V:

Alaska
Arizona
California
Hawaii
Nevada
Oregon
Washington

    (4) Any applicable information pursuant to the grouping provisions 
in Sec. 79.56, as follows:
    (i) If the manufacturer has enrolled or intends to enroll the 
product in a fuel/additive group, the relevant group and the person(s) 
or entity expected to submit information on behalf of the group must be 
identified.
    (ii) If the manufacturer intends to rely on registration information 
previously submitted by another manufacturer (or group) for registration 
of other product(s) in the same fuel/additive group, then the original 
submitter and its product (or product group) shall be identified. In 
such cases, the manufacturer shall provide evidence that the original 
submitter has been notified of the use of its registration data and that 
the manufacturer has complied or intends to comply with the proportional 
reimbursement required under Sec. 79.56(c) of this rule.
    (5) Any applicable information pursuant to the special provisions in 
Sec. 79.58, as follows:
    (i) If the manufacturer claims applicability of the special 
provisions for relabeled additives, pursuant to Sec. 79.58(a), then the 
manufacturer and brand name of the original product shall be given.

[[Page 431]]

    (ii) If the manufacturer claims applicability of any small business 
provisions pursuant to Sec. 79.58(d), the average of the manufacturer's 
total annual sales revenue for the previous three years shall be given.
    (iii) If the manufacturer claims applicability of the special 
provisions for aerosol products, pursuant to Sec. 79.58(e), then the 
purpose and recommended frequency of use shall be given.
    (c) Tier 1 and Tier 2 Reports. If the results of Tiers 1 and 2 are 
reported to EPA at the same time, then the report shall include the 
following documents in paragraphs (c)(1) through (7) of this section. If 
Tier 1 and Tier 2 results are submitted to EPA separately, then the 
separate Tier 1 report shall include only documents in paragraphs (c)(1) 
through (4), (c)(6), and associated appendices in paragraphs (c)(7) of 
this section, and the separate Tier 2 report shall include only 
documents in paragraphs (c)(1) through (3), (c)(5), (c)(6), and 
associated appendices in paragrpah (c)(7) of this section. In addition, 
pursuant to the requirements in Sec. 79.51(c)(1)(ii)(B), if the Tier 2 
report for registered fuels and fuel additives is not submitted prior to 
May 27, 1997, then evidence of a suitable arrangement for completion of 
Tier 2 (e.g., a copy of a signed contract with a qualified laboratory 
for applicable Tier 2 services) must be submitted to EPA prior to that 
date.
    (1) Cover page. (i) Identification of test substance,
    (ii) Name and address of the manufacturer of the test substance,
    (iii) Name and phone number of a designated contact person,
    (iv) Group information, if applicable, including:
    (A) Group name or grouping criteria,
    (B) Name and address of responsible organization or entity reporting 
for the group,
    (C) Product trade name and manufacturer of each member fuel and 
additive to which the report pertains.
    (2) Executive Summary. Text overview of the significant results and 
conclusions obtained as a result of completing the requirements of Tier 
1 and/or Tier 2, including references if used to support such results 
and conclusions.
    (3) Test Substance Information. Test substance description, 
including, as applicable,
    (i) Base fuel parameter values (including types and concentrations 
of base fuel additives) or test fuel composition (if a fuel other than 
the base fuel is used in testing). These values must be provided for 
each of the fuel parameters specified in Sec. 79.55 for the applicable 
fuel family.
    (ii) Test additive composition and concentration
    (4) Summary of Tier 1. (i) Literature Search. Pursuant to 
Sec. 79.52(d), the literature search shall include a text summary of the 
methods and results of the literature search, including the following:
    (A) Identification of person(s) performing the literature search,
    (B) Description of data sources accessed, search strategy used, 
search period, and terms included in literature search,
    (C) Documentation of all unpublished in-house and other privately-
conducted studies,
    (D) Tables summarizing the protocols and results of all cited 
studies,
    (E) Summary of significant results and conclusions with respect to 
the effects of the emissions of the subject fuel or fuel additive on the 
public health and welfare, including references if used to support such 
results and conclusions.
    (F) Statement of the extent to which the literature search has 
produced adequate information comparable to that which would otherwise 
be obtained through the performance of applicable emission 
characterization requirements under Sec. 79.52(b) and/or health effects 
testing requirements under Sec. 79.53, including justifications and 
specific references.
    (ii) Emission Characterization. Pursuant to Sec. 79.52(b), the 
emission characterization shall include:
    (A) Name, address, and telephone number of the laboratory performing 
the characterization,
    (B) Name and description of analytic methods used for 
characterization.
    (iii) Exposure Analysis. Pursuant to Sec. 79.52(c), the exposure 
analysis shall include:

[[Page 432]]

    (A) A qualitative discussion of the potential exposure(s) of the 
general and any special at-risk populations to the emission products, 
based on annual and projected production volume, and market distribution 
data. For group submittals, this discussion shall address the 
characteristics of the cumulative exposure from the potential use of all 
fuel or additive products in the group.
    (B) Identification of person(s) preparing the analysis.
    (5) Summary of Tier 2. For each health effects test performed 
pursuant to the provisions of Sec. 79.53, the Tier 2 summary shall 
contain the following information:
    (i) Name, address, and telephone number of the testing facility,
    (ii) Summary of procedures (including quality assurance, quality 
control and compliance with Good Laboratory Practice Standards as 
specified in Sec. 79.60), findings, and conclusions, including 
references if used to support such results and conclusions,
    (iii) Description of any problems and their resolution.
    (6) Conclusions. The conclusions shall identify the need for further 
testing, if that need exists, or justify that current testing and/or 
available information is adequate for the tier(s) included in the 
report.
    (7) Appendices. The appendices shall contain detailed documentation 
related to the summary information described in this section, including, 
at a minimum, the following five appendices:
    (i) Literature search appendices shall contain:
    (A) Copies of literature source outputs, including reference lists 
and associated abstracts from database searches, printed or on 3\1/2\ 
inch IBM-compatible computer diskettes;
    (B) Summary tables organized by health or welfare endpoint and type 
of emission (e.g., combustion, evaporation, individual emission 
product), presenting in tabular form the following information at a 
minimum: number and species of test subjects, exposure concentrations/
duration, positive (i.e., abnormal) findings including numbers of test 
subjects involved, and bibliographic references;
    (C) Complete documentation and/or reprints of articles for any 
previous study relied upon for satisfying emission characterization and/
or Tier 2 test requirements; and
    (D) Full reports for unpublished/in-house studies.
    (ii) Emissions characterization appendices shall contain:
    (A) Complete laboratory reports, including documentation of 
calibration and verification procedures;
    (B) Documentation of the emissions generation procedures used; and
    (C) Lists of speciated emission products and their emission rates 
reported in units of grams/mile.
    (iii) Exposure analysis appendices may be submitted to report any 
detailed documentation of data used in the analyses and/or calculations 
determining potential exposures to population(s). If modeling data are 
used, these should be included in an appendix.
    (iv) Tier 2 appendices shall contain, for each test performed:
    (A) Complete protocol used;
    (B) Documentation of emission generation procedures; and
    (C) Complete laboratory report in compliance with the reporting 
standards in Sec. 79.60, including detailed test results and 
conclusions, and descriptions of any problems encountered and their 
resolution.
    (v) Laboratory certification/accreditation information, personnel 
credentials, and statements of compliance with the Good Laboratory 
Practices Standards specified in Sec. 79.60 and the requirements in 
Sec. 79.53(c)(1).
    (d) Tier 3 Report. Subject to applicability as specified in 
Sec. 79.54, each manufacturer of a designated fuel or fuel additive, or 
each group of such manufacturers pursuant to the provisions of 
Sec. 79.56, shall submit the following information with respect to each 
Tier 3 test conducted for such fuels or fuel additives:
    (1) The test objectives, including a summary of the reason(s) why 
such additional testing, beyond Tiers 1 and 2, was required;
    (2) Name, address, and telephone number of each testing facility;
    (3) Summary of test procedures, results and conclusions;

[[Page 433]]

    (4) Complete documentation of test protocols and emission generation 
procedures, complete laboratory reports in compliance with the reporting 
standards of Sec. 79.60, detailed test results and conclusions, 
including references if used to support such results and conclusions, 
and descriptions of any problems encountered and their resolution; and
    (5) Laboratory certification information, personnel credentials, and 
statements of compliance with the Good Laboratory Practices Standards 
specified in Sec. 79.60.
    (e) Availability of Information. (1) All health and safety test data 
and other information concerning health and welfare effects which is 
submitted by any manufacturer or group pursuant to Secs. 79.52(c), 
79.53, or 79.54, shall be considered to be public information and shall 
be made available to the public by EPA upon request. A reasonable fee 
may be charged by EPA for copying such materials. Any manufacturer or 
group who claims that any information concerning the composition of a 
fuel or fuel additive product, or any other information, submitted under 
this subpart is confidential business information must state this claim 
in writing at the time of the submittal.
    (2) To assert a business confidentiality claim concerning any 
information submitted under this subpart, the submitter must:
     (i) Clearly mark the information as confidential at each location 
it appears in the submission; and
    (ii) Submit with the information claimed as confidential a separate 
document setting forth the claim and listing each location at which the 
information appears in the submission.
    (3) If any person subsequently requests access to information 
submitted under this subpart (other than health and safety test data and 
other information concerning health and welfare effects), and such 
information is subject to a claim of business confidentiality, the 
request and any subsequent disclosure shall be governed by the 
provisions of 40 CFR part 2.



Sec. 79.60  Good laboratory practices (GLP) standards for inhalation exposure health effects testing.

    (a) General Provisions--(1) Scope. (i) This section prescribes good 
laboratory practices (GLPs) for conducting inhalation exposure studies 
relating to motor vehicle emissions health effects testing under this 
part. These directions are intended to ensure the quality and integrity 
of health effects data submitted pursuant to registration regulations 
issued under sections 211(b) or 211(e) of the Clean Air Act (CAA) (42 
U.S.C. 7545).
    (ii) This section applies to any study described by paragraph 
(a)(1)(i) of this section which any person conducts, initiates, or 
supports on or after May 27, 1994.
    (iii) It is EPA's policy that all health effects data developed 
under sections 211(b) and (e) of CAA be in accordance with provisions of 
this section. If data are not developed in accordance with the 
provisions of this section, EPA may consider such data insufficient to 
evaluate the health effects of a motor vehicle's fuel or fuel additive 
emissions, unless the submitter provides additional information 
demonstrating that the data are reliable and adequate and EPA determines 
that the data are sufficient.
    (2) Definitions. As used in this section, the following terms shall 
have the meanings specified:
    Batch means a specific quantity or lot of a test fuel, additive/base 
fuel mixture, or reference substance that has been characterized 
according to Sec. 79.60(f)(1)(i).
    CAA means the Clean Air Act.
    Carrier means any material which is combined with engine/motor 
vehicle emissions or a reference substance for administration to a test 
system. ``Carrier'' includes, but is not limited to, clean, filtered 
air, water, feed, and nutrient media.
    Control atmosphere means clean, filtered air which is administered 
to the test system in the course of a study for the purpose of 
establishing a basis for comparison with the test atmosphere for 
chemical or biological measurements.

[[Page 434]]

    Experimental start date means the first date the test atmosphere is 
applied to the test system.
    Experimental termination date means the last date on which data are 
collected directly from the study.
    Person includes an individual, partnership, corporation, 
association, scientific or academic establishment, government agency, or 
organizational unit thereof, and any other legal entity.
    Quality assurance unit means any person or organizational element, 
except the study director, designated by testing facility management to 
perform the duties relating to quality assurance of the studies.
    Raw data means any laboratory worksheets, records, memoranda, notes, 
or exact copies thereof, that are the result of original observations 
and activities of a study and are necessary for the reconstruction and 
evaluation of the report of that study. In the event that exact 
transcripts of raw data have been prepared (e.g., tapes which have been 
transcribed verbatim, dated, and verified accurate by signature), the 
exact copy or exact transcript may be substituted for the original 
source as raw data. ``Raw data'' may include photographs, videotape, 
microfilm or microfiche copies, computer printouts, magnetic media, 
including dictated observations, and recorded data from automated 
instruments.
    Reference substance means any chemical substance or mixture, 
analytical standard, or material other than engine/motor vehicle 
emissions and/or its carrier, that is administered to or used in 
analyzing the test system in the course of a study. A ``reference 
substance'' is used to establish a basis for comparison with the test 
atmosphere for known chemical or biological measurements, i.e., positive 
or negative control substance.
    Specimen means any material derived from a test system for 
examination or analysis.
    Sponsor means person who initiates and supports, by provision of 
financial or other resources, a study or a person who submits a study to 
EPA in response to the CAA Section 211(b) or 211(e) Fuels and Fuel 
Additives Registration Rule or a testing facility, if it both initiates 
and actually conducts the study.
    Study means any experiment, at one or more test sites, in which a 
test system is exposed to a test atmosphere under laboratory conditions 
to determine or help predict the health effects of that exposure in 
humans, other living organisms, or media.
    Study completion date means the date the final report is signed by 
the study director.
    Study director means the individual responsible for the overall 
conduct of a study.
    Study initiation date means the date the protocol is signed by the 
study director.
    Test substance means a vapor and/or aerosol mixture composed of 
engine/motor vehicle emissions and clean, filtered air which is 
administered directly, or indirectly, by the inhalation route to a test 
system in a study which develops data to meet the registration 
requirements of CAA section 211(b) or (e).
    Test system means any animal, microorganism, chemical or physical 
matrix, to which the test, control, or reference substance is 
administered or added for study. This definition also includes 
appropriate groups or components of the system not treated with the 
test, control, or reference substance.
    Testing facility means a person who actually conducts a study, i.e., 
actually uses the test substance in a test system. ``Testing facility'' 
encompasses only those operational units that are being or have been 
used to conduct studies.
    TSCA means the Toxic Substances Control Act (15 U.S.C. 2601 et 
seq.).
    (3) Applicability to studies performed under grants and contracts. 
When a sponsor or other person utilizes the services of a consulting 
laboratory, contractor, or grantee to perform all or a part of a study 
to which this section applies, it shall notify the consulting 
laboratory, contractor, or grantee that the service is, or is part of, a 
study that must be conducted in compliance with the provisions of this 
section.
    (4) Statement of compliance or non-compliance. Any person who 
submits to EPA a test in compliance with registration regulations issued 
under CAA

[[Page 435]]

section 211(b) or section 211(e) shall include in the submission a true 
and correct statement, signed by the sponsor and the study director, of 
one of the following types:
    (i) A statement that the study was conducted in accordance with this 
section; or
    (ii) A statement describing in detail all differences between the 
practices used in the study and those required by this section; or
    (iii) A statement that the person was not a sponsor of the study, 
did not conduct the study, and does not know whether the study was 
conducted in accordance with this section.
    (5) Inspection of a testing facility. (i) A testing facility shall 
permit an authorized employee or duly designated representative of EPA, 
at reasonable times and in a reasonable manner, to inspect the facility 
and to inspect (and in the case of records also to copy) all records and 
specimens required to be maintained regarding studies to which this 
section applies. The records inspection and copying requirements shall 
not apply to quality assurance unit records of findings and problems, or 
to actions recommended and taken, except the EPA may seek production of 
these records in litigation or formal adjudicatory hearings.
    (ii) EPA will not consider reliable for purposes of showing that a 
test substance does or does not present a risk of injury to health or 
the environment any data developed by a testing facility or sponsor that 
refuses to permit inspection in accordance with this section. The 
determination that a study will not be considered reliable does not, 
however, relieve the sponsor of a required test of any obligation under 
any applicable statute or regulation to submit the results of the study 
to EPA.
    (6) Effects of non-compliance. (i) Pursuant to sections 114, 208, 
and 211(d) of the CAA, it shall be a violation of this section and a 
violation of this rule (40 CFR part 79, subpart F) if:
    (A) The test is not being or was not conducted in accordance with 
any requirement of this part; or
    (B) Data or information submitted to EPA under part 79, including 
the statement required by Sec. 79.60(a)(4), include information or data 
that are false or misleading, contain significant omissions, or 
otherwise do not fulfill the requirements of this part; or
    (C) Entry in accordance with Sec. 79.60(a)(5) for the purpose of 
auditing test data is denied.
    (ii) EPA, at its discretion, may not consider reliable for purposes 
of showing that a chemical substance or mixture does not present a risk 
of injury to health any study which was not conducted in accordance with 
this part. EPA, at its discretion, may rely upon such studies for 
purposes of showing adverse effects. The determination that a study will 
not be considered reliable does not, however, relieve the sponsor of a 
required test of the obligation under any applicable statute or 
regulation to submit the results of the study to EPA.
    (iii) If data submitted in compliance with registration regulations 
issued under CAA section 211(b) or section 211(e) are not developed in 
accordance with this section, EPA may determine that the sponsor has not 
fulfilled its obligations under 40 CFR part 79 and may require the 
sponsor to develop data in accordance with the requirements of this 
section in order to satisfy such obligations.
    (b) Organization and Personnel. (1) Personnel. (i) Each individual 
engaged in the conduct of or responsible for the supervision of a study 
shall have education, training, and experience, or combination thereof, 
to enable that individual to perform the assigned functions.
    (ii) Each testing facility shall maintain a current summary of 
training and experience and job description for each individual engaged 
in or supervising the conduct of a study.
    (iii) There shall be a sufficient number of personnel for the timely 
and proper conduct of the study according to the protocol.
    (iv) Personnel shall take necessary personal sanitation and health 
precautions designed to avoid contamination of test fuel and additive/
base fuel mixtures, test and reference substances, and test systems.
    (v) Personnel engaged in a study shall wear clothing appropriate for 
the duties they perform. Such clothing shall be changed as often as 
necessary

[[Page 436]]

to prevent microbiological, radiological, or chemical contamination of 
test systems and test, control, and reference substances.
    (vi) Any individual found at any time to have an illness that may 
adversely affect the quality and integrity of the study shall be 
excluded from direct contact with test systems, fuel and fuel/additive 
mixtures, test and reference substances and any other operation or 
function that may adversely affect the study until the condition is 
corrected. All personnel shall be instructed to report to their 
immediate supervisors any health or medical conditions that may 
reasonably be considered to have an adverse effect on a study.
    (2) Testing facility management. For each study, testing facility 
management shall:
    (i) Designate a study director as described in Sec. 79.60(b)(3) 
before the study is initiated.
    (ii) Replace the study director promptly if it becomes necessary to 
do so during the conduct of a study.
    (iii) Assure that there is a quality assurance unit as described in 
Sec. 79.60(b)(4).
    (iv) Assure that test fuels and fuel/additive mixtures and test and 
reference substances have been identified as to content, strength, 
purity, stability, and uniformity, as applicable.
    (v) Assure that personnel, resources, facilities, equipment, 
materials and methodologies are available as scheduled.
    (vi) Assure that personnel clearly understand the functions they are 
to perform.
    (vii) Assure that any deviations from these regulations reported by 
the quality assurance unit are communicated to the study director and 
corrective actions are taken and documented.
    (3) Study director. For each study, a scientist or other 
professional person with a doctorate degree or equivalent in toxicology 
or other appropriate discipline shall be identified as the study 
director. The study director has overall responsibility for the 
technical conduct of the study, as well as for the interpretation, 
analysis, documentation, and reporting of results, and represents the 
single point of study control. The study director shall assure that:
    (i) The protocol, including any changes, is approved as provided by 
Sec. 79.60(g)(1)(i) and is followed;
    (ii) All experimental data, including observations of unanticipated 
responses of the test system are accurately recorded and verified;
    (iii) Unforeseen circumstances that may affect the quality and 
integrity of the study are noted when they occur, and corrective action 
is taken and documented;
    (iv) Test systems are as specified in the protocol;
    (v) All applicable good laboratory practice regulations are 
followed; and
    (vi) All raw data, documentation, protocols, specimens, and final 
reports are archived properly during or at the close of the study.
    (4) Quality assurance unit. A testing facility shall have a quality 
assurance unit which shall be responsible for monitoring each study to 
assure management that the facilities, equipment, personnel, methods, 
practices, records, and controls are in conformance with the regulations 
in this section. For any given study, the quality assurance unit shall 
be entirely separate from and independent of the personnel engaged in 
the direction and conduct of that study. The quality assurance unit 
shall conduct inspections and maintain records appropriate to the study.
    (i) Quality assurance unit duties. (A) Maintain a copy of a master 
schedule sheet of all studies conducted at the testing facility indexed 
by test substance and containing the test system, nature of study, date 
study was initiated, current status of each study, identity of the 
sponsor, and name of the study director.
    (B) Maintain copies of all protocols pertaining to all studies for 
which the unit is responsible.
    (C) Inspect each study at intervals adequate to ensure the integrity 
of the study and maintain written and properly signed records of each 
periodic inspection showing the date of the inspection, the study 
inspected, the phase or segment of the study inspected, the person 
performing the inspection, findings and problems, action

[[Page 437]]

recommended and taken to resolve existing problems, and any scheduled 
date for re-inspection. Any problems which are likely to affect study 
integrity found during the course of an inspection shall be brought to 
the attention of the study director and management immediately.
    (D) Periodically submit to management and the study director written 
status reports on each study, noting any problems and the corrective 
actions taken.
    (E) Determine that no deviations from approved protocols or standard 
operating procedures were made without proper authorization and 
documentation.
    (F) Review the final study report to assure that such report 
accurately describes the methods and standard operating procedures, and 
that the reported results accurately reflect the raw data of the study.
    (G) Prepare and sign a statement to be included with the final study 
report which shall specify the dates inspections were made and findings 
reported to management and to the study director.
    (ii) The responsibilities and procedures applicable to the quality 
assurance unit, the records maintained by the quality assurance unit, 
and the method of indexing such records shall be in writing and shall be 
maintained. These items including inspection dates, the study inspected, 
the phase or segment of the study inspected, and the name of the 
individual performing the inspection shall be made available for 
inspection to authorized employees or duly designated representatives of 
EPA.
    (iii) An authorized employee or a duly designated representative of 
EPA shall have access to the written procedures established for the 
inspection and may request test facility management to certify that 
inspections are being implemented, performed, documented, and followed 
up in accordance with this paragraph.
    (c) Facilities--(1) General. Each testing facility shall be of 
suitable size and construction to facilitate the proper conduct of 
studies. Testing facilities which are not completely located within an 
indoor controlled environment shall be of suitable location/proximity to 
facilitate the proper conduct of studies. Testing facilities shall be 
designed so that there is a degree of separation that will prevent any 
function or activity from having an adverse effect on the study.
    (2) Test system care facilities. (i) A testing facility shall have a 
sufficient number of animal rooms or other test system areas, as needed, 
to ensure proper separation of species or test systems, quarantine or 
isolation of animals or other test systems, and routine or specialized 
housing of animals or other test systems.
    (ii) A testing facility shall have a number of animal rooms or other 
test system areas separate from those described in paragraph (a) of this 
section to ensure isolation of studies being done with test systems or 
test, control, and reference substances known to be biohazardous, 
including volatile atmospheres and aerosols, radioactive materials, and 
infectious agents. The animal handling facility must operate under the 
supervision of a veterinarian.
    (iii) Separate areas shall be provided, as appropriate, for the 
diagnosis, treatment, and control of laboratory test system diseases. 
These areas shall provide effective isolation for the housing of test 
systems either known or suspected of being diseased, or of being 
carriers of disease, from other test systems.
    (iv) Facilities shall have proper provisions for collection and 
disposal of contaminated air, water, or other spent materials. When 
animals are housed, facilities shall exist for the collection and 
disposal of all animal waste and refuse or for safe sanitary storage of 
waste before removal from the testing facility. Disposal facilities 
shall be so provided and operated as to minimize vermin infestation, 
odors, disease hazards, and environmental contamination.
    (v) Facilities shall have provisions to regulate environmental 
conditions (e.g., temperature, humidity, day length, etc.) as specified 
in the protocol.
    (3) Test system supply/operation areas. (i) There shall be storage 
areas, as needed, for feed, bedding, supplies, and equipment. Storage 
areas for feed and

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bedding shall be separated from areas where the test systems are located 
and shall be protected against infestation or contamination. Perishable 
supplies shall be preserved by appropriate means.
    (ii) Separate laboratory space and other space shall be provided, as 
needed, for the performance of the routine and specialized procedures 
required by studies.
    (4) Facilities for handling test fuels and fuel/additive mixtures 
and reference substances. (i) As necessary to prevent contamination or 
mixups, there shall be separate areas for:
    (A) Receipt and storage of the test fuels and fuel/additive mixtures 
and reference substances;
    (B) Mixing of the test fuels, fuel/additive mixtures, and reference 
substances with a carrier, i.e., liquid hydrocarbon; and
    (C) Storage of the test fuels, fuel/additive mixtures, and reference 
substance/carrier mixtures.
    (ii) Storage areas for test fuels and fuel/additive mixtures and 
reference substances and for reference mixtures shall be separate from 
areas housing the test systems and shall be adequate to preserve the 
identity, strength, purity, and stability of the substances and 
mixtures.
    (5) Specimen and data storage facilities. Space shall be secured for 
archives for the storage and retrieval of all raw data and specimens 
from completed studies.
    (d) Equipment--(1) Equipment design. Equipment used in the 
generation, measurement, or assessment of data and equipment used for 
facility environmental control shall be of appropriate design and 
adequate capacity to function according to the protocol and shall be 
suitably located for operation, inspection, cleaning, and maintenance.
    (2) Maintenance and calibration of equipment. (i) Equipment shall be 
adequately inspected, cleaned, and maintained. Equipment used for the 
generation, measurement, or assessment of data shall be adequately 
tested, calibrated, and/or standardized.
    (ii) The written standard operating procedures required under 
Sec. 79.60(e)(1)(ii)(K) shall set forth in sufficient detail the 
methods, materials, and schedules to be used in the routine inspection, 
cleaning, maintenance, testing, calibration, and/or standardization of 
equipment, and shall specify, when appropriate, remedial action to be 
taken in the event of failure or malfunction of equipment. The written 
standard operating procedures shall designate the person responsible for 
the performance of each operation.
    (iii) Written records shall be maintained of all inspection, 
maintenance, testing, calibrating, and/or standardizing operations. 
These records, containing the date of the operation, shall describe 
whether the maintenance operations were routine and followed the written 
standard operating procedures. Written records shall be kept of non-
routine repairs performed on equipment as a result of failure and 
malfunction. Such records shall document the nature of the defect, how 
and when the defect was discovered, and any remedial action taken in 
response to the defect.
    (e) Testing Facilities Operation--(1) Standard operating procedures. 
(i) A testing facility shall have standard operating procedures in 
writing, setting forth study methods that management is satisfied are 
adequate to insure the quality and integrity of the data generated in 
the course of a study. All deviations in a study from standard operating 
procedures shall be authorized by the study director and shall be 
documented in the raw data. Significant changes in established standard 
operating procedures shall be properly authorized in writing by 
management.
    (ii) Standard operating procedures shall be established for, but not 
limited to, the following:
    (A) Test system room preparation;
    (B) Test system care;
    (C) Receipt, identification, storage, handling, mixing, and method 
of sampling of test fuels and fuel/additive mixtures and reference 
substances;
    (D) Test system observations;
    (E) Laboratory or other tests;
    (F) Handling of test animals found moribund or dead during study;
    (G) Necropsy or postmortem examination of test animals;
    (H) Collection and identification of specimens;
    (I) Histopathology

[[Page 439]]

    (J) Data handling, storage and retrieval.
    (K) Maintenance and calibration of equipment.
    (L) Transfer, proper placement, and identification of test systems.
    (iii) Each laboratory or other study area shall have immediately 
available manuals and standard operating procedures relative to the 
laboratory procedures being performed. Published literature may be used 
as a supplement to standard operating procedures.
    (iv) A historical file of standard operating procedures, and all 
revisions thereof, including the dates of such revisions, shall be 
maintained.
    (2) Reagents and solutions. All reagents and solutions in the 
laboratory areas shall be labeled to indicate identity, titer or 
concentration, storage requirements, and expiration date. Deteriorated 
or outdated reagents and solutions shall not be used.
    (3) Animal and other test system care. (i) There shall be standard 
operating procedures for the housing, feeding, handling, and care of 
animals and other test systems.
    (ii) All newly received test systems from outside sources shall be 
isolated and their health status or appropriateness for the study shall 
be evaluated. This evaluation shall be in accordance with acceptable 
veterinary medical practice or scientific methods.
    (iii) At the initiation of a study, test systems shall be free of 
any disease or condition that might interfere with the purpose or 
conduct of the study. If during the course of the study, the test 
systems contract such a disease or condition, the diseased test systems 
shall be isolated, if necessary. These test systems may be treated for 
disease or signs of disease provided that such treatment does not 
interfere with the study. The diagnosis, authorization of treatment, 
description of treatment, and each date of treatment shall be documented 
and shall be retained.
    (iv) When laboratory procedures require test animals to be 
manipulated and observed over an extended period of time or when studies 
require test animals to be removed from and returned to their housing 
units for any reason (e.g., cage cleaning, treatment, etc.), these test 
systems shall receive appropriate identification (e.g., tattoo, color 
code, etc.). Test system identification shall conform with current 
laboratory animal handling practice. All information needed to 
specifically identify each test system within the test system-housing 
unit shall appear on the outside of that unit. Suckling animals are 
excluded from the requirement of individual identification unless 
otherwise specified in the protocol.
    (v) Except as specified in paragraph (e)(3)(v)(A) of this section, 
test animals of different species shall be housed in separate rooms when 
necessary. Test animals of the same species, but used in different 
studies, shall not ordinarily be housed in the same room when 
inadvertent exposure to the test or reference substances or test system 
mixup could affect the outcome of either study. If such mixed housing is 
necessary, adequate differentiation by space and identification shall be 
made.
    (A) Test systems that may be used in multispecies tests need not be 
housed in separate rooms, provided that they are adequately segregated 
to avoid mixup and cross-contamination.
    (B) [Reserved]
    (vi) Cages, racks, pens, enclosures, and other holding, rearing, and 
breeding areas, and accessory equipment, shall be cleaned and sanitized 
at appropriate intervals.
    (vii) Feed and water used for the test animals shall be analyzed 
periodically to ensure that contaminants known to be capable of 
interfering with the study and reasonably expected to be present in such 
feed or water are not present at greater than trace levels. 
Documentation of such analyses shall be maintained as raw data.
    (viii) Bedding used in animal cages or pens shall not interfere with 
the purpose or conduct of the study and shall be changed as often as 
necessary to keep the animals dry and clean.
    (ix) If any pest control materials are used, the use shall be 
documented. Cleaning and pest control materials that interfere with the 
study shall not be used.
    (x) All test systems shall be acclimatized to the environmental 
conditions of the test, prior to their use in a study.

[[Page 440]]

    (f) Test fuels, additive/base fuel mixtures, and reference 
substances--(1) Test fuel, fuel/additive mixture, and reference 
substance identity. (i) The product brand name/service mark, strength, 
purity, content, or other characteristics which appropriately define the 
test fuel, fuel/additive mixture, or reference substance shall be 
reported for each batch and shall be documented before its use in a 
study. Methods of synthesis, fabrication, or derivation, as appropriate, 
of the test fuel, fuel/additive mixture, or reference substance shall be 
documented by the sponsor or the testing facility, and such location of 
documentation shall be specified.
    (ii) The stability of test fuel, fuel/additive mixture, and 
reference substances under storage conditions at the test site shall be 
known for all studies.
    (2) Test fuel, additive/base fuel mixture, and reference substance 
handling. Procedures shall be established for a system for the handling 
of the test fuel, fuel/additive mixture, and reference substance(s) to 
ensure that:
    (i) There is proper storage.
    (ii) Distribution is made in a manner designed to preclude the 
possibility of contamination, deterioration, or damage.
    (iii) Proper identification is maintained throughout the 
distribution process.
    (iv) The receipt and distribution of each batch is documented. Such 
documentation shall include the date and quantity of each batch 
distributed or returned.
    (3) Mixtures of test emissions or reference solutions with carriers.
    (i) For test emissions or each reference substance mixed with a 
carrier, tests by appropriate analytical methods shall be conducted:
    (A) To determine the uniformity of the test substance and to 
determine, periodically, the concentration of the test emissions or 
reference substance in the mixture;
    (B) When relevant to the conduct of the experiment, to determine the 
solubility of each reference substance in the carrier mixture before the 
experimental start date; and
    (C) To determine the stability of test emissions or a reference 
solution in the test substance before the experimental start date or 
concomitantly according to written standard operating procedures, which 
provide for periodic analysis of each batch.
    (ii) Where any of the components of the reference substance/carrier 
mixture has an expiration date, that date shall be clearly shown on the 
container. If more than one component has an expiration date, the 
earliest date shall be shown.
    (iii) If a chemical or physical agent is used to facilitate the 
mixing of a test substance with a carrier, assurance shall be provided 
that the agent does not interfere with the integrity of the test.
    (g) Protocol for and conduct of a study--(1) Protocol. (i) Each 
study shall have a written protocol that clearly indicates the 
objectives and all methods for the conduct of the study. The protocol 
shall contain but shall not be limited to the following information:
    (A) A descriptive title and statement of the purpose of the study.
    (B) Identification of the test fuel, fuel/additive mixture, and 
reference substance by name, chemical abstracts service (CAS) number or 
code number, as applicable.
    (C) The name and address of the sponsor and the name and address of 
the testing facility at which the study is being conducted.
    (D) The proposed experimental start and termination dates.
    (E) Justification for selection of the test system, as necessary.
    (F) Where applicable, the number, body weight, sex, source of 
supply, species, strain, substrain, and age of the test system.
    (G) The procedure for identification of the test system.
    (H) A description of the experimental design, including methods for 
the control of bias.
    (I) Where applicable, a description and/or identification of the 
diet used in the study. The description shall include specifications for 
acceptable levels of contaminants that are reasonably expected to be 
present in the dietary materials and are known to be capable of 
interfering with the purpose or conduct of the study if present at 
levels greater than established by the specifications.

[[Page 441]]

    (J) Each concentration level, expressed in milligrams per cubic 
meter of air or other appropriate units, of the test or reference 
substance to be administered and the frequency of administration.
    (K) The type and frequency of tests, analyses, and measurements to 
be made.
    (L) The records to be maintained.
    (M) The date of approval of the protocol by the sponsor and the 
dated signature of the study director.
    (N) A statement of the proposed statistical method.
    (ii) All changes in or revisions of an approved protocol and the 
reasons therefor shall be documented, signed by the study director, 
dated, and maintained with the protocol.
    (2) Conduct of a study. (i) The study shall be conducted in 
accordance with the protocol.
    (ii) The test systems shall be monitored in conformity with the 
protocol.
    (iii) Specimens shall be identified by test system, study, nature, 
and date of collection. This information shall be located on the 
specimen container or shall accompany the specimen in a manner that 
precludes error in the recording and storage of data.
    (iv) In animal studies where histopathology is required, records of 
gross findings for a specimen from postmortem observations shall be 
available to a pathologist when examining that specimen 
histopathologically.
    (v) All data generated during the conduct of a study, except those 
that are generated by automated data collection systems, shall be 
recorded directly, promptly, and legibly in ink. All data entries shall 
be dated on the day of entry and signed or initialed by the person 
entering the data. Any change in entries shall be made so as not to 
obscure the original entry, shall indicate the reason for such change, 
and shall be dated and signed or identified at the time of the change. 
In automated data collection systems, the individual responsible for 
direct data input shall be identified at the time of data input. Any 
change in automated data entries shall be made so as not to obscure the 
original entry, shall indicate the reason for change, shall be dated, 
and the responsible individual shall be identified.
    (h) Records and Reports--(1) Reporting of study results. (i) A final 
report shall be prepared for each study and shall include, but not 
necessarily be limited to, the following:
    (A) Name and address of the facility performing the study and the 
dates on which the study was initiated and was completed, terminated, or 
discontinued.
    (B) Objectives and procedures stated in the approved protocol, 
including any changes in the original protocol.
    (C) Statistical methods employed for analyzing the data.
    (D) The test fuel, additive/base fuel mixture, and test and 
reference substances identified by name, chemical abstracts service 
(CAS) number or code number, strength, purity, content, or other 
appropriate characteristics.
    (E) Stability, and when relevant to the conduct of the study, the 
solubility of the test emissions and reference substances under the 
conditions of administration.
    (F) A description of the methods used.
    (G) A description of the test system used. Where applicable, the 
final report shall include the number of animals or other test organisms 
used, sex, body weight range, source of supply, species, strain and 
substrain, age, and procedure used for identification.
    (H) A description of the concentration regimen as daily exposure 
period, i.e., number of hours, and exposure duration, i.e., number of 
days.
    (I) A description of all circumstances that may have affected the 
quality or integrity of the data.
    (J) The name of the study director, the names of other scientists or 
professionals and the names of all supervisory personnel, involved in 
the study.
    (K) A description of the transformations, calculations, or 
operations performed on the data, a summary and analysis of the data, 
and a statement of the conclusions drawn from the analysis.
    (L) The signed and dated reports of each of the individual 
scientists or other professionals involved in the study, including each 
person who, at the request or direction of the testing

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facility or sponsor, conducted an analysis or evaluation of data or 
specimens from the study after data generation was completed.
    (M) The locations where all specimens, raw data, and the final 
report are to be kept or stored.
    (N) The statement, prepared and signed by the quality assurance 
unit, as described in Sec. 79.60(b)(4)(i)(G).
    (ii) The final report shall be signed and dated by the study 
director.
    (iii) Corrections or additions to a final report shall be in the 
form of an amendment by the study director. The amendment shall clearly 
identify that part of the final report that is being added to or 
corrected and the reasons for the correction or addition, and shall be 
signed and dated by the person responsible. Modification of a final 
report to comply with the submission requirements of EPA does not 
constitute a correction, addition, or amendment to a final report.
    (iv) A copy of the final report and of any amendment to it shall be 
maintained by the sponsor and the test facility.
    (2) Storage and retrieval of records and data. (i) All raw data, 
documentation, records, protocols, specimens, and final reports 
generated as a result of a study shall be retained. Specimens obtained 
from mutagenicity tests, wet specimens of blood, urine, feces, and 
biological fluids, do not need to be retained after quality assurance 
verification. Correspondence and other documents relating to 
interpretation and evaluation of data, other than those documents 
contained in the final report, also shall be retained.
    (ii) All raw data, documentation, protocols, specimens, and interim 
and final reports shall be archived for orderly storage and expedient 
retrieval. Conditions of storage shall minimize deterioration of the 
documents or specimens in accordance with the requirements for the time 
period of their retention and the nature of the documents of specimens. 
A testing facility may contract with commercial archives to provide a 
repository for all material to be retained. Raw data and specimens may 
be retained elsewhere provided that the archives have specific reference 
to those other locations.
    (iii) An individual shall be identified as responsible for the 
archiving of records.
    (iv) Access to archived material shall require authorization and 
documentation.
    (v) Archived material shall be indexed to permit expedient 
retrieval.
    (3) Retention of records. (i) Record retention requirements set 
forth in this section do not supersede the record retention requirements 
of any other regulations in this subchapter.
    (ii) Except as provided in paragraph (h)(3)(iii) of this section, 
documentation records, raw data, and specimens pertaining to a study and 
required to be retained by this part shall be archived for a period of 
at least ten years following the completion of the study.
    (iii) Wet specimens, samples of test fuel, additive/base fuel 
mixtures, or reference substances, and specially prepared material which 
are relatively fragile and differ markedly in stability and quality 
during storage, shall be retained only as long as the quality of the 
preparation affords evaluation. Specimens obtained from mutagenicity 
tests, wet specimens of blood, urine, feces, biological fluids, do not 
need to be retained after quality assurance verification. In no case 
shall retention be required for a longer period than that set forth in 
paragraph (h)(3)(ii) of this section.
    (iv) The master schedule sheet, copies of protocols, and records of 
quality assurance inspections, as required by Sec. 79.60(b)(4)(iii) 
shall be maintained by the quality assurance unit as an easily 
accessible system of records for the period of time specified in 
paragraph (h)(3)(ii) of this section.
    (v) Summaries of training and experience and job descriptions 
required to be maintained by Sec. 79.60(b)(1)(ii) may be retained along 
with all other testing facility employment records for the length of 
time specified in paragraph (h)(3)(ii) of this section.
    (vi) Records and reports of the maintenance and calibration and 
inspection of equipment, as required by Sec. 79.60(d)(2) (ii) and (iii), 
shall be retained for the length of time specified in paragraph 
(h)(3)(ii) of this section.

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    (vii) If a facility conducting testing or an archive contracting 
facility goes out of business, all raw data, documentation, and other 
material specified in this section shall be transferred to the sponsor 
of the study for archival.
    (viii) Records required by this section may be retained either as 
original records or as true copies such as photocopies, microfilm, 
microfiche, or other accurate reproductions of the original records.



Sec. 79.61  Vehicle emissions inhalation exposure guideline.

    (a) Purpose. This guideline provides additional information on 
methodologies required to conduct health effects tests involving 
inhalation exposures to vehicle combustion emissions from fuels or fuel/
additive mixtures. Where this guideline and the other health effects 
testing guidelines in 40 CFR 79.62 through 79.68 specify differing 
values for the same test parameter, the specifications in the individual 
health test guideline shall prevail for that health effect endpoint.
    (b) Definitions. For the purposes of this section the following 
definitions apply.
    Acute inhalation study means a short-term toxicity test 
characterized by a single exposure by inhalation over a short period of 
time (at least 4 hours and less than 24 hours), followed by at least 14 
days of observation.
    Aerodynamic diameter means the diameter of a sphere of unit density 
that has the same settling velocity as the particle of the test 
substance. It is used to compare particles of different sizes, densities 
and shapes, and to predict where in the respiratory tract such particles 
may be deposited. It applies to the size of aerosol particles.
    Chronic inhalation study means a prolonged and repeated exposure by 
inhalation for the life span of the test animal; technically, two years 
in the rat.
    Concentration means an exposure level. Exposure is expressed as 
weight or volume of test aerosol/substance per volume of air, usually 
mg/m3 or as parts per million (ppm) over a given time period. 
Micrograms per cubic meter (g/m3) or parts per billion may 
be appropriate, as well.
    Cumulative toxicity means the adverse effects of repeated exposures 
occurring as a result of prolonged action or increased concentration of 
the administered test substance or its metabolites in the susceptible 
tissues.
    Inhalable diameter means that aerodynamic diameter of a particle 
which is considered to be inhalable for the organism. It is used to 
refer to particles which are capable of being inhaled and may be 
deposited anywhere within the respiratory tract from the trachea to the 
alveoli.
    Mass median aerodynamic diameter (MMAD) means the calculated 
aerodynamic diameter, which divides the particles of an aerosol in half 
based on the mass of the particles. Fifty percent of the particles in 
mass will be larger than the median diameter, and fifty percent will be 
smaller than the median diameter. MMAD describes the particle 
distribution of any aerosol based on the weight and size of the 
particles. MMAD and the geometric standard deviation describe the 
particle-size distribution.
    Material safety data sheet (MSDS) means documentation or information 
on the physical, chemical, and hazardous characteristics of a given 
chemical, usually provided by the product's manufacturer.
    Reynolds number means a dimensionless number that is proportional to 
the ratio of inertial forces to frictional forces acting on a fluid. It 
quantitatively provides a measure of whether flow is laminar or 
turbulent. A fluid traveling through a pipe is fully developed into a 
laminar flow for a Reynolds number less than 2000, and fully developed 
into a turbulent flow for a Reynolds number greater than 4000.
    Subacute inhalation toxicity means the adverse effects occurring as 
a result of the repeated daily exposure of experimental animals to a 
chemical by inhalation for part (less than 10 percent) of a lifespan; 
generally, less than 90 days.
    Subchronic inhalation study means a repeated exposure by inhalation 
for part (approximately 10 percent) of a life span of the exposed test 
animal.

[[Page 444]]

    Toxic effect means an adverse change in the structure or function of 
an experimental animal as a result of exposure to a chemical substance.
    (c) Principles and design criteria of inhalation exposure systems. 
Proper conduct of inhalation toxicity studies of the emissions of fuels 
and additive/fuel mixtures requires that the exposure system be designed 
to ensure the controlled generation of the exposure atmosphere, the 
adequate dilution of the test emissions, delivery of the diluted 
exposure atmosphere to the test animals, and use of appropriate exposure 
chamber systems selected to meet criteria for a given exposure study.
    (1) Emissions generation. Emissions shall be generated according to 
the specifications in 40 CFR 79.57.
    (2) Dilution and delivery systems.
    (i) The delivery system is the means used to transport the emissions 
from the generation system to the exposure system. The dilution system 
is generally a component of the delivery system.
    (ii) Dilution provides control of the emissions concentration 
delivered to the exposure system, serving the function of diluting the 
associated combustion gases, such as carbon monoxide, carbon dioxide, 
nitrogen oxides, sulfur dioxide and other noxious gases and vapors, to 
levels that will ensure that there are no significant or measurable 
responses in the test animals as a result of exposure to the combustion 
gases. The formation of particle species is strongly dependent on the 
dilution rate, as well.
    (iii) The engine exhaust system shall connect to the first-stage-
dilution section at 90 deg. to the axis of the dilution section. This is 
then connected to a right angle elbow on the center line of the dilution 
section. Engine emissions are injected through the elbow so that exhaust 
flow is concurrent to dilution flow.
    (iv) Materials. In designing the dilution and delivery systems, the 
use of plastic, e.g., PVC and similar materials, copper, brass, and 
aluminum pipe and tubing shall be avoided if there exists a possibility 
of chemical reaction occurring between emissions and tubing. Stainless 
steel pipe and tubing is recommended as the best choice for most 
emission dilution and delivery applications, although glass and teflon 
may be appropriate, as well.
    (v) Flow requirements. (A) Conduit for dilute raw emissions shall be 
of such dimensions as to provide residence times for the emissions on 
the order of less than one second to several seconds before the 
emissions are further diluted and introduced to the test chambers. With 
the high flow rates in the dilute raw emissions conduit, it will be 
necessary to sample various portions of the dilute emissions for 
delivering differing concentrations to the test chambers. The unused 
portions of the emissions stream are normally exhausted to the 
atmosphere outside of the exposure facility.
    (B) Dimensions of the dilute raw exhaust conduit shall be such that, 
at a minimum, the flow Reynolds number is 70,000 or greater (see Mokler, 
et al., 1984 in paragraph (f)(13) of this section). This will maintain 
highly turbulent flow conditions so that there is more complete mixing 
of the exhaust emissions.
    (C) Wall losses. The delivery system shall be designed to minimize 
wall losses. This can be done by sizing the tubing or pipe to maintain 
laminar flow of the diluted emissions to the exposure chamber. A flow 
Reynolds number of 1000-3000 will ensure minimal wall losses. Also, the 
length of and number and degree of bends in the delivery lines to the 
exposure chamber system shall be minimized.
    (D) Whole-body exposure vs. nose-only exposure delivery systems. 
Flow rates through whole-body chamber systems are of the order of 100 
liters per minute to 500 liters per minute. Nose-only systems are on the 
order of less than 50 liters per minute. To maintain laminar flow 
conditions, the principles described in paragraph (c)(2)(v)(C) of this 
section apply to both systems.
    (vi) Dilution requirements. (A) To maintain the water vapor, and 
dissolved organic compounds, in the raw exhaust emissions stream, a 
manufacturer/tester will initially dilute one part emissions with a 
minimum of five parts clean, filtered air (see Hinners, et al., 1979 in 
paragraph (f)(11) of this section). Depending on the water vapor content 
of a particular fuel/additive

[[Page 445]]

mixture's combustion emissions and the humidity of the dilution air, 
initial exhaust dilutions as high as 1:15 or 1:20 may be necessary to 
maintain the general character of the exhaust as it cools, e.g., M100. 
At this point, it is expected that the exhaust stream would be further 
diluted to more appropriate levels for rodent health effects testing.
    (B) A maximum concentration (minimum dilution) of the raw exhaust 
going into the test animal cages is anticipated to lie in the range 
between 1:5 and 1:50 exhaust emissions to clean, filtered air. The 
minimum concentration (maximum dilution) of raw exhaust for health 
effects testing is anticipated to be in range between 1:100 and 1:150. 
Individual manufacturers will treat these ranges as approximations only 
and will determine the optimum range of emission concentrations to 
elicit effects in Tier 2 health testing for their particular fuel/fuel 
additive mixture.
    (3) Exposure chamber systems--(i) Referenced Guidelines. (A) The 
U.S. Department of Health and Human Services ``Guide for the Care and 
Use of Laboratory Animals'' (Guide), 1985 cited in paragraph 
(c)(3)(ii)(A)(4), and in paragraphs (d)(2)(i), (d)(2)(ii), (d)(2)(iii), 
(d)(4)(ii), and (d)(4)(iii) of this section, has been incorporated by 
reference.
    (B) This incorporation by reference was approved by the Director of 
the Federal Register in accordance with 5 U.S.C. 552(a) and 1 CFR part 
51. Copies may be purchased from the Superintendent of Documents, U.S. 
Government Printing Office, Washington, DC 20402. Copies may be 
inspected at U.S. EPA, OAR, 401 M Street SW., Washington, DC, 20460 or 
at the Office of the Federal Register, 800 North Capitol Street NW., 
suite 700, Washington, DC.
    (ii) Exposure chambers. There are two basic types of dynamic 
inhalation exposure chambers, whole-body chambers and nose-/head-only 
exposure chambers (see Cheng and Moss, 1989 in paragraph (f)(8) of this 
section).
    (A) Whole-body chambers. (1) The flow rate through a chamber shall 
be maintained at 15 air changes per hour.
    (2) The chambers are usually maintained at a slightly negative 
pressure (0.5 to 1.5 inch of water) to prevent leakage of test substance 
into the exposure room.
    (3) The exposure chamber shall be designed in such a way as to 
provide uniform distribution of exposure concentrations in all 
compartments (see Cheng et al., 1989 in paragraph (f)(7) of this 
section).
    (4) Animals are housed in separate compartments inside the chamber, 
where the whole surface area of an animal is exposed to the test 
material. The spaces required for different animal species shall follow 
the Guide. In general, the volume of animal bodies occupy less than 5 
percent of the chamber volume.
    (B) Head/nose-only exposure chambers. (1) In head/nose-only exposure 
chambers, only the head (oronasal) portion of the animal is exposed to 
the test material.
    (2) The chamber volume and flow rates are much less than in the 
whole-body exposure chambers because the subjects are usually restrained 
in a tube holder where the animal's breathing can be easily monitored. 
The head/nose-only exposure chamber is suitable for short-term exposures 
or when use of a small amount of test material is required.
    (iii) Since whole-body exposure appears to be the least stressful 
mode of exposure, it is the preferred method. In general, head/nose only 
exposure, which is sometimes used to avoid concurrent exposure by the 
dermal or oral routes, i.e., grooming, is not recommended because of the 
stress accompanying the restraining of the animals. However, there may 
be specific instances where it may be more appropriate than whole-body 
exposure. The tester shall provide justification for its selection.
    (d) Inhalation exposure procedures--(1) Animal selection. (i) The 
rat is the preferred species for vehicle emission inhalation health 
effects testing. Commonly used laboratory strains shall be used. Any 
rodent species may be used, but the tester shall provide justification 
for the choice of that species.
    (ii) Young adult animals, approximately ten weeks of age for the 
rat, shall be used. At the commencement of the study, the weight 
variation of animals used shall not exceed 20 percent of the 
mean weight for each sex. Animals shall be randomly assigned to

[[Page 446]]

treatment and control groups according to their weight.
    (iii) An equal number of male and female rodents shall be used at 
each concentration level. Situations may arise where use of a single sex 
may be appropriate. Females, in general, shall be nulliparous and 
nonpregnant.
    (iv) The number of animals used at each concentration level and in 
the control group(s) depends on the type of study, number of biological 
end points used in the toxicity evaluation, the pre-determined 
sensitivity of detection and power of significance of the study, and the 
animal species. For an acute study, at least five animals of each sex 
shall be used in each test group. For both the subacute and subchronic 
studies, at least 10 rodents of each sex shall be used in each test 
group. For a chronic study, at least 20 male and 20 female rodents shall 
be used in each test group.
    (A) If interim sacrifices are planned, the number of animals shall 
be increased by the number of animals scheduled to be sacrificed during 
the course of the study.
    (B) For a chronic study, the number of animals at the termination of 
the study must be adequate for a meaningful and valid statistical 
evaluation of chronic effects.
    (v) A concurrent control group is required. This group shall be 
exposed to clean, filtered air under conditions identical to those used 
for the group exposed to the test atmosphere.
    (vi) The same species/strain shall be used to make comparisons 
between fuel-only and fuel/additive mixture studies. If another species/
strain is used, the tester shall provide justification for its 
selection.
    (2) Animal handling and care. (i) A key element in the conduct of 
inhalation exposure studies is the proper handling and care of the test 
animal population. Therefore, the exposure conditions must conform 
strictly with the conditions for housing and animal care and use set 
forth in the Guide.
    (ii) In whole-body exposure chambers, animals shall be housed in 
individual caging. The minimum cage size per animal will be in 
accordance with instructions set forth in the Guide.
    (iii) Chambers shall be cleaned and maintained in accordance with 
recommendations and schedules set forth in the Guide.
    (A) Observations shall be made daily with appropriate actions taken 
to minimize loss of animals to the study (e.g., necropsy or 
refrigeration of animals found dead and isolation or sacrifice of weak 
or moribund animals). Exposure systems using head/nose-only exposure 
chambers require no special daily chamber maintenance. Chambers shall be 
inspected to ensure that they are clean, and that there are no 
obstructions in the chamber which would restrict air flow to the 
animals. Whole-body exposure chambers will be inspected on a minimum of 
twice daily, once before exposures and once after exposures.
    (B) Signs of toxicity shall be recorded as they are observed, 
including the time of onset, degree, and duration.
    (C) Cage-side observations shall include, but are not limited to: 
changes in skin, fur, eye and mucous membranes, respiratory, autonomic, 
and central nervous systems, somatomotor activity, and behavioral 
patterns. Particular attention shall be directed to observation of 
tremors, convulsions, salivation, diarrhea, lethargy, sleep, and coma.
    (iv) Food and water will be withheld from animals for head/nose-only 
exposure systems. For whole-body-exposure systems, water only may be 
provided. When the exposure generation system is not operating, food 
will be available ad libitum. During operation of the generation system, 
food will be withheld to avoid possible contamination by emissions.
    (v) At the end of the study period, all survivors in the main study 
population shall be sacrificed. Moribund animals shall be removed and 
sacrificed when observed.
    (3) Concentration levels and selection. (i) In acute and subacute 
toxicity tests, at least three exposure concentrations and a control 
group shall be used and spaced appropriately to produce test groups with 
a range of toxic effects and mortality rates. The data shall be 
sufficient to produce a concentration-response curve and permit an 
acceptable

[[Page 447]]

estimation of the median lethal concentration.
    (ii) In subchronic and chronic toxicity tests, testers shall use at 
least three different concentration levels, with a control exposure 
group, to determine a concentration-response relationship. 
Concentrations shall be spaced appropriately to produce test groups with 
a range of toxic effects. The concentration-response data may also be 
sufficient to determine a NOAEL, unless the result of a limit test 
precludes such findings. The criteria for selecting concentration levels 
has been published (40 CFR 798.2450 and 798.3260).
    (A) The highest concentration shall result in toxic effects but not 
produce an incidence of fatalities which would prevent a meaningful 
evaluation of the study.
    (B) The lowest concentration shall not produce toxic effects which 
are directly attributable to the test exposure. Where there is a useful 
estimation of human exposure, the lowest concentration shall exceed 
this.
    (C) The intermediate concentration level(s) shall produce minimal 
observable toxic effects. If more than one intermediate concentration 
level is used, the concentrations shall be spaced to produce a gradation 
of toxic effects.
    (D) In the low, intermediate, and control exposure groups, the 
incidence of fatalities shall be low to absent, so as not to preclude a 
meaningful evaluation of the results.
    (4) Exposure chamber environmental conditions. The following 
environmental conditions in the exposure chamber are critical to the 
maintenance of the test animals: flow; temperature; relative humidity; 
lighting; and noise.
    (i) Filtered and conditioned air shall be used during exposure, to 
dilute the exhaust emissions, and during non- exposure periods to 
maintain environmental conditions that are free of trace gases, dusts, 
and microorganisms on the test animals. Twelve to fifteen air changes 
per hour will be provided at all times to whole-body-exposure chambers. 
The minimum air flow rate for head/nose-only exposure chambers will be a 
function of the number of animals and the average minute volume of the 
animals:

Qminimum(L/min)=2  x  number of animals  x  average minute volume

(see Cheng and Moss, 1989 in paragraph (f)(8) of this section).
    (ii) Recommended ranges of temperature for various species are given 
in the Guide. The recommended temperature ranges will be used for 
establishing temperature conditions of whole-body- exposure chambers. 
For rodents in whole-body-exposure chambers, the recommended temperature 
is 22  deg.C +/- 2  deg.C and for rabbits, it is 20  deg.C +/- 3  deg.C. 
Temperature ranges have not been established for head/nose-only tubes; 
however, recommended maximum temperature limits have been established at 
the Inhalation Toxicology Research Institute (see Barr, 1988 in 
paragraph (f)(1) of this section). Maximum temperature for rats and mice 
in head/nose-only tubes is 23  deg.C.
    (iii) Relative humidity. The relative humidity in the chamber air is 
important for heat balance and shall be maintained between 40 percent 
and 60 percent, but in certain instances, this may not be practicable. 
Testers shall follow Guide recommends for a 30 percent to 70 percent 
relative humidity range for rodents in exposure chambers.
    (iv) Lighting. Light intensity of 30 foot candles at 3 ft. from the 
floor of the exposure facility is recommended (see Rao, 1986 in 
paragraph (f)(16) of this section).
    (5) Exposure Conditions. Study animals shall be exposed to the test 
atmosphere on a repeated basis for at least 6 hours per day on a 7-day 
per week basis for the exposure period. However, based primarily on 
practical considerations, exposure on a 5-day-per-week basis for a 
minimum of 6 hours per day is the minimum acceptable exposure period.
    (6) Exposure atmosphere. (i) The exposure atmosphere shall be held 
as constant as is practicable and must be monitored continuously or 
intermittently, depending on the method of analysis, to ensure that 
exposure levels are at the target values or within stated limits during 
the exposure period. Sampling methodology will be determined based on 
the type of generation

[[Page 448]]

system and the type of exposure chamber system specified for the 
exposure study.
    (A) Integrated samples of test atmosphere aerosol shall be taken 
daily during the exposure period from a single representative sample 
port in the chamber near the breathing zone of the animals. Gas samples 
shall be taken daily to determine concentrations (ppm) of the major 
vapor components of the test atmosphere including CO, CO2, 
NOX, SO2, and total hydrocarbons.
    (B) To ensure that animals in different locations of the chamber 
receive a similar exposure atmosphere, distribution of an aerosol or 
vapor concentration in exposure chambers can be determined without 
animals during the developmental phase of the study, or it can be 
determined with animals early in the study. For head/nose-only exposure 
chambers, it may not be possible to monitor the chamber distribution 
during the exposure, because the exposure port contains the animal.
    (C) During the development of the emissions generation system, 
particle size analysis shall be performed to establish the stability of 
an aerosol concentration with respect to particle size. Over the course 
of the exposure, analysis shall be conducted as often as is necessary to 
determine the consistency of particle size distribution.
    (D) Chamber rise and fall times. The rise time required for the 
exposure concentration to reach 90 percent of the stable concentration 
after the generator is turned on, and the fall time when the chamber 
concentration decreases to 10 percent of the stable concentration after 
the generation system is stopped shall be determined in the 
developmental phase of the study. Time-integrated samples collected for 
calculating exposure concentrations shall be taken after the rise time. 
The daily exposure time is exclusive of the rise or the fall time.
    (ii) Instrumentation used for a given study will be determined based 
on the type of generation system and the type of exposure chamber system 
specified for the exposure study.
    (A) For exhaust studies, combustion gases shall be sampled by 
collecting exposure air in bags and then analyzing the collected air 
sample to determine major components of the combustion gas using gas 
analyzers. Exposure chambers can also be connected to gas analyzers 
directly by using sampling lines and switching valves. Samples can be 
taken more frequently using the latter method. Aerosol instruments, such 
as photometers, or time-integrated gravimetric determination may be used 
to determine the stability of any aerosol concentration in the chamber.
    (B) For evaporative emission studies, concentration of fuel vapors 
can usually be determined by using a gas chromatograph (GC) and/or 
infrared (IR) spectrometry. Grab samples for intermittent sampling can 
be taken from the chamber by using bubble samplers with the appropriate 
solvent to collect the vapors, or by collecting a small volume of air in 
a syringe. Intermediate or continuous monitoring of the chamber 
concentration is also possible by connecting the chamber with a GC or IR 
detector.
    (7) Monitoring chamber environmental conditions may be performed by 
a computer system or by exposure system operating personnel.
    (i) The flow-metering device used for the exposure chambers must be 
a continuous monitoring device, and actual flow measurements must be 
recorded at least every 30 minutes. Accuracy must be 5 
percent of full scale range. Measurement of air flow through the 
exposure chamber may be accomplished using any device that has 
sufficient range to accurately measure the air flow for the given 
chamber. Types of flow metering devices include rotameters, orifice 
meters, venturi meters, critical orifices, and turbinemeters (see 
Benedict, 1984 in paragraph (f)(4) and Spitzer, 1984 in paragraph 
(f)(17) of this section).
    (ii) Pressure. Pressure measurement may be accomplished using 
manometers, electronic pressure transducers, magnehelics, or similar 
devices (see Gillum, 1982 in paragraph (f)(10) of this section). 
Accuracy of the pressure device must be 5 percent of full 
scale range. Pressure measurements must be continuous and recorded at 
least every 30 minutes.
    (iii) Temperature. The temperature of exposure chambers must be 
monitored

[[Page 449]]

continuously and recorded at least every 30 minutes. Temperature may be 
measured using thermometers, RTD's, thermocouples, thermistors, or other 
devices (see Benedict, 1984 in paragraph (f)(4) of this section). It is 
necessary to incorporate an alarm system into the temperature monitoring 
system. The exposure operators must be notified by the alarm system when 
the chamber temperature exceeds 26.7  deg.C (80  deg.F). The exposure 
must be discontinued and emergency procedures enacted to immediately 
reduce temperatures or remove test animals from high temperature 
environment when chamber temperatures exceed 29  deg.C. Accuracy of the 
temperature monitoring device will be 1  deg.C for the 
temperature range of 20-30  deg.C.
    (iv) Relative humidity. The relative humidity of exposure chambers 
must be monitored continuously and recorded at least every 30 minutes. 
Relative humidity may be measured using various devices (see Chaddock, 
1985 in paragraph (f)(6) of this section).
    (v) Lighting shall be measured quarterly, or once at the beginning, 
middle, and end of the study for shorter studies.
    (vi) Noise level in the exposure chamber(s) shall be measured 
quarterly, or once at the beginning, middle, and end of the study for 
shorter studies.
    (vii) Oxygen content is critical, especially in nose-only chamber 
systems, and shall be greater than or equal to 19 percent in the test 
cages. An oxygen sensor shall be located at a single position in the 
test chamber and a lower alarm limit of 18 percent shall be used to 
activate an alarm system.
    (8) Safety procedures and requirements. In the case of potentially 
explosive test substance concentrations, care shall be taken to avoid 
generating explosive atmospheres.
    (i) It is mandatory that the upper explosive limit (UEL) and lower 
explosive limit (LEL) for the fuel and/or fuel additive(s) that are 
being tested be determined. These limits can be found in the material 
safety data sheets (MSDS) for each substance and in various reference 
texts. The air concentration of the fuel or additive-base fuel mixture 
in the generation system, dilution/delivery system, and the exposure 
chamber system shall be calculated to ensure that explosive limits are 
not present.
    (ii) Storage, handling, and use of fuels or fuel/additive mixtures 
shall follow guidelines given in 29 CFR 1910.106.
    (iii) Monitoring for carbon monoxide (CO) levels is mandatory for 
combustion systems. CO shall be continuously monitored in the immediate 
area of the engine/vehicle system and in the exposure chamber(s).
    (iv) Air samples shall be taken quarterly in the immediate area of 
the vapor generation system and the exposure chamber system, or once at 
the beginning, middle, and end of the study for shorter studies. These 
samples shall be analyzed by methods described in paragraph 
(d)(6)(ii)(B) of this section.
    (v) With the presence of fuels and/or fuel additives, all electrical 
and electronic equipment must be grounded. Also, the dilution/delivery 
system and chamber exposure system must be grounded. Guidelines for 
grounding are given in 29 CFR 1910.304.
    (9) Quality control and quality assurance procedures--(i) Standard 
operating procedures (SOPs). SOPs for exposure operations, sampling 
instruments, animal handling, and analytical methods shall be written 
during the developmental phase of the study.
    (ii) Technicians/operators shall be trained in exposure operation, 
maintenance, and documentation, as appropriate, and their training shall 
be documented.
    (iii) Flow meters, sampling instruments, and balances used in the 
inhalation experiments shall be calibrated with standards during the 
developmental phase to determine their sensitivity, detection limits, 
and linearity. During the exposure period, instruments shall be checked 
for calibration and documented to ensure that each instrument still 
functions properly.
    (iv) The mean exposure concentration shall be within 10 percent of 
the target concentration on 90 percent or more of exposure days. The 
coefficient of variation shall be within 25 percent

[[Page 450]]

of target on 90 percent or more of exposure days. For example, a 
manufacturer might determine a mean exposure concentration of its 
product's exposure emissions by identifying ``marker'' compound(s) 
typical of the emissions of the fuel or fuel/additive mixture under 
study as a surrogate for the total of individual compounds in those 
exposure emissions. The manufacturer would note any concentration 
changes in the level of the ``marker'' compound(s) in the sample's daily 
emissions for biological testing.
    (v) The spatial variation of the chamber concentration shall be 10 
percent, or less. If a higher spatial variation is observed during the 
developmental phase, then air mixing in the chamber shall be increased. 
In any case, animals shall be rotated among the various cages in the 
exposure chamber(s) to insure each animal's uniform exposure during the 
study.
    (e) Data and reporting. Data shall be summarized in tabular form, 
showing for each group the number of animals at the start of the test, 
the number of animals showing lesions, the types of lesions, and the 
percentage of animals displaying each type of lesion.
    (1) Treatment of results. All observed results, quantitative and 
incidental, shall be evaluated by an appropriate statistical method. Any 
generally accepted statistical method may be used; the statistical 
methods shall be selected during the design of the study.
    (2) Evaluation of results. The findings of an inhalation toxicity 
study should be evaluated in conjunction with the findings of preceding 
studies and considered in terms of the observed toxic effects and the 
necropsy and histopathological findings. The evaluation will include the 
relationship between the concentration of the test atmosphere and the 
duration of exposure, and the severity of abnormalities, gross lesions, 
identified target organs, body weight changes, effects on mortality and 
any other general or specific toxic effects.
    (3) Test conditions. (i) The exposure apparatus shall be described, 
including:
    (A) The vehicle/engine design and type, the dynamometer, the cooling 
system, if any, the computer control system, and the dilution system for 
exhaust emission generation;
    (B) The evaporative emissions generator model, type, or design and 
its dilution system; and
    (C) Other test conditions, such as the source and quality of mixing 
air, fuel or fuel/additive mixture used, treatment of exhaust air, 
design of exposure chamber and the method of housing animals in a test 
chamber shall be described.
    (ii) The equipment for measuring temperature, humidity, particulate 
aerosol concentrations and size distribution, gas analyzers, fuel vapor 
concentrations, chamber distribution, and rise and fall time shall be 
described.
    (iii) Daily exposure results. The daily record shall document the 
date, the start and stop times of the exposure, number of samples taken 
during the day, daily concentrations determined, calibration of 
instruments, and problems encountered during the exposure. The daily 
exposure data shall be signed by the exposure operator and reviewed and 
signed by the exposure supervisor responsible for the study.
    (4) Exposure data shall be tabulated and presented with mean values 
and a measure of variability (e.g., standard deviation), and shall 
include:
    (i) Airflow rates through the inhalation equipment;
    (ii) Temperature and humidity of air;
    (iii) Chamber concentrations in the chamber breathing zone;
    (iv) Concentration of combustion exhaust gases in the chamber 
breathing zone;
    (v) Particle size distribution (e.g., mass median aerodynamic 
diameter and geometric standard deviation from the mean);
    (vi) Rise and fall time;
    (vii) Chamber concentrations during the non-exposure period; and
    (viii) Distribution of test substance in the chamber.
    (5) Animal data. Tabulation of toxic response data by species, 
strain, sex and exposure level for:
    (i) Number of animals exposed;
    (ii) Number of animals showing signs of toxicity; and
    (iii) Number of animals dying.

[[Page 451]]

    (f) References. For additional background information on this 
exposure guideline, the following references should be consulted.

    (1) Barr, E.B. (1988) Operational Limits for Temperature and Percent 
Oxygen During HM Nose-Only Exposures--Emergency Procedures [interoffice 
memorandum]. Albuquerque, NM: Lovelace Inhalation Toxicology Research 
Institute; May 13.
    (2) Barr, E.B.; Cheng, Y.S.; Mauderly, J.L. (1990) Determination of 
Oxygen Depletion in a Nose-Only Exposure Chamber. Presented at: 1990 
American Association for Aerosol Research; June; Philadelphia, PA: 
American Association for Aerosol Research; abstract no. P2e1.
    (3) Barrow, C.S. (1989) Generation and Characterization of Gases and 
Vapors. In: McClellan, R.O., Henderson, R.F. ed. Concepts in Inhalation 
Toxicology. New York, NY: Hemisphere Publishing Corp., 63-84.
    (4) Benedict, R.P. (1984) Fundamentals of Temperature, Pressure, and 
Flow Measurements. 3rd ed. New York, NY: John Wiley and Sons.
    (5) Cannon, W.C.; Blanton, E.F.; McDonald, K.E. The Flow-Past 
Chamber. (1983) An Improved Nose-Only Exposure System for Rodents. Am. 
Ind. Hyg. Assoc. J. 44: 923-928.
    (6) Chaddock, J.B. ed. (1985) Moisture and humidity. Measurement and 
Control in Science and Industry: Proceedings of the 1985 International 
Symposium on Moisture and Humidity; April 1985; Washington, D.C. 
Research Triangle Park, NC: Instrument Society of America.
    (7) Cheng, Y.S.; Barr, E.B.; Carpenter, R.L.; Benson, J.M.; Hobbs, 
C.H. (1989) Improvement of Aerosol Distribution in Whole-Body Inhalation 
Exposure Chambers. Inhal. Toxicol. 1: 153-166.
    (8) Cheng,Y.S.; Moss, O.R. (1989) Inhalation Exposure Systems. In: 
McClellan, R.O.; Henderson, R.F. ed. Concepts in Inhalation Toxicology. 
New York, NY: Hemisphere Publishing Corp., 19-62.
    (9) Cheng, Y.S.; Yeh, H.C.; Mauderly, J.L.; Mokler, B.V. (1984) 
Characterization of Diesel Exhaust in a Chronic Inhalation Study. Am. 
Ind. Hyg. Assoc. J. 45: 547-555.
    (10) Gillum, D.R. (1982) Industrial Pressure Measurement. Research 
Triangle Park, NC: Instrument Society of America.
    (11) Hinners, R.G.; Burkart, J.K.; Malanchuk, M. (1979) Animal 
Exposure Facility for Diesel Exhaust Studies.
    (12) Kittelson, D.B.; Dolan, D.F. (1979) Diesel exhaust aerosols. In 
Willeke, K. ed. Generation of Aerosols and Facilities for Exposure 
Experiments. Ann Arbor, MI: Ann Arbor Science Publishers Inc., 337-360.
    (13) Mokler, B.V.; Archibeque, F.A.; Beethe, R.L.; Kelly, C.P.J.; 
Lopez, J.A.; Mauderly, J.L.; Stafford, D.L. (1984) Diesel Exhaust 
Exposure System for Animal Studies. Fundamental and Applied Toxicology 
4: 270-277.
    (14) Moore, W.; et al. (1978) Preliminary finding on the Deposition 
and Retention of Automotive Diesel Particulate in Rat Lungs. Proc. of 
Annual Meeting of the Air Pollution Control Assn, 3, paper 78-33.7.
    (15) Raabe, O.G., Bennick, J.E., Light, M.E., Hobbs, C.H., Thomas, 
R.L., Tillery, M.I. (1973) An Improved Apparatus for Acute Inhalation 
Exposure of Rodents to Radioactive Aerosols. Toxicol & Applied 
Pharmaco.; 1973; 26: 264-273.
    (16) Rao, G.N. (1986) Significance of Environmental Factors on the 
Test System. In: Hoover, B.K.; Baldwin, J.K.; Uelner, A.F.; Whitmire, 
C.E.; Davies, C.L.; Bristol, D.W. ed. Managing conduct and data quality 
of toxicology studies. Raleigh, NC: Princeton Scientific Publishing Co., 
Inc.: 173-185.
    (17) Spitzer, D.W. (1984) Industrial Flow Measurement. Research 
Triangle Park, NC: Instrument Society of America.
    (18) 40 CFR part 798, Health effects testing guidelines.
    (19) 29 CFR part 1910, Occupational safety and health standards for 
general industry.
    (20) Federal Register, 42 FR 26748, May 25, 1977.



Sec. 79.62  Subchronic toxicity study with specific health effect assessments.

    (a) Purpose--(1) General toxicity. This subchronic inhalation study 
is designed to determine a concentration-response relationship for 
potential toxic effects in rats resulting from continuous or repeated 
inhalation exposure to vehicle/engine emissions over a period of 90 
days. A subgroup of perfusion-fixed animals is required, in addition to 
the main study population, for more exacting organ and tissue histology. 
This test will provide screening information on target organ toxicities 
and on concentration levels useful for running chronic studies and 
establishing exposure criteria. Initial information on effective 
concentrations/exposures of the test atmosphere may be determined from 
the literature of previous studies or through concentration range-
finding trials prior to starting this study. This health effects 
screening test is not capable of directly determining those effects 
which have a long latency period for development (e.g., carcinogenicity 
and life-shortening), though it may permit the detremination of a no-
observed-adverse-effect level, or NOAEL.
    (2) Specific health effects assessments (HEAs). These supplemental 
studies are designed to determine the potential for

[[Page 452]]

reproductive/teratologic, carcinogenic, mutagenic, and neurotoxic health 
effect outcomes from vehicle/engine emission exposures. They are done in 
combination with the subchronic toxicity study and paragraph (c) of this 
section or may be done separately as outlined by the appropriate test 
guideline.
    (i) Fertility assessment/teratology. The fertility assessment is an 
in vivo study designed to provide information on potential health 
hazards to the fetus arising from the mother's repeated exposure to 
vehicle/engine emissions before and during her pregnancy. By including a 
mating of test animals, the study provides preliminary data on the 
effects of repeated vehicle/engine emissions exposure on gonadal 
function, conception, and fertility. The fertility assessment/teratology 
guideline is found in Sec. 79.63.
    (ii) Micronucleus (MN) Assay. The MN assay is an in vivo cytogenetic 
test which gives information on potential carcinogenic and/or mutagenic 
effects of exposure to vehicle/engine emissions. The MN assay detects 
damage to the chromosomes or mitotic apparatus of cells in the tissues 
of a test subject exposed repeatedly to vehicle/engine emissions. The 
assay is based on an increase in the frequency of micronucleated 
erythrocytes found in bone marrow from treated animals compared to that 
of control animals. The guideline for the MN assay is found in 
Sec. 79.64.
    (iii) Sister Chromatid Exchange (SCE) Assay. The SCE assay is an in 
vivo analysis which gives information on potential mutagenic and/or 
carcinogenic effects of exposure to vehicle/engine emissions. The assay 
detects the ability of a chemical to enhance the exchange of DNA between 
two sister chromatids of a duplicating chromosome. This assay uses 
peripheral blood lymphocytes isolated from an exposed rodent test 
species and grown to confluence in cell culture. The guideline for the 
SCE assay is found in Sec. 79.65.
    (iv) Neurotoxicity (NTX) measures. NTX measures include (A) 
histopathology of specified central and peripheral nervous system 
tissues taken from emission-exposed rodents, and (B) an assay of brain 
tissue levels of glial fibrillary acidic protein (GFAP), a major 
filament protein of astrocytes, from emission-exposed rodents. The 
guidelines for the neurohistopathology and GFAP studies are found in 
Sec. 79.66 and Sec. 79.67, respectively.
    (b) Definitions. For the purposes of this section, the following 
definitions apply:
    No-observed-adverse-effect-level (NOAEL) means the maximum 
concentration used in a test which produces no observed adverse effects. 
A NOAEL is expressed in terms of weight or volume of test substance 
given daily per unit volume of air (g/L or ppm).
    Subchronic inhalation toxicity means the adverse effects occurring 
as a result of the continuous or repeated daily exposure of experimental 
animals to a chemical by inhalation for part (approximately 10 percent) 
of a life span.
    (c) Principle of the test method. As long as none of the 
requirements of any study are violated by the combination, one or more 
HEAs may be combined with the general toxicity study through concurrent 
exposures of their study populations and/or by sharing the analysis of 
the same animal subjects. Requirements duplicated in combined studies 
need not be repeated. Guidelines for combining HEAs with the general 
toxicity study are as follows.
    (1) Fertility assessment. (i) The number of study animals in the 
test population is increased when the fertility assessment is run 
concurrently with the 90-day toxicity study. A minimum of 40 females per 
test group shall undergo vaginal lavage daily for two weeks before the 
start of the exposure period. The resulting wet smears are examined to 
cull those animals which are acyclic. Twenty-five females shall be 
randomly assigned to a for-breeding group with the balance of females 
assigned to a group for histopathologic examination.
    (ii) All test groups are exposed over a period of 90 days to various 
concentrations of the test atmosphere for a minimum of six hours per 
day. After seven weeks of exposures, analysis of vaginal cell smears 
shall resume on a daily basis for the 25 for-breeding females

[[Page 453]]

and shall continue for a period of four weeks or until each female in 
the group is confirmed pregnant. Following the ninth week of exposures, 
each for-breeding female is housed overnight with a single study male. 
Matings shall continue for as long as two weeks, or until pregnancy is 
confirmed (pregnancy day 0). Pregnant females are only exposed through 
day 15 of their pregnancy while daily exposures continue throughout the 
course of the study for non-pregnant females and study males.
    (iii) On pregnancy day 20, pregnant females are sacrificed and their 
uteri are examined. Pregnancy status and fetal effects are recorded as 
described in Sec. 79.63. At the end of the exposure period, all males 
and non-pregnant females are sacrificed and necropsied. Testes and 
epididymal tissue samples are taken from five perfusion-fixed test 
subjects and histopathological examinations are carried out on the 
remainder of the non-pregnant females and study males.
    (2) Carcinogenicity/mutagenicity
(C/M) assessment. When combined with the subchronic toxicity study, the 
main study population is used to perform both the in vivo MN and SCE 
assays. Because of the constant turnover of the cells to be analyzed in 
these assays, a separate study population may be used for this 
assessment. A study population needs only to be exposed a minimum of 
four weeks. At exposure's end, ten animals per exposure and control 
groups are anaesthetized and heart punctures are performed on all 
members. After separating blood components, individual lymphocyte cell 
cultures are set up for SCE analysis. One femur from each study subject 
is also removed and the marrow extracted. The marrow is smeared onto a 
glass slide, and stained for analysis of micronuclei in erythrocytes.
    (3) Neurotoxicity (NTX) measures. (i) When combined with this 
subchronic toxicity study, test animals designated for whole-body 
perfusion fixation/lung histology and exposed as part of the main animal 
population are used to perform the neurohistology portion of these 
measures. After the last exposure period, a minimum of ten animals from 
each exposure group shall be preserved in situ with fixative. Sections 
of brain, spinal cord, and proximal sciatic or tibial nerve are then 
cut, processed further in formalin, and mounted for viewing under a 
light microscope. Fibers from the sciatic or tibial nerve sample are 
teased apart for further analysis under the microscope.
    (ii) GFAP assay. After the last exposure period, a minimum of ten 
rodents from each exposure group shall be sacrificed, and their brains 
excised and divided into regions. The tissue samples are then applied to 
filter paper, washed with anti-GFAP antibody, and visualized with a 
radio-labelled Protein A. The filters are quantified for degree of 
immunoreactivity between the antibody and GFAP in the tissue samples. A 
non-radioactive ELISA format is also referenced in the GFAP guideline 
cited in paragraph (a)(2)(iv) of this section. Note: Because the GFAP 
assay requires fresh, i.e., non-preserved, brain tissue, the number of 
test animals may need to be increased to provide an adequate number of 
test subjects to complete the histopathology requirements of both the 
GFAP and the general toxicity portion of the 90-day inhalation study.
    (iii) The start of the exposure period for the NTX measures study 
population may be staggered from that of the main study group to more 
evenly distribute the analytical work required in both study 
populations. The exposures would remain the same in all other respects.
    (d) Test procedures--(1) Animal selection--(i) Species and sex. The 
rat is the recommended species. If another rodent species is used, the 
tester shall provide justification for its selection. Both sexes shall 
be used in any assessment unless it is demonstrated that one sex is 
refractory to the effects of exposure.
    (ii) Age and number. Rats shall be at least ten weeks of age at the 
beginning of the study exposure. The number of animals necessary for 
individual health effect outcomes is as follows:
    (A) Thirty rodents per concentration level/group, fifteen of each 
sex, shall be used to satisfy the reporting requirements of the 90-day 
toxicity study. Ten animals per concentration level/group

[[Page 454]]

shall be designated for whole body perfusion with fixative (by gravity) 
for lung studies, and neurohistology and testes studies, as appropriate.
    (B) Forty rodents, 25 females and ten males shall be added for each 
test concentration or control group when combining a 90-day toxicity 
study with a fertility assessment.
    (C) The tester shall provide a group of 10 animals (five animals per 
sex per experimental/control groups) in addition to the main test 
population when performing the GFAP neurotoxicity HEA.
    (2) Recovery group. The manufacturer shall include an group of 20 
animals (10 animals per sex) in the test population, exposing them to 
the highest concentration level for the entire length of the study's 
exposure period. This group shall then be observed for reversibility, 
persistence, or delayed occurrence of toxic effects during a post-
exposure period of not less than 28 days.
    (3) Inhalation exposure. (i) All data developed within this study 
shall be in accordance with good laboratory practice provisions under 
Sec. 79.60.
    (ii) The general conduct of this study shall be in accordance with 
the vehicle emissions inhalation exposure guideline in Sec. 79.61.
    (4) Observation of animals. (i) All toxicological (e.g., weight 
loss) and neurological signs (e.g., motor disturbance) shall be recorded 
frequently enough to observe any abnormality, and not less than weekly 
for all study animals. Animals shall be weighed weekly.
    (ii) The following is a minimal list of measures that shall be 
noted:
    (A) Body weight;
    (B) Subject's reactivity to general stimuli such as removal from the 
cage or handling;
    (C) Description, incidence, and severity of any convulsions, 
tremors, or abnormal motor movements in the home cage;
    (D) Descriptions and incidence of posture and gait abnormalities 
observed in the home cage;
    (E) Description and incidence of any unusual or abnormal behaviors, 
excessive or repetitive actions (stereotypies), emaciation, dehydration, 
hypotonia or hypertonia, altered fur appearance, red or crusty deposits 
around the eyes, nose, or mouth, and any other observations that may 
facilitate interpretation of the data.
    (iii) Any animal which dies during the test is necropsied as soon as 
possible after discovery.
    (5) Clinical examinations. (i) The following examinations shall be 
performed on the twenty animals designated as the 90-day study 
population, exclusive of pregnant dams and those study animals targeted 
for perfusion by gravity:
    (A) The following hematology determinations shall be carried out at 
least two times during the test period (after 30 days of exposure and 
just prior to terminal sacrifice at the end of the exposure period): 
hematocrit, hemoglobin concentration, erythrocyte count, total and 
differential leukocyte count, and a measure of clotting potential such 
as prothrombin time, thromboplastin time, or platelet count.
    (B) Clinical biochemistry determinations on blood shall be carried 
out at least two times during the test period, after 30 days of exposure 
and just prior to terminal sacrifice at the end of the exposure period, 
on all groups of animals including concurrent controls. Clinical 
biochemical testing shall include assessment of electrolyte balance, 
carbohydrate metabolism, and liver and kidney function. The selection of 
specific tests will be influenced by observations on the mode of action 
of the substance. In the absence of more specific tests, the following 
determinations may be made: calcium, phosphorus, chloride, sodium, 
potassium, fasting glucose (with period of fasting appropriate to the 
species), serum alanine aminotransferase, serum aspartate 
aminotransferase, sorbitol dehydrogenase, gamma glutamyl transpeptidase, 
urea nitrogen, albumen, blood creatinine, methemoglobin, bile acids, 
total bilirubin, and total serum protein measurements. Additional 
clinical biochemistry shall be employed, where necessary, to extend the 
investigation of observed effects, e.g., analyses of lipids, hormones, 
acid/base balance, and cholinesterase activity.
    (ii) The following examinations shall initially be performed on the 
high concentration and control groups only:

[[Page 455]]

    (A) Ophthalmological examination, using an ophthalmoscope or 
equivalent suitable equipment, shall be made prior to exposure to the 
test substance and at the termination of the study. If changes in the 
eyes are detected, all animals shall be examined.
    (B) Urinalysis is not required on a routine basis, but shall be done 
when there is an indication based on expected and/or observed toxicity.
    (iii) Preservation by whole-body perfusion of fixative into the 
anaesthetized animal for lung histology of ten animals from the 90-day 
study population for each experimental and control group.
    (6) Gross pathology. With the exception of the whole body perfusion-
fixed test animals cited in paragraph (d)(1)(ii)(A) of this section, all 
rodents shall be subjected to a full gross necropsy which includes 
examination of the external surface of the body, all orifices and the 
cranial, thoracic, and abdominal cavities and their contents. Gross 
pathology shall be performed on the following organs and tissues:
    (i) The liver, kidneys, lungs, adrenals, brain, and gonads, 
including uterus, ovaries, testes, epididymides, seminal vesicles (with 
coagulating glands), and prostate, constitute the group of target organs 
for histology and shall be weighed as soon as possible after dissection 
to avoid drying. In addition, for other than rodent test species, the 
thyroid with parathyroids, when present, shall also be weighed as soon 
as possible after dissection to avoid drying.
    (ii) The following organs and tissues, or representative samples 
thereof, shall be preserved in a suitable medium for possible future 
histopathological examination: All gross lesions; lungs--which shall be 
removed intact, weighed, and treated with a suitable fixative to ensure 
that lung structure is maintained (perfusion with the fixative is 
considered to be an effective procedure); nasopharyngeal tissues; 
brain--including sections of medulla/pons, cerebellar cortex, and 
cerebral cortex; pituitary; thyroid/parathyroid; thymus; trachea; heart; 
sternum with bone marrow; salivary glands; liver; spleen; kidneys; 
adrenals; pancreas; reproductive organs: uterus; cervix; ovaries; 
vagina; testes; epididymides; prostate; and, if present, seminal 
vesicles; aorta; (skin); gall bladder (if present); esophagus; stomach; 
duodenum; jejunum; ileum; cecum; colon; rectum; urinary bladder; 
representative lymph node; (mammary gland); (thigh musculature); 
peripheral nerve/tissue; (eyes); (femur--including articular surface); 
(spinal cord at three levels--cervical, midthoracic, and lumbar); and 
(zymbal and exorbital lachrymal glands).
    (7) Histopathology. Histopathology shall be performed on the 
following organs and tissues from all rodents:
    (i) All gross lesions.
    (ii) Respiratory tract and other organs and tissues, listed in 
paragraph (d)(6)(ii) of this section (except organs/tissues in 
parentheses), of all animals in the control and high dose groups.
    (iii) The tissues mentioned in parentheses, listed in paragraph 
(d)(6)(ii) of this section, if indicated by signs of toxicity or target 
organ involvement.
    (iv) Lungs of animals in the low and intermediate dose groups shall 
also be subjected to histopathological examination, primarily for 
evidence of infection since this provides a convenient assessment of the 
state of health of the animals.
    (v) Lungs and trachea of the whole-body perfusion-fixed test animals 
cited in paragraph (d)(1)(ii)(A) of this section are examined for 
inhaled particle distribution.
    (e) Interpretation of results. All observed results, quantitative 
and incidental, shall be evaluated by an appropriate statistical method. 
The specific methods, including consideration of statistical power, 
shall be selected during the design of the study.
    (f) Test report. In addition to the reporting requirements as 
specified under Secs. 79.60 and 79.61(e), the following individual 
animal data information shall be reported:
    (1) Date of death during the study or whether animals survived to 
termination.
    (2) Date of observation of each abnormal sign and its subsequent 
course.
    (3) Individual body weight data, and group average body weight data 
vs. time.
    (4) Feed consumption data, when collected.

[[Page 456]]

    (5) Hematological tests employed and all results.
    (6) Clinical biochemistry tests employed and all results.
    (7) Necropsy findings.
    (8) Type of stain/fixative and procedures used in preparing tissue 
samples.
    (9) Detailed description of all histopathological findings.
    (10) Statistical treatment of the study results, where appropriate.
    (g) References. For additional background information on this test 
guideline, the following references should be consulted.
    (1) 40 CFR 798.2450, Inhalation toxicity.
    (2) 40 CFR 798.2675, Oral Toxicity with Satellite Reproduction and 
Fertility Study.
    (3) General Statement of Work for the Conduct of Toxicity and 
Carcinogenicity Studies in Laboratory Animals (revised April, 1987/
modifications through January, 1990) appendix G, National Toxicology 
Program--U.S. Dept. of Health and Human Services (Public Health 
Service), P.O. Box 12233, Research Triangle Park, NC 27709.



Sec. 79.63  Fertility assessment/teratology.

    (a) Purpose. Fertility assessment/teratology is an in vivo study 
designed to provide information on potential health hazards to the fetus 
arising from the mother's repeated inhalation exposure to vehicle/engine 
emissions before and during her pregnancy. By including a mating of test 
animals, the study provides preliminary data on the effects of repeated 
vehicle/engine emissions exposure on gonadal function, conception, and 
fertility. Since this is a one-generation test that ends with 
examination of full-term fetuses, but not of live pups, it is not 
capable of determining effects on reproductive development which would 
only be detected in viable offspring of treated parents.
    (b) Definitions. For the purposes of this section, the following 
definitions apply:
    Developmental toxicity means the ability of an agent to induce in 
utero death, structural or functional abnormalities, or growth 
retardation after contact with the pregnant animal.
    Estrous cycle means the periodic recurrence of the biological phases 
of the female reproductive system which prepare the animal for 
conception and the development of offspring. The phases of the estrous 
cycle for a particular animal can be characterized by the general 
condition of the cells present in the vagina and the presence or absence 
of various cell types.
    Vaginal cytology evaluation means the use of wet vaginal cell smears 
to determine the phase of a test animal's estrous cycle and the 
potential for adverse exposure effects on the regularity of the animal's 
cycle. In the rat, common cell types found in the smears correlate well 
with the various stages of the estrous cycle and to changes occurring in 
the reproductive tract.
    (c) Principle of the test method. (1) For a two week period before 
exposures start, daily vaginal cell smears are examined from a surplus 
of female test animals to identify and cull those females which are 
acyclic. After culling, testers shall randomly assign at each exposure 
concentration (including unexposed) a minimum of twenty-five females for 
breeding and fifteen non-bred females for later histologic evaluation. 
Test animals shall be exposed by inhalation to graduated concentrations 
of the test atmosphere for a minimum of six hours per day over the next 
13 weeks. Males and females in both test and control groups are mated 
after nine weeks of exposure. Exposures for pregnant females continue 
through gestation day 15, while exposures for males and all non- 
pregnant females shall continue for the full exposure period.
    (2) Beginning two weeks before the start of the mating period, daily 
vaginal smears resume for all to-be-bred females to characterize their 
estrous cycles. This will continue for four weeks or until a rat's 
pregnancy is confirmed, i.e., day 0, by the presence of sperm in the 
cell smear. On pregnancy day 20, shortly before the expected date of 
delivery, each pregnant female is sacrificed, her uterus removed, and 
the contents examined for embryonic or fetal deaths, and live fetuses. 
At the end of the exposure period, males and all non-pregnant females 
shall be

[[Page 457]]

weighed, and various organs and tissues, as appropriate, shall be 
removed and weighed, fixed with stain, and sectioned for viewing under a 
light microscope.
    (3) This assay may be done separately or in combination with the 
subchronic toxicity study, pursuant to the provisions in Sec. 79.62.
    (d) Limit test. If a test at one dose level of the highest 
concentration that can be achieved while maintaining a particle size 
distribution with a mass median aerodynamic diameter (MMAD) of 4 
micrometers (m) or less, using the procedures described in 
section 79.60 of this part produces no observable toxic effects and if 
toxicity would not be expected based upon data of structurally related 
compounds, then a full study using three dose levels might not be 
necessary. Expected human exposure though may indicate the need for a 
higher dose level.
    (e) Test procedures--(1) Animal selection--(i) Species and strain. 
The rat is the preferred species. Strains with low fecundity shall not 
be used and the candidate species shall be characterized for its 
sensitivity to developmental toxins. If another rodent species is used, 
the tester shall provide justification for its selection.
    (ii) Animals shall be a minimum of 10 weeks old at the start of the 
exposure period.
    (iii) Number and sex. Each test and control group shall have a 
minimum of 25 males and 40 females. In order to ensure that sufficient 
pups are produced to permit meaningful evaluation of the potential 
developmental toxicity of the test substance, twenty pregnant test 
animals are required for each exposure and control level.
    (2) Observation period. The observation period shall be 13 weeks, at 
a minimum.
    (3) Concentration levels and concentration selection. (i) To select 
the appropriate concentration levels, a pilot or trial study may be 
advisable. Since pregnant animals have an increased minute ventilation 
as compared to non-pregnant animals, it is recommended that the trial 
study be conducted in pregnant animals. Similarly, since presumably the 
minute ventilation will vary with progression of pregnancy, the animals 
should be exposed during the same period of gestation as in the main 
study. It is not always necessary, though, to carry out a trial study in 
pregnant animals. Comparisons between the results of a trial study in 
non-pregnant animals, and the main study in pregnant animals will 
demonstrate whether or not the test substance is more toxic in pregnant 
animals. In the trial study, the concentration producing embryonic or 
fetal lethalities or maternal toxicity should be determined.
    (ii) The highest concentration level shall induce some overt 
maternal toxicity such as reduced body weight or body weight gain, but 
not more than 10 percent maternal deaths.
    (iii) The lowest concentration level shall not produce any grossly 
observable evidence of either maternal or developmental toxicity.
    (4) Inhalation exposure. (i) All data developed within this study 
shall be in accordance with good laboratory practice provisions under 
Sec. 79.60.
    (ii) The general conduct of this study shall be in accordance with 
the vehicle emissions inhalation exposure guideline in Sec. 79.61.
    (f) Test performance--(1) Study conduct. Directions specific to this 
study are:
    (i) The duration of exposure shall be at least six hours daily, 
allowing appropriate additional time for chamber equilibrium.
    (ii) Where an exposure chamber is used, its design shall minimize 
crowding of the test animals. This is best accomplished by individual 
caging.
    (iii) Pregnant animals shall not be subjected to beyond the minimum 
amount of stress. Since whole-body exposure appears to be the least 
stressful mode of exposure, it is the preferred method. In general 
oronasal or head-only exposure, which is sometimes used to avoid 
concurrent exposure by the dermal or oral routes, is not recommended 
because of the associated stress accompanying the restraining of the 
animals. However, there may be specific instances where it may be more 
appropriate than whole-body exposure. The tester shall provide 
justification/reasoning for its selection.

[[Page 458]]

    (iv) Measurements shall be made at least every other day of food 
consumption for all animals in the study. Males and females shall be 
weighed on the first day of exposure and 2-3 times per week thereafter, 
except for pregnant dams.
    (v) The test animal housing, mating, and exposure chambers shall be 
operated on a twenty-four hour lighting schedule, with twelve hours of 
light and twelve hours of darkness. Test animal exposure shall only 
occur during the light portion of the cycle.
    (vi) Signs of toxicity shall be recorded as they are observed 
including the time of onset, degree, and duration.
    (vii) Females showing signs of abortion or premature delivery shall 
be sacrificed and subjected to a thorough macroscopic examination.
    (viii) Animals that die or are euthanized because of morbidity will 
be necropsied promptly.
    (2) Vaginal cytology. (i) For a two week period before the mating 
period starts, each female in the to-be-bred population shall undergo a 
daily saline vaginal lavage. Two wet cell smears from this lavage shall 
be examined daily for each subject to determine a baseline pattern of 
estrus. Testers shall avoid excessive handling and roughness in 
obtaining the vaginal cell samples, as this may induce a condition of 
pseudo-pregnancy in the test animals.
    (ii) This will continue for four weeks or until day 0 of a rat's 
pregnancy is confirmed by the presence of sperm in the cell smear.
    (3) Mating and fertility assessment. (i) Beginning nine weeks after 
the start of exposure, each exposed and control group female (exclusive 
of the histology group females) shall be paired during non-exposure 
hours with a male from the same exposure concentration group. Matings 
shall continue for a period of two weeks, or until all mated females are 
determined to be pregnant. Mating pairs shall be clearly identified.
    (ii) Each morning, including weekends, cages shall be examined for 
the presence of a sperm plug. When found, this shall mark gestation day 
0 and pregnancy shall be confirmed by the presence of sperm in the day's 
wet vaginal cell smears.
    (iii) Two weeks after mating is begun, or as females are determined 
to be pregnant, bred animals are returned to pre-mating housing. Daily 
exposures continues through gestation day 15 for all pregnant females or 
through the balance of the exposure period for non-pregnant females and 
all males.
    (iv) Those pairs which fail to mate shall be evaluated in the course 
of the study to determine the cause of the apparent infertility. This 
may involve such procedures as additional opportunities to mate with a 
proven fertile partner, histological examination of the reproductive 
organs, and, in males, examination of the spermatogenic cycles. The 
stage of estrus for each non-pregnant female in the breeding group will 
be determined at the end of the exposure period.
    (4) All animals in the histology group shall be subject to 
histopathologic examination at the end of the study's exposure period.
    (g) Treatment of results. (1) All observed results, quantitative and 
incidental, shall be evaluated by an appropriate statistical method. The 
specific methods, including consideration of statistical power, shall be 
selected during the design of the study.
    (2) Data and reporting. In addition to the reporting requirements 
specified under Secs. 79.60 and 79.61, the final test report must 
include the following information:
    (i) Gross necropsy. (A) All animals shall be subjected to a full 
necropsy which includes examination of the external surface of the body, 
all orifices, and the cranial, thoracic, and abdominal cavities and 
their contents. Special attention shall be directed to the organs of the 
reproductive system.
    (B) The liver, kidneys, adrenals, pituitary, uterus, vagina, 
ovaries, testes, epididymides and seminal vesicles (with coagulating 
glands), and prostate shall be weighed wet, as soon as possible after 
dissection, to avoid drying.
    (i) At the time of sacrifice on gestation day 20 or at death during 
the study, each dam shall be examined macroscopically for any structural 
abnormalities or pathological changes which may have influenced the 
pregnancy.

[[Page 459]]

    (ii) The contents of the uterus shall be examined for embryonic or 
fetal deaths and the number of viable fetuses. Gravid uterine weights 
need not be obtained from dead animals where decomposition has occurred. 
The degree of resorption shall be described in order to help estimate 
the relative time of death.
    (iii) The number of corpora lutea shall be determined in each 
pregnant dam.
    (iv) Each fetus shall be weighed, all weights recorded, and mean 
fetal weights determined.
    (v) Each fetus shall be examined externally and the sex determined.
    (vi) One-half of the rat fetuses in each litter shall be examined 
for skeletal anomalies, and the remaining half shall be examined for 
soft tissue anomalies, using appropriate methods.
    (ii) Histopathology. (A) Histopathology on vagina, uterus, ovaries, 
testes, epididymides, seminal vesicles, and prostate as appropriate for 
all males and histology group females in the control and high 
concentration groups and for all animals that died or were euthanized 
during the study. If abnormalities or equivocal results are seen in any 
of these organs/tissues, the same organ/tissue from test animals in 
lower concentration groups shall be examined.

    Note: Testes, seminal vesicles, epididymides, and ovaries, at a 
minimum, shall be examined in perfusion-fixed (pressure or gravity 
method) test subjects, when available.

    (B) All gross lesions in all study animals shall be examined.
    (C) As noted under mating procedures, reproductive organs of animals 
suspected of infertility shall be subject to microscopic examination.
    (D) The following organs and tissues, or representative samples 
thereof, shall be preserved in a suitable medium for future 
histopathological examination: all gross lesions; vagina; uterus; 
ovaries; testes; epididymides; seminal vesicles; prostate; liver; and 
kidneys/adrenals.
    (3) Evaluation of results. (i) The findings of a developmental 
toxicity study shall be evaluated in terms of the observed effects and 
the exposure levels producing effects. It is necessary to consider the 
historical developmental toxicity data on the species/strain tested.
    (ii) There are several criteria for determining a positive result 
for reproductive/teratologic effects; a statistically significant dose-
related decrease in the weight of the testes for treated subjects over 
control subjects, a decrease in neonatal viability, a significant change 
in the presence of soft tissue or skeletal abnormalities, or an 
increased rate of embryonic or fetal resorption or death. Other 
criteria, e.g., lengthening of the estrous cycle or the time spent in 
any one stage of estrus, changes in the proportion of viable male vs 
female fetuses or offspring, the number and type of cells in vaginal 
smears, or pathologic changes found during gross or microscopic 
examination of male or female reproductive organs may be based upon 
detection of a reproducible and statistically significant positive 
response for that evaluation parameter. A positive result indicates 
that, under the test conditions, the test substance does induce 
reproductive organ or fetal toxicity in the test species.
    (iii) A test substance which does not produce either a statistically 
significant dose-related change in the reproductive organs or cycle or a 
statistically significant and reproducible positive response at any one 
of the test points may not induce reproductive organ toxicity in this 
test species, but further investigation , e.g., to establish absorption 
and bioavailability of the test substance, should be considered.
    (h) Test report. In addition to the reporting requirements as 
specified under 40 CFR 79.60 and the vehicle emissions inhalation 
toxicity guideline as published in 40 CFR 79.61, the following specific 
information shall be reported:
    (1) Individual animal data. (i) Time of death during the study or 
whether animals survived to termination.
    (ii) Date of onset and duration of each abnormal sign and its 
subsequent course.
    (iii) Feed and body weight data.
    (iv) Necropsy findings.
    (v) Male test subjects.
    (A) Testicle weight, and body weight: testicle weight ratio.

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    (B) Detailed description of all histopathological findings, 
especially for the testes and the epididymides.
    (vi) Female test subjects.
    (A) Uterine weight data.
    (B) Beginning and ending collection dates for vaginal cell smears.
    (C) Estrous cycle length compared within and between groups 
including mean cycle length for groups.
    (D) Percentage of time spent in each stage of cycle.
    (E) Stage of estrus at time of mating/sacrifice and proportion of 
females in estrus between concentration groups.
    (F) Detailed description of all histopathological findings, 
especially for uterine/ovary samples.
    (vii) Pregnancy and litter data. Toxic response data by exposure 
level, including but not limited to, indices of fertility and time-to-
mating, including the number of days until mating and the number of full 
or partial estrous cycles until mating.
    (A) Number of pregnant animals,
    (B) Number and percentage of live fetuses, resorptions.
    (viii) Fetal data. (A) Numbers of each sex.
    (B) Number of fetuses with any soft tissue or skeletal 
abnormalities.
    (2) Type of stain/fixative and procedures used in preparing tissue 
samples.
    (3) Statistical treatment of the study results.
    (i) References. For additional background information on this test 
guideline, the following references should be consulted.

    (1) 40 CFR 798.2675, Oral Toxicity with Satellite Reproduction and 
Fertility Study.
    (2) 40 CFR 798.4350, Inhalation Developmental Toxicity Study.
    (3) Chapin, R.E. and J.J. Heindel (1993) Methods in Toxicology, Vol. 
3, Parts A and B: Reproductive Toxicology, Academic Press, Orlando, FL.
    (4) Gray, L.E., et al. (1989) ``A Dose-Response Analysis of 
Methoxychlor-Induced Alterations of Reproductive Development and 
Function in the Rat'' Fund. App. Tox. 12, 92-108.
    (5) Leblond, C.P. and Y. Clermont (1952) ``Definition of the Stages 
of the Cycle of the Seminiferous Epithelium of the Rat.'' Ann. N. Y. 
Acad. Sci. 55:548-73.
    (6) Morrissey, R.E., et al. (1988) ``Evaluation of Rodent Sperm, 
Vaginal Cytology, and Reproductive Organ Weight Data from National 
Toxicology Program 13-week Studies.'' Fundam. Appl. Toxicol. 11:343-358.
    (7) Russell, L.D., Ettlin, R.A., Sinhattikim, A.P., and Clegg, E.D 
(1990) Histological and Histopathological Evaluation of the Testes, 
Cache River Press, Clearwater, FL.



Sec. 79.64   In vivo micronucleus assay.

    (a) Purpose. The micronucleus assay is an in vivo cytogenetic test 
which uses erythrocytes in the bone marrow of rodents to detect chemical 
damage to the chromosomes or mitotic apparatus of mammalian cells. As 
the erythroblast develops into an erythrocyte (red blood cell), its main 
nucleus is extruded and may leave a micronucleus in the cell body; a few 
micronuclei form under normal conditions in blood elements. This assay 
is based on an increase in the frequency of micronucleated erythrocytes 
found in bone marrow from treated animals compared to that of control 
animals. The visualization of micronuclei is facilitated in these cells 
because they lack a main nucleus.
    (b) Definitions. For the purposes of this section the following 
definitions apply:
    Micronuclei mean small particles consisting of acentric fragments of 
chromosomes or entire chromosomes, which lag behind at anaphase of cell 
division. After telophase, these fragments may not be included in the 
nuclei of daughter cells and form single or multiple micronuclei in the 
cytoplasm.
    Polychromatic erythrocyte (PCE) means an immature red blood cell 
that, because it contains RNA, can be differentiated by appropriate 
staining techniques from a normochromatic erythrocyte (NCE), which lacks 
RNA. In one to two days, a PCE matures into a NCE.
    (c) Test method--(1) Principle of the test method. (i) Groups of 
rodents are exposed by the inhalation route for a minimum of 6 hours/day 
over a period of not less than 28 days to three or more concentrations 
of a test substance in air. Groups of animals are sacrificed at the end 
of the exposure period and femoral bone marrow is extracted. The bone 
marrow is then smeared onto glass slides, stained, and PCEs are scored 
for micronuclei. Researchers may need to run a trial at

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the highest tolerated concentration of the test atmosphere to optimize 
the sample collection time for micronucleated cells.
    (ii) This assay may be done separately or in combination with the 
subchronic toxicity study, pursuant to the provisions in Sec. 79.62.
    (2) Species and strain. (i) The rat is the recommended test animal. 
Other rodent species may be used in this assay, but use of that species 
will be justified by the tester.
    (ii) If a strain of mouse is used in this assay, the tester shall 
sample peripheral blood from an appropriate site on the test animal, 
e.g., the tail vein, as a source of normochromatic erythrocytes. Results 
shall be reported as outlined later in this guideline with 
``normochromatic'' interchanged for ``polychromatic'', where specified.
    (3) Animal number and sex. At least five female and five male 
animals per experimental/sample and control group shall be used. The use 
of a single sex or a smaller number of animals shall be justified.
    (4) Positive control group. A single concentration of a compound 
known to produce micronuclei in vivo is adequate as a positive control 
if it shows a significant response at any one time point; additional 
concentration levels may be used. To select an appropriate concentration 
level, a pilot or trial study may be advisable. Initially, one 
concentration of the test substance may be used, the maximum tolerated 
dose or that producing some indication of toxicity, e.g., a drop in the 
ratio of polychromatic to normochromatic erythrocytes. Intraperitoneal 
injection of 1,2-dimethyl-benz-anthracene or benzene are examples of 
positive control exposures. A concentration of 50-80 percent of an LD50 
may be a suitable guide.
    (d) Test performance--(1) Inhalation exposure. (i) All data 
developed within this study shall be in accordance with good laboratory 
practice provisions under Sec. 79.60.
    (ii) The general conduct of this study shall be in accordance with 
the vehicle emissions inhalation exposure guideline in Sec. 79.61.
    (2) Preparation of slides and sampling times. Within twenty-four 
hours of the last exposure, test animals will be sacrificed. One femur 
from each test animal will be removed and placed in fetal bovine serum. 
The bone marrow is removed, cells processed, and two bone marrow smears 
are made for each animal on glass microscope slides. The slides are 
stained with acridine- orange (AO) or another appropriate stain (Giemsa 
+ Wright's, etc.) and examined under a microscope.
    (3) Analysis. Slides shall be coded for study before microscopic 
analysis. At least 1,000 first-division erythrocytes per animal shall be 
scored for the incidence of micronuclei. Sexes will be analyzed 
separately.
    (e) Data and report--(1) Treatment of results. In addition to the 
reporting requirements specified under Secs. 79.60 and 79.61, the final 
test report must include the criteria for scoring micronuclei. 
Individual data shall be presented in a tabular form including both 
positive and negative controls and experimental groups. The number of 
polychromatic erythrocytes scored, the number of micronucleated 
erythrocytes, the percentage of micronucleated cells, and, where 
applicable, the percentage of micronucleated erythrocytes shall be 
listed separately for each experimental and control animal. Absolute 
numbers shall be included if percentages are reported.
    (2) Interpretation of data. (i) There are several criteria for 
determining a positive response, one of which is a statistically 
significant dose-related increase in the number of micronucleated 
polychromatic erythrocytes. Another criterion may be based upon 
detection of a reproducible and statistically significant positive 
response for at least one of the test substance concentrations.
    (ii) A test substance which does not produce either a statistically 
significant dose-related increase in the number of micronucleated 
polychromatic erythrocytes or a statistically significant and 
reproducible positive response at any one of the test points is 
considered nonmutagenic in this system.
    (3) Test evaluation. (i) Positive results in the micronucleus test 
provide information on the ability of a chemical to induce micronuclei 
in erythrocytes of the test species under the conditions of

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the test. This damage may have been the result of chromosomal damage or 
damage to the mitotic apparatus.
    (ii) Negative results indicate that under the test conditions the 
test substance does not produce micronuclei in the bone marrow of the 
test species.
    (f) Test report. In addition to the reporting recommendations as 
specified under Sec. 79.60, the following specific information shall be 
reported:
    (1) Test atmosphere concentration(s) used and rationale for 
concentration selection.
    (2) Rationale for and description of treatment and sampling 
schedules, toxicity data, negative and positive controls.
    (3) Historical control data (negative and positive), if available.
    (4) Details of the protocol used for slide preparation.
    (5) Criteria for identifying micronucleated erythrocytes.
    (6) Micronucleus analysis by animal and by group for each 
concentration (sexes analyzed separately).
    (i) Ratio of polychromatic to normochromatic erythrocytes.
    (ii) Number of polychromatic erythrocytes with micronuclei.
    (iii) Number of polychromatic erythrocytes scored.
    (7) Statistical methodology chosen for test analysis.
    (g) References. For additional background information on this test 
guideline, the following references should be consulted.

    (1) 40 CFR 798.5395, In Vivo, Mammalian Bone Marrow Cytogenetics 
Tests: Micronucleus Assay.
    (2) Cihak, R. ``Evaluation of Benzidine by the Micronucleus Test.'' 
Mutation Research, 67: 383-384 (1979).
    (3) Evans, H.J. ``Cytological Methods for Detecting Chemical 
Mutagens.'' Chemical Mutagens: Principles and Methods for Their 
Detection, Vol. 4. Ed. A. Hollaender (New York and London: Plenum Press, 
1976) pp. 1-29.
    (4) Heddle, J.A., et al. ``The Induction of Micronuclei as a Measure 
of Genotoxicity. A Report of the U.S. Environmental Protection Agency 
Gene-Tox Program.'' Mutation Research, 123:61-118 (1983).
    (5) Preston, J.R. et al. ``Mammalian In Vivo and In Vitro 
Cytogenetics Assays: Report of the Gene-Tox Program.'' Mutation 
Research, 87:143-188 (1981).
    (6) Schmid, W. ``The micronucleus test for cytogenetic analysis'', 
Chemical Mutagens, Principles and Methods for their Detection. Vol. 4 
Hollaender A, (Ed. A ed. (New York and London: Plenum Press, (1976) pp. 
31-53.
    (7) Tice, R.E., and Al Pellom ``User's guide: Micronucleus assay 
data management and analysis system'', NTIS Order no. PB-90-212-598AS.



Sec. 79.65  In vivo sister chromatid exchange assay.

    (a) Purpose. The in vivo sister chromatid exchange (SCE) assay 
detects the ability of a chemical to enhance the exchange of DNA between 
two sister chromatids of a duplicating chromosome. The most commonly 
used assays employ mammalian bone marrow cells or peripheral blood 
lymphocytes, often from rodent species.
    (b) Definitions. For the purposes of this section, the following 
definitions apply:
    C-metaphase means a state of arrested cell growth typically seen 
after treatment with a spindle inhibitor, i.e., colchicine.
    Sister chromatid exchange means a reciprocal interchange of the two 
chromatid arms within a single chromosome. This exchange is visualized 
during the metaphase portion of the cell cycle and presumably requires 
the enzymatic incision, translocation and ligation of at least two DNA 
helices.
    (c) Test method--(1) Principle of the test method. (i) Groups of 
rodents are exposed by the inhalation route for a minimum of 6 hours/day 
over a period of not less than 28 days to three or more concentrations 
of a test substance in air. Groups of animals are sacrificed at the end 
of the exposure period and blood lymphocyte cell cultures are prepared 
from study animals. Cell growth is suspended after a time and cells are 
harvested, fixed and stained before scoring for SCEs. Researchers may 
need to run a trial at the highest tolerated concentration of the test 
atmosphere to optimize the sample collection time for second division 
metaphase cells.
    (ii) This assay may be done separately or in combination with the 
subchronic toxicity study, pursuant to the provisions in Sec. 79.62.
    (2) Description. (i) The method described here employs peripheral 
blood

[[Page 463]]

lymphocytes (PBL) of laboratory rodents exposed to the test atmosphere.
    (ii) Within twenty-four hours of the last exposure, test animal 
lymphocytes are obtained by heart puncture and duplicate cell cultures 
are started for each animal. Cultures are grown in bromo-deoxyuridine 
(BrdU), and then a spindle inhibitor (e.g., colchicine) is added to 
arrest cell growth. Cells are harvested, fixed, and stained and their 
chromosomes are scored for SCEs.
    (3) Species and strain. The rat is the recommended test animal. 
Other rodent species may be used in this assay, but use of that species 
will be justified by the tester.
    (4) Animal number and sex. At least five female and five male 
animals per experimental and control group shall be used. The use of a 
single sex or different number of animals shall be justified.
    (5) Positive control group. A single concentration of a compound 
known to produce SCEs in vivo is adequate as a positive control if it 
shows a significant response at any one time point; additional 
concentration levels may be used. To select an appropriate concentration 
level, a pilot or trial study may be advisable. Initially, one 
concentration of the test substance may be used, the maximum tolerated 
dose or that producing some indication of toxicity as evidenced by 
animal morbidity (including death) or target cell toxicity. 
Intraperitoneal injection of 1,2-dimethyl-benz-anthracene or benzene are 
examples of positive control exposures. A concentration of 50-80 percent 
of an LD50 would also be a suitable guide.
    (6) Inhalation exposure. (i) All data developed within this study 
shall be in accordance with good laboratory practice provisions under 
Sec. 79.60.
    (ii) The general conduct of this study shall be in accordance with 
the vehicle emissions inhalation exposure guideline in Sec. 79.61.
    (d) Test performance--(1) Treatment. At the conclusion of the 
exposure period, all test animals are anaesthetized and heart punctures 
are performed. Lymphocytes are isolated over a Ficoll gradient and 
replicate cell cultures are started for each animal. After some 21 
hours, the cells are treated with BrdU and returned to incubation. The 
following day, a spindle inhibitor (e.g., colchicine) is added to arrest 
cell growth in c-metaphase. Cells are harvested 4 hours later and 
second-division metaphase cells are washed and fixed in methanol:acetic 
acid, stained, and chromosome preparations are scored for SCEs.
    (2) Staining method. Staining of slides to reveal SCEs can be 
performed according to any of several protocols. However, the 
fluorescence plus Giemsa method is recommended.
    (3) Number of cells scored. (i) A minimum of 25 well-stained, 
second-division metaphase cells shall be scored for each animal for each 
cell type.
    (ii) At least 100 consecutive metaphase cells shall be scored for 
the number of first, second, and third division metaphases for each 
animal for each cell type.
    (iii) At least 1000 consecutive PBL's shall be scored for the number 
of metaphase cells present.
    (iv) The number of cells to be analyzed per animal shall be based 
upon the number of animals used, the negative control frequency, the 
pre-determined sensitivity and the power chosen for the test. Slides 
shall be coded before microscopic analysis.
    (e) Data and report--(1) Treatment of results. In addition to the 
reporting requirements specified under Secs. 79.60 and 61, data shall be 
presented in tabular form, providing scores for both the number of SCE 
for each metaphase. Differences among animals within each group shall be 
considered before making comparisons between treated and control groups.
    (2) Statistical evaluation. Data shall be evaluated by appropriate 
statistical methods.
    (3) Interpretation of results. (i) There are several criteria for 
determining a positive result, one of which is a statistically 
significant dose-related increase in the number of SCE. Another 
criterion may be based upon detection of a reproducible and 
statistically significant positive response for at least one of the test 
concentrations.
    (ii) A test substance which does not produce either a statistically 
significant dose-related increase in the number of SCE or a 
statistically significant

[[Page 464]]

and reproducible positive response at any one of the test concentrations 
is considered not to induce rearrangements of DNA segments in this 
system.
    (iii) Both biological and statistical significance shall be 
considered together in the evaluation.
    (4) Test evaluation. (i) A positive result in the in vivo SCE assay 
for either, or both, the lung or lymphocyte cultures indicates that 
under the test conditions the test substance induces reciprocal 
interchanges of DNA in duplicating chromosomes from lung or lymphocyte 
cells of the test species.
    (ii) Negative results indicate that under the test conditions the 
test substance does not induce reciprocal interchanges in lung or 
lymphocyte cells of the test species.
    (5) Test report. In addition to the reporting recommendations as 
specified under Secs. 79.60 and 79.61, the following specific 
information shall be reported:
    (i) Test concentrations used, rationale for concentration selection, 
negative and positive controls;
    (ii) Toxic response data by concentration;
    (iii) Schedule of administration of test atmosphere, BrdU, and 
spindle inhibitor;
    (iv) Time of harvest after administration of BrdU;
    (v) Identity of spindle inhibitor, its concentration and timing of 
treatment;
    (vi) Details of the protocol used for cell culture and slide 
preparation;
    (vii) Criteria for scoring SCE;
    (viii) Replicative index, i.e., [percent 1st division+(2 x percent 
2nd division) + (3 x percent 3rd division) metaphases]/100; and
    (ix) Mitotic activity, i.e., # of metaphases/1000 cells.
    (f) References. For additional background information on this test 
guideline, the following references should be consulted.

    (1) 40 CFR 798.5915, In vivo Sister Chromatid Exchange Assay.
    (2) Kato, H. ``Spontaneous Sister Chromatid Exchanges Detected by a 
BudR-Labeling Method.'' Nature, 251:70-72 (1974).
    (4) Kligerman, A. D., et al. ``Sister Chromatid Exchange Analysis in 
Lung and Peripheral Blood Lymphocytes of Mice Exposed to Methyl 
Isocyanate by Inhalation.'' Environmental Mutagenesis 9:29-36 (1987).
    (5) Kligerman, A.D., et al., ``Cytogenetic Studies of Rodents 
Exposed to Styrene by Inhalation'', IARC Monographs no. 127 ``Butadiene 
and Styrene: Assesment of Health Hazards'' (Sorsa, et al., eds), pp 217-
224, 1993.
    (6) Kligerman, A., et al., ``Cytogenetic Studies of Mice Exposed to 
Styrene by Inhalation.'', Mutation Research, 280:35-43, 1992.
    (7) Wolff, S., and P. Perry. ``Differential Giemsa Staining of 
Sister Chromatids and the Study of Sister Chromatid Exchanges Without 
Autoradiography.'' Chromosoma 48: 341-53 (1974).



Sec. 79.66  Neuropathology assessment.

    (a) Purpose. (1) The histopathological and biochemical techniques in 
this guideline are designed to develop data in animals on morphologic 
changes in the nervous system associated with repeated inhalation 
exposures to motor vehicle emissions. These tests are not intended to 
provide a detailed evaluation of neurotoxicity. Neuropathological 
evaluation should be complemented by other neurotoxicity studies, e.g. 
behavioral and neurophysiological studies and/or general toxicity 
testing, to more completely assess the neurotoxic potential of an 
exposure.
    (2) [Reserved]
    (b) Definition. Neurotoxicity (NTX) or a neurotoxic effect is an 
adverse change in the structure or function of the nervous system 
following exposure to a chemical substance.
    (c) Principle of the test method. (1) Laboratory rodents are exposed 
to one of several concentration levels of a test atmosphere for at least 
six hours daily over a period of 90 days. At the end of the exposure 
period, the animals are anaesthetized, perfused in situ with fixative, 
and tissues in the nervous system are examined grossly and prepared for 
microscopic examination. Starting with the highest dosage level, tissues 
are examined under the light microscope for morphologic changes, until a 
no-observed-adverse-effect level is determined. In cases where light 
microscopy has revealed neuropathology, the NOAEL may be confirmed by 
electron microscopy.
    (2) The tests described herein may be combined with any other 
toxicity study, as long as none of the requirements of either are 
violated by the combination. Specifically, this assay may be combined 
with a subchronic

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toxicity study, pursuant to provisions in Sec. 79.62.
    (d) Limit test. If a test at one dose level of the highest 
concentration that can be achieved while maintaining a particle size 
distribution with a mass median aerodynamic diameter (MMAD) of 4 
micrometers (m) or less, using the procedures described in 
paragraph (a) of this section, produces no observable toxic effects and 
if toxicity would not be expected based upon data of structurally 
related compounds, then a full study using three dose levels might not 
be necessary. Expected human exposure though may indicate the need for a 
higher dose level.
    (e) Test procedures--(1) Animal selection--(i) Species and strain. 
Testing shall be performed in the species being used in other NTX tests. 
A standard strain of laboratory rat is recommended. The choice of 
species shall take into consideration such factors as the comparative 
metabolism of the chemical and species sensitivity to the toxic effects 
of the test substance, as evidenced by the results of other studies, the 
potential for combined studies, and the availability of other toxicity 
data for the species.
    (ii) Age. Animals shall be at least ten weeks of age at the start of 
exposure.
    (iii) Sex. Both sexes shall be used unless it is demonstrated that 
one sex is refractory to the effects of exposure.
    (2) Number of Animals. A minimum of ten animals per group shall be 
used. The tissues from each animal shall be examined separately.
    (3) Control Groups. (i) A concurrent control group, exposed to 
clean, filtered air only, is required.
    (ii) The laboratory performing the testing shall provide positive 
control data, e.g., results from repeated acrylamide exposure, as 
evidence of the ability of their histology procedures to detect 
neurotoxic endpoints. Positive control data shall be collected at the 
time of the test study unless the laboratory can demonstrate the 
adequacy of historical data for the planned study.
    (iii) A satellite group of 10 female and 10 male test subjects shall 
be treated with the highest concentration level for the duration of the 
exposure and observed thereafter for reversibility, persistence, or 
delayed occurrence of toxic effects during a post-treatment period of 
not less than 28 days.
    (4) Inhalation exposure. (i) All data developed within this study 
shall be in accordance with good laboratory practice provisions under 
Sec. 79.60.
    (ii) The general conduct of this study shall be in accordance with 
the vehicle emissions inhalation exposure guideline in Sec. 79.61.
    (5) Study conduct--(i) Observation of animals. All toxicological 
(e.g., weight loss) and neurological signs (e.g., motor disturbance) 
shall be recorded frequently enough to observe any abnormality, and not 
less than weekly.
    (ii) The following is a minimal list of measures that shall be 
noted:
    (A) Body weight;
    (B) Subject's reactivity to general stimuli such as removal from the 
cage or handling;
    (C) Description, incidence, and severity of any convulsions, 
tremors, or abnormal motor movements in the home cage;
    (D) Descriptions and incidence of posture and gait abnormalities 
observed in the home cage; and
    (E) Description and incidence of any unusual or abnormal behaviors, 
excessive or repetitive actions (stereotypies), emaciation, dehydration, 
hypotonia or hypertonia, altered fur appearance, red or crusty deposits 
around the eyes, nose, or mouth, and any other observations that may 
facilitate interpretation of the data.
    (iii) Sacrifice of animals--(A) General. The goal of the techniques 
outlined for sacrifice of animals and preparation of tissues is 
preservation of tissue morphology to simulate the living state of the 
cell.
    (B) Perfusion technique. Animals shall be perfused in situ by a 
generally recognized technique. For fixation suitable for light or 
electronic microscopy, saline solution followed by buffered 2.5 percent 
glutaraldehyde or buffered 4.0 percent paraformaldehyde, is recommended. 
While some minor modifications or variations in procedures are used in 
different laboratories, a detailed and standard procedure for vascular 
perfusion may be found in the text by Zeman and Innes (1963), Hayat 
(1970), and Spencer and Schaumburg

[[Page 466]]

(1980) under paragraph (g) of this section. A more sophisticated 
technique is described by Palay and Chan-Palay (1974) under paragraph 
(g) of this section.
    (C) Removal of brain and cord. After perfusion, the bony structure 
(cranium and vertebral column) shall be exposed. Animals shall then be 
stored in fixative-filled bags at 4  deg.C for 8-12 hours. The cranium 
and vertebral column shall be removed carefully by trained technicians 
without physical damage of the brain and cord. Detailed dissection 
procedures may be found in the text by Palay and Chan-Palay (1974) under 
paragraph (g) of this section. After removal, simple measurement of the 
size (length and width) and weight of the whole brain (cerebrum, 
cerebellum, pons-medulla) shall be made. Any abnormal coloration or 
discoloration of the brain and cord shall also be noted and recorded.
    (D) Sampling. Cross-sections of the following areas shall be 
examined: The forebrain, the center of the cerebrum, the midbrain, the 
cerebellum, and the medulla oblongata; the spinal cord at the cervical 
swelling (C3-C6), and proximal sciatic nerve (mid-thigh and 
sciatic notch) or tibial nerve (at knee). Other sites and tissue 
elements (e.g., gastrocnemius muscle) shall be examined if deemed 
necessary. Any observable gross changes shall be recorded.
    (iv) Specimen storage. Tissue samples from both the central and 
peripheral nervous system shall be further immersion fixed and stored in 
appropriate fixative (e.g., 10 percent buffered formalin for light 
microscopy; 2.5 percent buffered gluteraldehyde or 4.0 percent buffered 
paraformaldehyde for electron microscopy) for future examination. The 
volume of fixative versus the volume of tissues in a specimen jar shall 
be no less than 25:1. All stored tissues shall be washed with buffer for 
at least 2 hours prior to further tissue processing.
    (v) Histopathology examination--(A) Fixation. Tissue specimens 
stored in 10 percent buffered formalin may be used for this purpose. All 
tissues must be immersion fixed in fixative for at least 48 hours prior 
to further tissue processing.
    (B) Dehydration. All tissue specimens shall be washed for at least 1 
hour with water or buffer, prior to dehydration. (A longer washing time 
is needed if the specimens have been stored in fixative for a prolonged 
period of time.) Dehydration can be performed with increasing 
concentration of graded ethanols up to absolute alcohol.
    (C) Clearing and embedding. After dehydration, tissue specimens 
shall be cleared with xylene and embedded in paraffin or paraplast. 
Multiple tissue specimens (e.g. brain, cord, ganglia) may be embedded 
together in one single block for sectioning. All tissue blocks shall be 
labelled showing at least the experiment number, animal number, and 
specimens embedded.
    (D) Sectioning. Tissue sections, 5 to 6 microns in thickness, shall 
be prepared from the tissue blocks and mounted on standard glass slides. 
It is recommended that several additional sections be made from each 
block at this time for possible future needs for special stainings. All 
tissue blocks and slides shall be filed and stored in properly labeled 
files or boxes.
    (E) Histopathological techniques. The following general testing 
sequence is proposed for gathering histopathological data:
    (1) General staining. A general staining procedure shall be 
performed on all tissue specimens in the highest treatment group. 
Hematoxylin and eosin (H&E) shall be used for this purpose. The staining 
shall be differentiated properly to achieve bluish nuclei with pinkish 
background.
    (2) Peripheral nerve teasing. Peripheral nerve fiber teasing shall 
be used. Detailed staining methodology is available in standard 
histotechnological manuals such as AFIP (1968), Ralis et al. (1973), and 
Chang (1979) under paragraph (g) of this section. The nerve fiber 
teasing technique is discussed in Spencer and Schaumberg (1980) under 
paragraph (g) of this section. A section of normal tissue shall be 
included in each staining to assure that adequate staining has occurred. 
Any changes shall be noted and representative photographs shall be 
taken. If a lesion(s) is observed, the special techniques shall

[[Page 467]]

be repeated in the next lower treatment group until no further lesion is 
detectable.
    (F) Examination. All stained microscopic slides shall be examined 
with a standard research microscope. Examples of cellular alterations 
(e.g., neuronal vacuolation, degeneration, and necrosis) and tissue 
changes (e.g., gliosis, leukocytic infiltration, and cystic formation) 
shall be recorded and photographed.
    (f) Data collection, reporting, and evaluation. In addition to 
information meeting the requirements stated under 40 CFR 79.60 and 
79.61, the following specific information shall be reported:
    (1) Description of test system and test methods. (i) A description 
of the general design of the experiment shall be provided. This shall 
include a short justification explaining any decisions where 
professional judgment is involved such as fixation technique and choice 
of stains; and
    (ii) Positive control data from the laboratory performing the test 
that demonstrate the sensitivity of the procedures being used. 
Historical data may be used if all essential aspects of the experimental 
protocol are the same.
    (2) Results. All observations shall be recorded and arranged by test 
groups. This data may be presented in the following recommended format:
    (i) Description of signs and lesions for each animal. For each 
animal, data must be submitted showing its identification (animal 
number, treatment, dose, duration), neurologic signs, location(s) nature 
of, frequency, and severity of lesion(s). A commonly-used scale such as 
1+, 2+, 3+, and 4+ for degree of severity ranging from very slight to 
extensive may be used. Any diagnoses derived from neurologic signs and 
lesions including naturally occurring diseases or conditions, shall also 
be recorded;
    (ii) Counts and incidence of lesions, by test group. Data shall be 
tabulated to show:
    (A) The number of animals used in each group, the number of animals 
displaying specific neurologic signs, and the number of animals in which 
any lesion was found; and
    (B) The number of animals affected by each different type of lesion, 
the average grade of each type of lesion, and the frequency of each 
different type and/or location of lesion.
    (iii) Evaluation of data. (A) An evaluation of the data based on 
gross necropsy findings and microscopic pathology observations shall be 
made and supplied. The evaluation shall include the relationship, if 
any, between the animal's exposure to the test atmosphere and the 
frequency and severity of any lesions observed; and
    (B) The evaluation of dose-response, if existent, for various groups 
shall be given, and a description of statistical method must be 
presented. The evaluation of neuropathology data shall include, where 
applicable, an assessment in conjunction with any other neurotoxicity 
studies, electrophysiological, behavioral, or neurochemical, which may 
be relevant to this study.
    (g) References. For additional background information on this test 
guideline, the following references should be consulted.

(1) 40 CFR 798.6400, Neuropathology.
(2) AFIP Manual of Histologic Staining Methods. (New York: McGraw-Hill 
          (1968).
(3) Chang, L.W. A Color Atlas and Manual for Applied Histochemistry. 
          (Springfield, IL: Charles C. Thomas, 1979).
(4) Dunnick, J.K., et.al. Thirteen-week Toxicity Study of N-Hexane in 
          B6C3F1 Mice After Inhalation Exposure (1989) Toxicology, 57, 
          163-172.
(5) Hayat, M.A. ``Vol. 1. Biological applications,'' Principles and 
          techniques of electron microscopy. (New York: Van Nostrand 
          Reinhold, 1970).
(6) Palay S.L., Chan-Palay, V. Cerebellar Cortex: Cytology and 
          Organization. (New York: Springer-Verlag, 1974).
(7) Ralis, H.M., Beesley, R.A., Ralis, Z.A. Techniques in 
          Neurohistology. (London: Butterworths, 1973).
(8) Sette, W. ``Pesticide Assessment Guidelines, Subdivision F, 
          Neurotoxicity Test Guidelines.'' Report No. 540/09-91-123 U.S. 
          Environmental Protection Agency 1991 (NTIS #PB91-154617).
(9) Spencer, P.S., Schaumburg, H.H. (eds). Experimental and Clinical 
          Neurotoxicology. (Baltimore: Williams and Wilkins, 1980).
(10) Zeman, W., Innes, J.R.M. Craigie's Neuroanatomy of the Rat. (New 
          York: Academic, 1963).

[[Page 468]]



Sec. 79.67  Glial fibrillary acidic protein assay.

    (a) Purpose. Chemical-induced injury of the nervous system, i.e., 
the brain, is associated with astrocytic hypertrophy at the site of 
damage (see O'Callaghan, 1988 in paragraph (e)(3) in this section). 
Assays of glial fibrillary acidic protein (GFAP), the major intermediate 
filament protein of astrocytes, can be used to document this response. 
To date, a diverse variety of chemical insults known to be injurious to 
the central nervous system have been shown to increase GFAP. Moreover, 
increases in GFAP can be seen at concentrations below those necessary to 
produce cytopathology as determined by routine Nissl stains (standard 
neuropathology). Thus it appears that assays of GFAP represent a 
sensitive approach for documenting the existence and location of 
chemical-induced injury of the central nervous system. Additional 
functional, histopathological, and biochemical tests are necessary to 
assess completely the neurotoxic potential of any chemical. This 
biochemical test is intended to be used in conjunction with 
neurohistopathological studies.
    (b) Principle of the test method. (1) This guideline describes the 
conduct of a radioimmunoassay for measurement of the amount of GFAP in 
the brain of vehicle emission-exposed and unexposed control animals. It 
is based on modifications (O'Callaghan & Miller 1985 in paragraph 
(e)(5), O'Callaghan 1987 in paragraph (e)(1) of this section) of the 
dot-immunobinding procedure described by Jahn et al. (1984) in paragraph 
(e)(2) of this section. Briefly, brain tissue samples from study animals 
are assayed for total protein, diluted in dot-immunobinding buffer, and 
applied to nitrocellulose sheets. The spotted sheets are then fixed, 
blocked, washed and incubated in anti-GFAP antibody and [I125] 
Protein A. Bound protein A is then quantified by gamma spectrometry. In 
lieu of purified protein standards, standard curves are constructed from 
dilution of a single control sample. By comparing the immunoreactivity 
of individual samples (both control and exposed groups) with that of the 
sample used to generate the standard curve, the relative 
immunoreactivity of each sample is obtained. The immunoreactivity of the 
control groups is normalized to 100 percent and all data are expressed 
as a percentage of control. A variation on this radioimmunoassay 
procedure has been proposed (O'Callaghan 1991 in paragraph (e)(4) of 
this section) which uses a ``sandwich'' of GFAP, anti-GFAP, and a 
chromophore in a microtiter plate format enzyme-link immunosorbent assay 
(ELISA). The use of this variation shall be justified.
    (2) This assay may be done separately or in combination with the 
subchronic toxicity study, pursuant to the provisions of Sec. 79.62.
    (c) Test procedure--(1) Animal selection--(i) Species and strain. 
Test shall be performed on the species being used in concurrent testing 
for neurotoxic or other health effect endpoints. This will generally be 
a species of laboratory rat. The use of other rodent or non-rodent 
species shall be justified.
    (ii) Age. Based on other concurrent testing, young adult rats shall 
be used. Study rodents shall not be older than ten weeks at the start of 
exposures.
    (iii) Number of animals. A minimum of ten animals per group shall be 
used. The tissues from each animal shall be examined separately.
    (iv) Sex. Both sexes shall be used unless it is demonstrated that 
one sex is refractory to the effects.
    (2) Materials. The materials necessary to perform this study are 
[I125] Protein A (2-10 Ci/g), Anti-sera to GFAP, 
nitrocellulose paper (0.1 or 0.2 m pore size), sample 
application template (optional; e.g., ``Minifold II'', Schleicher & 
Schuell, Keene, NH), plastic sheet incubation trays.
    (3) Study conduct. (i) All data developed within this study shall be 
in accordance with good laboratory practice provisions under Sec. 79.60.
    (ii) Tissue Preparation. Animals are euthanized 24 hours after the 
last exposure and the brain is excised from the skull. On a cold 
dissecting platform, the following six regions are dissected freehand: 
cerebellum; cerebral cortex; hippocampus; striatum; thalamus/
hypothalamus; and the rest of the brain. Each region is then weighed and 
homogenized in 10 volumes of hot (70-90

[[Page 469]]

 deg.C) 1 percent (w/v) sodium dodecyl sulfate (SDS). Homogenization is 
best achieved through sonic disruption. A motor driven pestle inserted 
into a tissue grinding vessel is a suitable alternative. The homogenized 
samples can then be stored frozen at -70  deg.C for at least 4 years 
without loss of GFAP content.
    (iii) Total Protein Assay. Aliquots of the tissue samples are 
assayed for total protein using the method of Smith et al. (1985) in 
paragraph (e)(7) of this section. This assay may be purchased in kit 
form (e.g., Pierce Chemical Company, Rockford, IL).
    (iv) Sample Preparation. Dilute tissue samples in sample buffer (120 
mM KCl, 20 mM NaCl, 2 mM MgCl2), 5 mM Hepes, pH 7.4, 0.7 percent 
Triton X-100) to a final concentration of 0.25 mg total protein per ml 
(5 g/20 l).
    (v) Preparation of Standard Curve. Dilute a single control sample in 
sample buffer to give at least five standards, between 1 and 10 
g total protein per 20 l. The suggested values of 
total protein per 20 l sample buffer are 1.25, 2.50, 3.25, 5.0, 
6.25, 7.5, 8.75, and 10.0 g.
    (vi) Preparation of Nitrocellulose Sheets. Nitrocellulose sheets of 
0.1 or 0.2 micron pore size are rinsed by immersion in distilled water 
for 5 minutes and then air dried.
    (vii) Sample Application. Samples can be spotted onto the 
nitrocellulose sheets free-hand or with the aid of a template. For free-
hand application, draw a grid of squares approximately 2 centimeters by 
2 centimeters (cm) on the nitrocellulose sheets using a soft pencil. 
Spot 5-10 l portions to the center of each square for a total 
sample volume of 20 l. For template aided sample application a 
washerless microliter capacity sample application manifold is used. 
Position the nitrocellulose sheet in the sample application device as 
recommended by the manufacturer and spot a 20 l sample in one 
application. Do not wet the nitrocellulose or any support elements prior 
to sample application. Do not apply vacuum during or after sample 
application. After spotting samples (using either method), let the 
sheets air dry. The sheets can be stored at room temperature for several 
days after sample application.
    (viii) Standard Incubation Conditions. These conditions have been 
described by Jahn et al. (1984) in paragraph (e)(2) of this section. All 
steps are carried out at room temperature on a flat shaking platform 
(one complete excursion every 2-3 seconds). For best results, do not use 
rocking or orbital shakers. Perform the following steps in enough 
solution to cover the nitrocellulose sheets to a depth of 1 cm.
    (A) Incubate 20 minutes in fixer (25 percent (v/v) isopropanol, 10 
percent (v/v) acetic acid).
    (B) Discard fixer, wash several times in deionized water to 
eliminate the fixer, and then incubate for 5 minutes in Tris-buffered 
saline (TBS): 200 mM NaCL, 60 mM Tris-HCl to pH 7.4.
    (C) Discard TBS and incubate 1 hour in blocking solution (0.5 
percent gelatin (w/v)) in TBS.
    (D) Discard blocking solution and incubate for 2 hours in antibody 
solution (anti-GFAP antiserum diluted to the desired dilution in 
blocking solution containing 0.1 percent Triton X-100). Serum anti-
bovine GFAP, which cross reacts with GFAP from rodents and humans, can 
be obtained commercially (e.g., Dako Corp.) and used at a dilution of 
1:500.
    (E) Discard antibody solution, and wash in 4 changes of TBS for 5 
minutes each time. Then wash in TBS for 10 minutes.
    (F) Discard TBS and incubate in blocking solution for 30 minutes.
    (G) Discard blocking solution and incubate for 1 hour in Protein A 
solution ([I\125\]-labeled Protein A diluted in blocking solution 
containing 0.1 percent Triton X-100, sufficient to produce 2000 counts 
per minute (cpm) per 10 l of Protein A solution).
    (H) Remove Protein A solution (it may be reused once). Wash in 0.1 
percent Triton X-100 in TBS (TBSTX) for 5 minutes, 4 times. Then wash in 
TBSTX for 2-3 hours for 4 additional times. An overnight wash in a 
larger volume can be used to replace the last 4 washes.
    (I) Hang sheets to air-dry. Cut out squares or spots and count 
radioactivity in a gamma counter.
    (ix) Expression of data. Compare radioactivity counts for samples 
obtained from control and treated animals with

[[Page 470]]

counts obtained from the standard curve. By comparing the 
immunoreactivity (counts) of each sample with that of the standard 
curve, the relative amount of GFAP in each sample can be determined and 
expressed as a percent of control.
    (d) Data Reporting and Evaluation--(1) Test Report. In addition to 
information meeting the requirements stated under 40 CFR 79.60, the 
following specific information shall be reported:
    (i) Body weight and brain region weights at time of sacrifice for 
each subject tested;
    (ii) Indication of whether each subject survived to sacrifice or 
time of death;
    (iii) Data from control animals and blank samples; and
    (iv) Statistical evaluation of results;
    (2) Evaluation of Results. (i) Results shall be evaluated in terms 
of the extent of change in the amount of GFAP as a function of treatment 
and dose. GFAP assays (of any brain region) from a minimum of 6 samples 
typically will result in a standard error of the mean of +/- 5 percent. 
In this case, a chemically-induced increase in GFAP of 115 percent of 
control is likely to be statistically significant.
    (ii) The results of this assay shall be compared to and evaluated 
with any relevant behavioral and histopathological data.
    (e) References. For additional background information on this test 
guideline the following references should be consulted.

(1) Brock, T.O and O'Callaghan, J.P. 1987. Quantitative changes in the 
          synaptic vesicle proteins, synapsin I and p38 and the 
          astrocyte specific protein, glial fibrillary acidic protein, 
          are associated with chemical-induced injury to the rat central 
          nervous system, J. Neurosci. 7:931-942.
(2) Jahn, R., Schiebler, W. Greengard, P. 1984. A quantitative dot-
          immunobinding assay for protein using nitrocellulose membrane 
          filters. Proc. Natl. Acad. Sci. U.S.A. 81:1684-1687.
(3) O'Callaghan, J.P. 1988. Neurotypic and gliotypic protein as 
          biochemical markers of neurotoxicity. Neurotoxicol. Teratol. 
          10:445-452.
(4) O'Callaghan, J.P. 1991. Quantification of glial fibrillary acidic 
          protein: comparison of slot-immunobinding assays with a novel 
          sandwich ELISA. Neurotoxicol. Teratol. 13:275-281.
(5) O'Callaghan, J.P. and Miller, D.B. 1985. Cerebellar hypoplasia in 
          the Gunn rat is associated with quantitative changes in 
          neurotypic and gliotypic proteins. J. Pharmacol. Exp. Ther. 
          234:522-532.
(6) Sette, W.F. ``Pesticide Assessment Guidelines, Subdivision `F', 
          Hazard Evaluation: Human and Domestic Animals, Addendum 10, 
          Neurotoxicity, Series 81, 82, and 83'' US-EPA, Office of 
          Pesticide Programs, EPA-540/09-91-123, March 1991.
(7) Smith, P.K., Krohn, R.I., Hermanson, G.T., Mallia, A.K., Gartner, 
          F.H., Provenzano, M.D., Fujimoto, E.K., Goeke, N.M., Olson, 
          B.J., Klenk, D.C. 1985. Measurement of protein using 
          bicinchoninic acid. Annal. Biochem. 150:76-85.



Sec. 79.68  Salmonella typhimurium reverse mutation assay.

    (a) Purpose. The Salmonella typhimurium histidine (his) reversion 
system is a microbial assay which measures his-   
his+ reversion induced by chemicals which cause base changes or 
frameshift mutations in the genome of the microorganism Salmonella 
typhimurium.
    (b) Definitions. For the purposes of this section, the following 
definitions apply:

Base pair mutagen means an agent which causes a base change in DNA. In a 
    reversion assay, this change may occur at the site of the original 
    mutation or at a second site in the chromosome.
Frameshift mutagen is an agent which causes the addition or deletion of 
    single or multiple base pairs in the DNA molecule.
Salmonella typhimurium reverse mutation assay detects mutation in a gene 
    of a histidine-requiring strain to produce a histidine independent 
    strain of this organism.

    (c) Reference substances. These may include, but need not be limited 
to, sodium azide, 2-nitrofluorene, 9-aminoacridine, 2-aminoanthracene, 
congo red, benzopurpurin 4B, trypan blue or direct blue 1.
    (d) Test method.--(1) Principle. Motor vehicle combustion emissions 
from fuel or additive/base fuel mixtures are,

[[Page 471]]

first, filtered to trap particulate matter and, then, passed through a 
sorbent resin to trap semi-volatile gases. Bacteria are separately 
exposed to the extract from both the filtered particulates and the 
resin-trapped organics. Assays are conducted using both test mixtures 
with and without a metabolic activation system and exposed cells are 
plated onto minimal medium. After a suitable period of incubation, 
revertant colonies are counted in test cultures and compared to the 
number of spontaneous revertants in unexposed control cultures.
    (2) Description. Several methods for performing the test have been 
described. The procedures described here are for the direct plate 
incorporation method and the azo-reduction method. Among those used are:
    (i) Direct plate incorporation method;
    (ii) Preincubation method;
    (iii) Azo-reduction method;
    (iv) Microsuspension method; and
    (v) Spiral assay.
    (3) Strain selection--(i) Designation. Five tester strains shall be 
used in the assay. At the present time, TA1535, TA1537, TA98, and TA100 
are designated as tester strains. The fifth strain will be chosen from 
the pool of Salmonella strains commonly used to determine the degree to 
which nitrated organic compounds, i.e., nitroarenes, contribute to the 
overall mutagenic activity of a test substance. TA98/1,8-DNP6 or 
other suitable Rosenkranz nitro-reductase resistant strains will be 
considered acceptable. The choice of the particular strain is left to 
the discretion of the researcher. However, the researcher shall justify 
the use of the selected bacterial tester strains.
    (ii) Preparation and storage of bacterial tester strains. Recognized 
methods of stock culture preparation and storage shall be used. The 
requirement of histidine for growth shall be demonstrated for each 
strain. Other phenotypic characteristics shall be checked using such 
methods as crystal violet sensitivity and resistance to ampicillin. 
Spontaneous reversion frequency shall be in the range expected as 
reported in the literature and as established in the laboratory by 
historical control values.
    (iii) Bacterial growth. Fresh cultures of bacteria shall be grown up 
to the late exponential or early stationary phase of growth 
(approximately 108-109 cells per ml).
    (4) Exogenous metabolic activation. Bacteria shall be exposed to the 
test substance both in the presence and absence of an appropriate 
exogenous metabolic activation system. For the direct plate 
incorporation method, the most commonly used system is a cofactor-
supplemented postmitochondrial fraction prepared from the livers of 
rodents treated with enzyme-inducing agents, such as Aroclor 1254. For 
the azo-reduction method, a cofactor- supplemented postmitochondrial 
fraction (S-9) prepared from the livers of untreated hamsters is 
preferred. For this method, the cofactor supplement shall contain flavin 
mononucleotide, exogenous glucose 6-phosphate dehydrogenase, NADH and 
excess of glucose-6-phosphate.
    (5) Control groups--(i) Concurrent controls. Concurrent positive and 
negative (untreated) controls shall be included in each experiment. 
Positive controls shall ensure both strain responsiveness and efficacy 
of the metabolic activation system.
    (ii) Strain specific positive controls shall be included in the 
assay. Examples of strain specific positive controls are as follows:

(A) Strain TA1535, TA100: sodium azide;
(B) TA98: 2-nitrofluorene (without activation), 2-anthramine (with 
    activation);
(C) TA1537: 9-aminoacridine; and
(D) TA98/1,8-DNP6: benzo(a)pyrene (with activation).
    The papers by Claxton et al., 1991 and 1992 in paragraph (g) in this 
section will provide helpful information for the selection of positive 
controls.
    (iii) Positive controls to ensure the efficacy of the activation 
system. The positive control reference substances for tests including a 
metabolic activation system shall be selected on the basis of the type 
of activation system used in the test. 2-Aminoanthracene is an example 
of a positive control compound in plate-incorporation tests using 
postmitochondrial fractions from the livers of rodents treated with 
enzyme-inducing agents such as Aroclor-1254.

[[Page 472]]

Congo red is an example of a positive control compound in the azo-
reduction method. Other positive control reference substances may be 
used.
    (iv) Class-specific positive controls. The azo-reduction method 
shall include positive controls from the same class of compounds as the 
test agent wherever possible.
    (6) Sampling the test atmosphere.--(i) Extracts of test emissions 
are collected on Teflon-coated glass fiber filters using an 
exhaust dilution setup. The particulates are extracted with 
dichloromethane (DCM) using Soxhlet extraction techniques. Extracts in 
DCM can be stored at dry ice temperatures until use.
    (ii) Gaseous hydrocarbons passing through the filter are trapped by 
a porous, polymer resin, like XAD-2/styrene-divinylbenzene, or an 
equivalent product. Methylene chloride is used to extract the resin and 
the sample is evaporated to dryness before storage or use.
    (iii) Samples taken from this material are then used to expose the 
cells in this assay. Final concentration of extracts in solvent/vehicle, 
or after solvent exchange, shall not interfere with cell viability or 
growth rate. The paper by Stump (1982) in paragraph (g) of this section 
is useful for preparing extracts of particulate and semi-volatile 
organic compounds from diesel and gasoline exhaust stream.
    (iv) Exposure concentrations. (A) The test should initially be 
performed over a broad range of concentrations. Among the criteria to be 
taken into consideration for determining the upper limits of test 
substance concentration are cytotoxicity and solubility. Cytotoxicity of 
the test chemical may be altered in the presence of metabolic activation 
systems. Toxicity may be evidenced by a reduction in the number of 
spontaneous revertants, a clearing of the background lawn or by the 
degree of survival of treated cultures. Relatively insoluble samples 
shall be tested up to the limits of solubility. The upper test chemical 
concentration shall be determined on a case by case basis.
    (B) Generally, a maximum of 5 mg/plate for pure substances is 
considered acceptable. At least 5 different concentrations of test 
substance shall be used with adequate intervals between test points.
    (C) When appropriate, a single positive response shall be confirmed 
by testing over a narrow range of concentrations.
    (e) Test performance. All data developed within this study shall be 
in accordance with good laboratory practice provisions under Sec. 79.60.
    (1) Direct plate incorporation method. When testing with metabolic 
activation, test solution, bacteria, and 0.5 ml of activation mixture 
containing an adequate amount of postmitochondrial fraction shall be 
added to the liquid overlay agar and mixed. This mixture is poured over 
the surface of a selective agar plate. Overlay agar shall be allowed to 
solidify before incubation. At the end of the incubation period, 
revertant colonies per plate shall be counted. When testing without 
metabolic activation, the test sample and 0.1 ml of a fresh bacterial 
culture shall be added to 2.0 ml of overlay agar.
    (2) Azo-reduction method. When testing with metabolic activation, 
0.5 ml of activation mixture containing 150 l of 
postmitochondrial fraction and 0.1 ml of bacterial culture shall be 
added to a test tube kept on ice. 0.1 ml of test solution shall be 
added, and the tubes shall be incubated with shaking at 30  deg.C for 30 
minutes. At the end of the incubation period, 2.0 ml of agar shall be 
added to each tube, the contents mixed and poured over the surface of a 
selective agar plate. Overlay agar shall be allowed to solidify before 
incubation. At the end of the incubation period, revertant colonies per 
plate shall be counted. For tests without metabolic activation, 0.5 ml 
of buffer shall be used in place of the 0.5 ml of activation mixture. 
All other procedures shall be the same as those used for the test with 
metabolic activation.
    (3) Other methods/modifications may also be appropriate.
    (4) Media. An appropriate selective medium with an adequate overlay 
agar shall be used.
    (5) Incubation conditions. All plates within a given experiment 
shall be incubated for the same time period. This incubation period 
shall be for 48-72 hours at 37  deg.C.

[[Page 473]]

    (6) Number of cultures. All plating shall be done at least in 
triplicate.
    (f) Data and report--(1) Treatment of results. Data shall be 
presented as number of revertant colonies per plate, revertants per 
kilogram (or liter) of fuel, and as revertants per kilometer (or mile) 
for each replicate and dose. These same measures shall be recorded on 
both the negative and positive control plates. The mean number of 
revertant colonies per plate, revertants per kilogram (or liter) of 
fuel, and revertants per kilometer (or mile), as well as individual 
plate counts and standard deviations shall be presented for the test 
substance, positive control, and negative control plates.
    (2) Statistical evaluation. Data shall be evaluated by appropriate 
statistical methods. Those methods shall include, at a minimum, means 
and standard deviations of the reversion data.
    (3) Interpretation of results. (i) There are several criteria for 
determining a positive result, one of which is a statistically 
significant dose-related increase in the number of revertants. Another 
criterion may be based upon detection of a reproducible and 
statistically significant positive response for at least one of the test 
substance concentrations.
    (ii) A test substance which does not produce either a statistically 
significant dose-related increase in the number of revertants or a 
statistically significant and reproducible positive response at any one 
of the test points is considered nonmutagenic in this system.
    (iii) Both biological and statistical significance shall be 
considered together in the evaluation.
    (4) Test evaluation. (i) Positive results from the Salmonella 
typhimurium reverse mutation assay indicate that, under the test 
conditions, the test substance induces point mutations by base changes 
or frameshifts in the genome of this organism.
    (ii) Negative results indicate that under the test conditions the 
test substance is not mutagenic in Salmonella typhimurium.
    (5) Test report. In addition to the reporting recommendations as 
specified under 40 CFR 79.60, the following specific information shall 
be reported:
    (i) Sampling method(s) used and manner in which cells are exposed to 
sample solution;
    (ii) Bacterial strains used;
    (iii) Metabolic activation system used (source, amount and 
cofactor); details of preparation of postmitochondrial fraction;
    (iv) Concentration levels and rationale for selection of 
concentration range;
    (v) Description of positive and negative controls, and 
concentrations used, if appropriate;
    (vi) Individual plate counts, mean number of revertant colonies per 
plate, number of revertants per mile (or kilometer), and standard 
deviation; and
    (vii) Dose-response relationship, if applicable.
    (g) References. For additional background information on this test 
guideline, the following references should be consulted.

(1) 40 CFR 798.5265, The Salmonella typhimurium reverse mutation asay.
(2) Ames, B.N., McCann, J., Yamasaki, E. ``Methods for detecting 
          carcinogens and mutagens with the Salmonella/mammalian 
          microsome mutagenicity test,'' Mutation Research 31:347-364 
          (1975).
(3) Huisingh, J.L., et al.,``Mutagenic and Carcinogenic Potency of 
          Extracts of Diesel and Related Environmental Emissions: Study 
          Design, Sample Generation, Collection, and Preparation''. In: 
          Health Effects of Diesel Engine Emissions, Vol. II, W.E. 
          Pepelko, R., M., Danner and N. A. Clarke (Eds.), US EPA, 
          Cincinnati, EPA-600/9-80-057b, pp. 788-800 (1980).
(4) [Reserved]
(5) Claxton, L.D., Allen, J., Auletta, A., Mortelmans, K., Nestmann, E., 
          Zeiger, E. ``Guide for the Salmonella typhimurium/mammalian 
          microsome tests for bacterial mutagenicity'' Mutation Research 
          189(2):83-91 (1987).
(6) Claxton, L., Houk, V.S., Allison, J.C., Creason, J., ``Evaluating 
          the relationship of metabolic activation system concentrations 
          and chemical dose concentrations for the Salmonella Spiral and 
          Plate Assays'' Mutation Research 253:127-136 (1991).
(7) Claxton, L., Houk, V.S., Monteith, L.G., Myers, L.E., Hughes, T.J., 
          ``Assessing the use of known mutagens to calibrate the 
          Salmonella typhimurium mutagenicity assay: I. Without 
          exogenous activation.'' Mutation Research 253:137-147 (1991).

[[Page 474]]

(8) Claxton, L., Houk, V.S., Warner, J.R., Myers, L.E., Hughes, T.J., 
          ``Assessing the use of known mutagens to calibrate the 
          Salmonella typhimurium mutagenicity assay: II. With exogenous 
          activation.'' Mutation Research 253:149-159 (1991).
(9) Claxton, L., Creason, J., Lares, B., Augurell, E., Bagley, S., 
          Bryant, D.W., Courtois, Y.A., Douglas, G., Clare, C.B., Goto, 
          S., Quillardet, P., Jagannath, D.R., Mohn, G., Neilsen, P.A., 
          Ohnishi, Y., Ong, T., Pederson, T.C., Shimizu, H., Nylund, L., 
          Tokiwa, H., Vink, I.G.R., Wang, Y., Warshawsky, D., ``Results 
          of the IPCS Collaborative Study on Complex Mixtures'' Mutation 
          Research 276:23-32 (1992).
(10) Claxton, L., Douglas, G., Krewski, D., Lewtas, J., Matsushita, H., 
          Rosenkranz, H., ``Overview, conclusions, and recommendations 
          of the IPCS Collaborative Study on Complex Mixtures'' Mutation 
          Research 276:61-80 (1992).
(11) Houk, V.S., Schalkowsky, S., and Claxton, L.D., ``Development and 
          Validation of the Spiral Salmonella Assay: An Automated 
          Approach to Bacterial Mutagenicity Testing'' Mutation Research 
          223:49-64 (1989).
(12) Jones, E., Richold, M., May, J.H., and Saje, A. ``The Assessment of 
          the Mutagenic Potential of Vehicle Engine Exhaust in the Ames 
          Salmonella Assay Using a Direct Exposure Method'' Mutation 
          Research 97:35-40 (1985).
(13) Maron, D., and Ames, B. N., Revised methods for the Salmonella 
          mutagenicity test, Mutation Research, 113:173-212 (1983).
(14) Prival, M.J., and Mitchell, V.D. ``Analysis of a method for testing 
          azo dyes for mutagenic activity in Salmonella typhimurium in 
          the presence of flavin mononucleotide and hamster liver S-9,'' 
          Mutation Research 97:103-116 (1982).
(15) Rosenkranz, H.S., et.al. ``Nitropyrenes: Isolation, identification, 
          and reduction of mutagenic impurities in carbon black and 
          toners'' Science 209:1039-43 (1980).
(16) Stump, F., Snow, R., et.al., ``Trapping gaseous hydrocarbons for 
          mutagenic testing'' SAE Technical Paper Series, No. 820776 
          (1982).
(17) Vogel, H.J., Bonner, D.M. ``Acetylornithinase of E. coli: partial 
          purification and some properties,'' Journal of Biological 
          Chemistry. 218:97-106 (1956).



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




                      Subpart A--General Provisions

Sec.
80.1  Scope.
80.2  Definitions.
80.3  Test methods.
80.4  Right of entry; tests and inspections.
80.5  Penalties.
80.7  Requests for information.

                  Subpart B--Controls and Prohibitions

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

                     Subpart C--Oxygenated Gasoline

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

                    Subpart D--Reformulated Gasoline

80.40  Fuel certification procedures.
80.41  Standards and requirements for compliance.
80.42  Simple emissions model.
80.43-80.44  [Reserved]
80.45  Complex emissions model.
80.46  Measurement of reformulated gasoline fuel parameters.
80.47  [Reserved]
80.48  Augmentation of the complex emission model by vehicle testing.
80.49  Fuels to be used in augmenting the complex emission model through 
          vehicle testing.
80.50  General test procedure requirements for augmentation of the 
          emission models.
80.51  Vehicle test procedures.
80.52  Vehicle preconditioning.
80.53-80.54  [Reserved]
80.55  Measurement methods for benzene and 1,3-butadiene.
80.56  Measurement methods for formaldehyde and acetaldehyde.
80.57-80.58  [Reserved]
80.59  General test fleet requirements for vehicle testing.
80.60  Test fleet requirements for exhaust emission testing.
80.61  [Reserved]
80.62  Vehicle test procedures to place vehicles in emitter group sub-
          fleets.
80.63-80.64  [Reserved]

[[Page 475]]

80.65  General requirements for refiners, importers, and oxygenate 
          blenders.
80.66  Calculation of reformulated gasoline properties.
80.67  Compliance on average.
80.68  Compliance surveys.
80.69  Requirements for downstream oxygenate blending.
80.70  Covered areas.
80.71  Descriptions of VOC-control regions.
80.72  [Reserved]
80.73  Inability to produce conforming gasoline in extraordinary 
          circumstances.
80.74  Recordkeeping requirements.
80.75  Reporting requirements.
80.76  Registration of refiners, importers or oxygenate blenders.
80.77  Product transfer documentation.
80.78  Controls and prohibitions on reformulated gasoline.
80.79  Liability for violations of the prohibited activities.
80.80  Penalties.
80.81  Enforcement exemptions for California gasoline.
80.82  Conventional gasoline marker. [Reserved]
80.83  Renewable oxygenate requirements.
80.84-80.89  [Reserved]

                         Subpart E--Anti-Dumping

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

                      Subpart F--Attest Engagements

80.125  Attest engagements.
80.126  Definitions.
80.127  Sample size guidelines.
80.128  Agreed upon procedures for refiners and importers.
80.129  Agreed upon procedures for downstream oxygenate blenders.
80.130  Agreed upon procedures reports.
80.131-80.135  [Reserved]

                      Subpart G--Detergent Gasoline

80.140  Definitions.
80.141  Interim detergent gasoline program.
80.142-80.154  [Reserved]
80.155  Controls and prohibitions.
80.156  Liability for violations of the interim detergent program 
          controls and prohibitions.
80.157  Volumetric additive reconciliation (``VAR''), equipment 
          calibration, and recordkeeping requirements.
80.158  Product transfer documents.
80.159  Penalties.
80.160  Exemptions.
80.161-80.169  [Reserved]

Appendix A to Part 80--Test for the Determination of Phosphorus in 
          Gasoline
Appendix B to Part 80--Test Methods for Lead in Gasoline
Appendix C to Part 80--[Reserved]
Appendix D to Part 80--Sampling Procedures for Fuel Volatility
Appendix E to Part 80--Test for Determining Reid Vapor Pressure (RVP) of 
          Gasoline and Gasoline--Oxygenate Blends
Appendix F to Part 80--Test for Determining the Quantity of Alcohol in 
          Gasoline
Appendix G to Part 80--Sampling Procedures for Diesel Fuel

    Authority: Secs. 144, 211, and 301(a) of the Clean Air Act, as 
amended (42 U.S.C. 7414, 7545, and 7601(a)).

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

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



                      Subpart A--General Provisions



Sec. 80.1   Scope.

    (a) This part prescribes regulations for the control and/or 
prohibition of fuels and additives for use in motor vehicles and motor 
vehicle engines. These regulations are based upon a determination by the 
Administrator that the emission product of a fuel or additive will 
endanger the public health, or will impair to a significant degree the 
performance of a motor vehicle emission control device in general use or 
which the Administrator finds has been developed to a point where in a 
reasonable time it would be in general use were such regulations 
promulgated; and certain other findings specified by the Act.
    (b) Nothing in this part is intended to preempt the ability of State 
or local governments to control or prohibit any

[[Page 476]]

fuel or additive for use in motor vehicles and motor vehicle engines 
which is not explicitly regulated by this part.

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



Sec. 80.2   Definitions.

    As used in this part:
    (a) Act means the Clean Air Act, as amended (42 U.S.C. 1857 et 
seq.).
    (b) Administrator means the Administrator of the Environmental 
Protection Agency.
    (c) Gasoline means any fuel sold in any State1 for use in motor 
vehicles and motor vehicle engines, and commonly or commercially known 
or sold as gasoline.
---------------------------------------------------------------------------

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

    (d) [Reserved]
    (e) Lead additive means any substance containing lead or lead 
compounds.
    (f) [Reserved]
    (g) Unleaded gasoline means gasoline which is produced without the 
use of any lead additive and which contains not more than 0.05 gram of 
lead per gallon and not more than 0.005 gram of phosphorus per gallon.
    (h) Refinery means a plant at which gasoline or diesel fuel is 
produced.
    (i) Refiner means any person who owns, leases, operates, controls, 
or supervises a refinery.
    (j) Retail outlet means any establishment at which gasoline, diesel 
fuel, methanol, natural gas or liquefied petroleum gas is sold or 
offered for sale for use in motor vehicles.
    (k) Retailer means any person who owns, leases, operates, controls, 
or supervises a retail outlet.
    (l) Distributor means any person who transports or stores or causes 
the transportation or storage of gasoline or diesel fuel at any point 
between any gasoline or diesel fuel refinery or importer's facility and 
any retail outlet or wholesale purchaser-consumer's facility.
    (m) Lead additive manufacturer means any person who produces a lead 
additive or sells a lead additive under his own name.
    (n) Reseller means any person who purchases gasoline or diesel fuel 
identified by the corporate, trade, or brand name of a refiner from such 
refiner or a distributor and resells or transfers it to retailers or 
wholesale purchaser-consumers displaying the refiner's brand, and whose 
assets or facilities are not substantially owned, leased, or controlled 
by such refiner.
    (o) Wholesale purchaser-consumer means any organization that is an 
ultimate consumer of gasoline, diesel fuel, methanol, natural gas or 
liquefied petroleum gas and which purchases or obtains gasoline, diesel 
fuel, natural gas or liquefied petroleum gas from a supplier for use in 
motor vehicles and, in the case of gasoline, diesel fuel, methanol or 
liquefied petroleum gas, receives delivery of that product into a 
storage tank of at least 550-gallon capacity substantially under the 
control of that organization.
    (p)--(q) [Reserved]
    (r) Importer means a person who imports gasoline, gasoline blending 
stocks or components, or diesel fuel from a foreign country into the 
United States (including the Commonwealth of Puerto Rico, the Virgin 
Islands, Guam, American Samoa, and the Northern Mariana Islands).
    (s) Gasoline blending stock or component means any liquid compound 
which is blended with other liquid compounds or with lead additives to 
produce gasoline.
    (t) Carrier means any distributor who transports or stores or causes 
the transportation or storage of gasoline or diesel fuel without taking 
title to or otherwise having any ownership of the gasoline or diesel 
fuel, and without altering either the quality or quantity of the 
gasoline or diesel fuel.
    (u) Ethanol blending plant means any refinery at which gasoline is 
produced solely through the addition of ethanol to gasoline, and at 
which the quality or quantity of gasoline is not altered in any other 
manner.
    (v) Ethanol blender means any person who owns, leases, operates, 
controls, or supervises an ethanol blending plant.
    (w) Cetane index or ``Calculated cetane index'' is a number 
representing the ignition properties of diesel fuel oils from API 
gravity and mid-boiling

[[Page 477]]

point as determined by ASTM standard method D 976-80, entitled 
``Standard Methods for Calculated Cetane Index of Distillate Fuels''. 
ASTM test method D 976-80 is incorporated by reference. This 
incorporation by reference was approved by the Director of the Federal 
Register in accordance with 5 U.S.C. 552(a) and 1 CFR part 51. A copy 
may be obtained from the American Society for Testing and Materials, 
1916 Race Street, Philadelphia, PA 19103. A copy may be inspected at the 
Air Docket Section (A-130), Room M-1500, U.S. Environmental Protection 
Agency, Docket No. A-86-03, 401 M Street SW., Washington, DC 20460 or at 
the Office of the Federal Register, 800 North Capitol Street, NW., suite 
700, Washington, DC.
    (x) Diesel fuel means any fuel sold in any State and suitable for 
use in diesel motor vehicles and diesel motor vehicle engines, and which 
is commonly or commercially known or sold as diesel fuel.
    (y) Sulfur percentage is the percentage of sulfur as determined by 
ASTM standard test method D 2622-87, entitled ``Standard Test Method for 
Sulfur in Petroleum Products by X-Ray Spectrometry''. ASTM test method D 
2622-87 is incorporated by reference. This incorporation by reference 
was approved by the Director of the Federal Register in accordance with 
5 U.S.C. 552(a) and 1 CFR part 51. A copy may be obtained from the 
American Society for Testing and Materials, 1916 Race Street, 
Philadelphia, PA 19103. A copy may be inspected at the Air Docket 
Section (A-130), room M-1500, U.S. Environmental Protection Agency, 
Docket No. A-86-03, 401 M Street SW., Washington DC 20460 or at the 
Office of the Federal Register, 800 North Capitol Street, NW., suite 
700, Washington, DC.
    (z) Aromatic content is the aromatic hydrocarbon content in volume 
percent as determined by ASTM standard test method D 1319-88, entitled 
``Standard Test Method for Hydrocarbon Types in Liquid Petroleum 
Products by Fluorescent Indicator Adsorption''. ASTM test method D 1319-
88 is incorporated by reference. This incorporation by reference was 
approved by the Director of the Federal Register in accordance with 5 
U.S.C. 552(a) and 1 CFR part 51. A copy may be obtained from the 
American Society for Testing and Materials, 1916 Race Street, 
Philadelphia, PA 19103. A copy may be inspected at the Air Docket 
Section (A-130), room M-1500, U.S. Environmental Protection Agency, 
Docket No. A-86-03, 401 M Street SW., Washington, DC 20460 or at the 
Office of the Federal Register, 800 North Capitol Street, NW., suite 
700, Washington, DC.
    (aa) Small refinery means a domestic diesel fuel refinery
    (1) Which has a crude oil or bonafide feedstock capacity of 50,000 
barrels per day or less, and
    (2) Which is not owned or controlled by any refiner with a total 
combined crude oil or bonafide feedstock capacity greater than 137,500 
barrels per day.

The above capacities shall be measured in terms of the average of the 
actual daily utilization rates of the affected refiners or refineries 
during the period January 1, 1988 to December 31, 1990. These averages 
will be calculated as barrels per calendar day.
    (bb) [Reserved]
    (cc) Designated Volatility Nonattainment Area means any area 
designated as being in nonattainment with the National Ambient Air 
Quality Standard for ozone pursuant to rulemaking under section 
107(d)(4)(A)(ii) of the Clean Air Act.
    (dd) Designated Volatility Attainment Area means an area not 
designated as being in nonattainment with the National Ambient Air 
Quality Standard for ozone pursuant to rulemaking under section 
107(d)(4)(A)(ii) of the Clean Air Act.
    (ee) Reformulated gasoline means any gasoline whose formulation has 
been certified under Sec. 80.40, which meets each of the standards and 
requirements prescribed under Sec. 80.41, and which contains less than 
the maximum concentration of the marker specified in Sec. 80.82 that is 
allowed for reformulated gasoline under Sec. 80.82.
    (ff) Conventional gasoline means any gasoline which has not been 
certified under Sec. 80.40.
    (gg) Batch of reformulated gasoline means a quantity of reformulated 
gasoline which is homogeneous with regard to those properties which are 
specified for reformulated gasoline certification.

[[Page 478]]

    (hh) Covered area means each of the geographic areas specified in 
Sec. 80.70 in which only reformulated gasoline may be sold or dispensed 
to ultimate consumers.
    (ii) Reformulated gasoline credit means the unit of measure for the 
paper transfer of oxygen or benzene content resulting from reformulated 
gasoline which contains more than 2.1 weight percent of oxygen or less 
than 0.95 volume percent benzene.
    (jj) Oxygenate means any substance which, when added to gasoline, 
increases the oxygen content of that gasoline. Lawful use of any of the 
substances or any combination of these substances requires that they be 
``substantially similar'' under section 211(f)(1) of the Clean Air Act, 
or be permitted under a waiver granted by the Administrator under the 
authority of section 211(f)(4) of the Clean Air Act.
    (kk) Reformulated gasoline blendstock for oxygenate blending, or 
RBOB means a petroleum product which, when blended with a specified type 
and percentage of oxygenate, meets the definition of reformulated 
gasoline, and to which the specified type and percentage of oxygenate is 
added other than by the refiner or importer of the RBOB at the refinery 
or import facility where the RBOB is produced or imported.
    (ll) Oxygenate blending facility means any facility (including a 
truck) at which oxygenate is added to gasoline or blendstock, and at 
which the quality or quantity of gasoline is not altered in any other 
manner except for the addition of deposit control additives.
    (mm) Oxygenate blender means any person who owns, leases, operates, 
controls, or supervises an oxygenate blending facility, or who owns or 
controls the blendstock or gasoline used or the gasoline produced at an 
oxygenate blending facility.
    (nn) Oxygenated fuels program reformulated gasoline, or OPRG means 
reformulated gasoline which is intended for use in an oxygenated fuels 
program control area, as defined at paragraph (pp) of this section, 
during an oxygenated fuels program control period, as defined at 
paragraph (qq) of this section.
    (oo) Liquefied petroleum gas means a liquid hydrocarbon fuel that is 
stored under pressure and is composed primarily of species that are 
gases at atmospheric conditions (temperature = 25 deg.C and pressure = 1 
atm), excluding natural gas.
    (pp) Control area means a geographic area in which only oxygenated 
gasoline under the oxygenated gasoline program may be sold or dispensed, 
with boundaries determined by section 211(m) of the Act.
    (qq) Control period means the period during which oxygenated 
gasoline must be sold or dispensed in any control area, pursuant to 
section 211(m)(2) of the Act.
    (rr) Oxygenated gasoline means gasoline which contains a measurable 
amount of oxygenate.
    (ss) Extended non-commingling season means the period during which 
oxygenates which demonstrate commingling-related increases in Reid Vapor 
Pressure (RVP) will not be permitted to receive credit toward the 
renewable oxygenate requirements of Sec. 80.83. Any extended non-
commingling season is limited to that period of time determined by the 
Administrator pursuant to Sec. 80.83(i).
    (tt) Natural gas means a fuel whose primary constituent is methane.
    (uu) Methanol means any fuel sold for use in motor vehicles and 
commonly known or commercially sold as methanol or MXX, where XX is the 
percent methanol (CH3OH) by volume.

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

[38 FR 1255, Jan. 10, 1973, as amended at 38 FR 33741, Dec. 6, 1973; 39 
FR 43283, Dec. 12, 1974; 44 FR 46277, Aug. 7, 1979; 47 FR 49331, Oct. 
29, 1982; 48 FR 4287, Jan. 31, 1983; 50 FR 9397, Mar. 7, 1985; 54 FR 
11883, Mar. 22, 1989; 55 FR 34137, Aug. 21, 1990; 56 FR 13768, Apr. 4, 
1991; 56 FR 64710, Dec. 12, 1991; 57 FR 19537, May 7, 1992; 57 FR 47771, 
Oct. 20, 1992; 59 FR 7812, Feb. 16, 1994; 59 FR 39289, Aug. 2, 1994; 59 
FR 48489, Sept. 21, 1994; 59 FR 60715, Nov. 28, 1994; 61 FR 3837, Feb. 
2, 1996]

    Effective Date Note: At 59 FR 39289, Aug. 2, 1994, Sec. 80.2 was 
amended by adding paragraph (ss) effective September 1, 1994. At 59 FR 
60715, Nov. 28, 1994, the amendment was stayed effective September 13, 
1994.

[[Page 479]]



Sec. 80.3  Test methods.

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

[47 FR 765, Jan. 7, 1982]



Sec. 80.4  Right of entry; tests and inspections.

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

[50 FR 9397, Mar. 7, 1985]



Sec. 80.5   Penalties.

    Any person who violates these regulations shall be liable to the 
United States for a civil penalty of not more than the sum of $25,000 
for every day of such violation and the amount of economic benefit or 
savings resulting from the violation. Any violation with respect to a 
regulation proscribed under section 211(c), (k), (l) or (m) of the Act 
which establishes a regulatory standard based upon a multi-day averaging 
period shall constitute a separate day of violation for each and every 
day in the averaging period. Civil penalties shall be assessed in 
accordance with section 205(b) and (c) of the Act.

[58 FR 65554, Dec. 15, 1993]



Sec. 80.7   Requests for information.

    (a) When the Administrator, the Regional Administrator, or their 
delegates have reason to believe that a violation of section 211(c) or 
section 211(n) of the Act and the regulations thereunder has occurred, 
they may require any refiner, distributor, wholesale purchaser-consumer, 
or retailer to report the following information regarding receipt, 
transfer, delivery, or sale of gasoline represented to be unleaded 
gasoline and to allow the reproduction of such information at all 
reasonable times.
    (1) For any bulk shipment of gasoline represented to be unleaded 
gasoline which is transferred, sold, or delivered within the previous 6 
months by a refiner or a distributor to a distributor, wholesale 
purchaser-consumer or a retail outlet, the refiner or distributor shall 
maintain and provide the following information as applicable:
    (i) Business or corporate name and address of distributors, 
wholesale purchaser-consumers or retail outlets to which the gasoline 
has been transferred, sold, or delivered.
    (ii) Quantity of gasoline involved.
    (iii) Date of delivery.
    (iv) Storage location of gasoline prior to transit via delivery 
vessel (e.g., location of a bulk terminal).
    (v) Business or corporate name and address of the person who 
delivered the gasoline.
    (vi) Identification of delivery vessel (e.g., truck number). This 
information shall be supplied by the person in paragraph (a)(1)(v) of 
this section who performed the delivery, e.g., common or contract 
carrier.
    (2) For any bulk shipment of gasoline represented to be unleaded 
gasoline received by a retail outlet or a wholesale-purchaser-consumer 
facility within the previous 6 months, whether by purchase or otherwise, 
the retailer or wholesale purchaser-consumer shall maintain 
accessibility to and provide the following information:
    (i) Business or corporate name and address of the distributor.
    (ii) Quantity of gasoline received.
    (iii) Date of receipt.
    (b) Upon request by the Administrator, the Regional Administrator, 
or their delegates, any retailer shall provide documentation of his 
annual total sales volume in gallons of gasoline for each retail outlet 
for each calendar year beginning with 1971.
    (c) Any refiner, distributor, wholesale purchaser-consumer, 
retailer, or importer shall provide such other information as the 
Administrator or his authorized representative may reasonably require to 
enable him to determine whether such refiner, distributor, wholesale 
purchaser-consumer, retailer, or importer has acted or is acting in 
compliance with sections 211(c)

[[Page 480]]

and 211(n) of the Act and the regulations thereunder and shall, upon 
request of the Administrator or his authorized representative, produce 
and allow reproduction of any relevant records at all reasonable times. 
Such information may include but is not limited to records of unleaded 
gasoline inventory at a wholesale purchaser-consumer facility or a 
retail outlet, unleaded pump meter readings at a wholesale purchaser-
consumer facility or a retail outlet, and receipts providing the date of 
acquisition of signs, labels, and nozzles required by Sec. 80.22. No 
person shall be required to furnish information requested under this 
paragraph if he can establish that such information is not maintained in 
the normal course of his business.

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

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



                  Subpart B--Controls and Prohibitions

Secs. 80.20--80.21  [Reserved]



Sec. 80.22  Controls and prohibitions.

    (a) After December 31, 1995, no person shall sell, offer for sale, 
supply, offer for supply, dispense, transport, or introduce into 
commerce gasoline represented to be unleaded gasoline unless such 
gasoline meets the defined requirements for unleaded gasoline in 
Sec. 80.2(g); nor shall he dispense, or cause or allow the gasoline 
other than unleaded gasoline to be dispensed into any motor vehicle 
which is equipped with a gasoline tank filler inlet which is designed 
for the introduction of unleaded gasoline.
    (b) After December 31, 1995, no person shall sell, offer for sale, 
supply, offer for supply, dispense, transport, or introduce into 
commerce for use as fuel in any motor vehicle (as defined in Section 
216(2) of the Clean Air Act, 42 U.S.C. 7550(2)), any gasoline which is 
produced with the use of lead additives or which contains more than 0.05 
gram of lead per gallon.
    (c)--(e) [Reserved]
    (f) Beginning January 1, 1996, every retailer and wholesale 
purchaser-consumer shall equip all gasoline pumps as follows:
    (1) [Reserved]
    (2) Each pump from which unleaded gasoline is dispensed into motor 
vehicles shall be equipped with a nozzle spout which meets the following 
specifications:
    (i) The outside diameter of the terminal end shall not be greater 
than 0.840 inch (2.134 centimeters);
    (ii) The terminal end shall have a straight section of at least 2.5 
inches (6.34 centimeters) in length; and
    (iii) The retaining spring shall terminate 3.0 inches (7.6 
centimeters) from the terminal end.
     (g)--(i) Reserved
    (j) After July 1, 1996 every retailer and wholesale purchaser-
consumer handling over 10,000 gallons (37,854 liters) of fuel per month 
shall limit each nozzle from which gasoline or methanol is introduced 
into motor vehicles to a maximum fuel flow rate not to exceed 10 gallons 
per minute (37.9 liters per minute). The flow rate may be controlled 
through any means in the pump/dispenser system, provided the nozzle flow 
rate does not exceed 10 gallons per minute (37.9 liters per minute). 
After January 1, 1998 this requirement applies to every retailer and 
wholesale purchaser-consumer. Any dispensing pump that is dedicated 
exclusively to heavy-duty vehicles, boats, or airplanes is exempt from 
this requirement.

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

    Effective Date Note: At 61 FR 33039, June 26, 1996, Sec. 80.22 was 
amended by revising paragraph (j), effective Aug. 26, 1996. For the 
convenience of the user, the superseded text is set forth as follows:
Sec. 80.22  Controls and prohibitions.

                                * * * * *

    (j) After January 1, 1996 every retailer and wholesale purchaser-
consumer handling over 10,000 gallons of fuel per month shall equip each 
pump from which gasoline or methanol is introduced into motor vehicles 
with a nozzle that dispenses fuel at a flow rate not to exceed 10 
gallons per minute. After January

[[Page 481]]

1, 1998 this requirement applies to every retailer and wholesale 
purchaser-consumer. Any dispensing pump shown to be dedicated to heavy-
duty vehicles is exempt from this requirement.



Sec. 80.23   Liability for violations.

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

[[Page 482]]

Provided, however, That if such wholesale purchaser-consumer was 
supplied by a reseller, the refiner must demonstrate that the violation 
could not have been prevented by such reseller's compliance with a 
contractual undertaking imposed by the refiner on such reseller as 
provided in paragraph (b)(2)(iii) of this section.
    (viii) In paragraphs (b)(2)(ii) through (vi) hereof, the term ``was 
caused'' means that the refiner must demonstrate by reasonably specific 
showings by direct or circumstantial evidence that the violation was 
caused or must have been caused by another.
    (c) In any case in which a retailer or wholesale purchaser-consumer, 
a reseller, and any gasoline refiner would be in violation under 
paragraph (a)(1) of this section, the reseller shall not be deemed in 
violation if he can demonstrate that the violation was not caused by him 
or his employee or agent.
    (d) In any case in which a retailer or wholesale purchaser-consumer 
and any gasoline distributor would be in violation under paragraph 
(a)(2) of this section, the distributor will not be deemed in violation 
if he can demonstrate that the violation was not caused by him or his 
employee or agent.
    (e)(1) In any case in which a retailer or his employee or agent or a 
wholesale purchase-consumer or his employee or agent introduced gasoline 
other than unleaded gasoline into a motor vehicle which is equipped with 
a gasoline tank filler inlet designed for the introduction of unleaded 
gasoline, only the retailer or wholesale purchaser-consumer shall be 
deemed in violation.
    (2) [Reserved]

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

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



Sec. 80.24   Controls applicable to  motor vehicle manufacturers.

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

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

    Effective Date Note: At 61 FR 28766, June 6, 1996, Sec. 80.24 was 
amended by revising paragraph (b), effective July 8, 1996. For the 
convenience of the user, the superseded text is set forth as follows:
Sec. 80.24  Controls applicable to  motor vehicle manufacturers.

                                * * * * *

    (b) Manufacture such vehicle with each gasoline tank filler inlet 
having a restriction which prevents the insertion of a nozzle with a 
spout as described in Sec. 80.22(f)(1) and allows the insertion of a 
nozzle with a spout as described in Sec. 80.22(f)(2).
    (1) Such filler inlet shall be designed to pass not more than 700 
c.c. of gasoline into the tank when the introduction of gasoline into 
such filler inlet is attempted from a nozzle, as described in 
Sec. 80.22(f)(1), which has a vacuum port the center of which is located 
within 0.87 inches of the tip and which passes less than 120 c.c. of 
fuel when fully and rapidly activated with the nozzle vacuum port 
plugged. During such attempted introduction, the nozzle shall be 
inserted such that its automatic shutoff vacuum port is at various 
depths within the filler inlet, except those locations which cause fuel 
spillage (not including splash back) outside the filler inlet shall not 
be used. The nozzle may have any orientation within the filler inlet 
which may reasonably be expected to be encountered in use. The nozzle 
valve shall be fully and rapidly opened to a 8plus-minus1 gallon/
minute flow setting. This test is conducted using a test fixture which 
positions the filler inlet pipe in the same position as it is installed 
in the vehicle.
    (2) Paragraph (b)(1) of this section shall not apply to motorcycles.

[[Page 483]]

Sec. 80.25  [Reserved]



Sec. 80.26   Confidentiality of information.

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

[38 FR 33741, Dec. 6, 1973]



Sec. 80.27  Controls and prohibitions on gasoline volatility.

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

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

[[Page 484]]

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

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

                               Applicable Standards \1\ 1992 and Subsequent Years                               
----------------------------------------------------------------------------------------------------------------
                     State                           May          June         July        August     September 
----------------------------------------------------------------------------------------------------------------
Alabama........................................          9.0          7.8          7.8          7.8          7.8
Arizona........................................          9.0          7.8          7.8          7.8          7.8
Arkansas.......................................          9.0          7.8          7.8          7.8          7.8
California.....................................          9.0          7.8          7.8          7.8          7.8
Colorado \2\...................................          9.0          7.8          7.8          7.8          7.8
Connecticut....................................          9.0          9.0          9.0          9.0          9.0
Delaware.......................................          9.0          9.0          9.0          9.0          9.0

[[Page 485]]

                                                                                                                
District of Columbia...........................          9.0          7.8          7.8          7.8          7.8
Florida........................................          9.0          7.8          7.8          7.8          7.8
Georgia........................................          9.0          7.8          7.8          7.8          7.8
Idaho..........................................          9.0          9.0          9.0          9.0          9.0
Illinois.......................................          9.0          9.0          9.0          9.0          9.0
Indiana........................................          9.0          9.0          9.0          9.0          9.0
Iowa...........................................          9.0          9.0          9.0          9.0          9.0
Kansas.........................................          9.0          7.8          7.8          7.8          7.8
Kentucky.......................................          9.0          9.0          9.0          9.0          9.0
Louisiana......................................          9.0          7.8          7.8          7.8          7.8
Maine..........................................          9.0          9.0          9.0          9.0          9.0
Maryland.......................................          9.0          7.8          7.8          7.8          7.8
Massachusetts..................................          9.0          9.0          9.0          9.0          9.0
Michigan.......................................          9.0          9.0          9.0          9.0          9.0
Minnesota......................................          9.0          9.0          9.0          9.0          9.0
Mississippi....................................          9.0          7.8          7.8          7.8          7.8
Missouri.......................................          9.0          7.8          7.8          7.8          7.8
Montana........................................          9.0          9.0          9.0          9.0          9.0
Nebraska.......................................          9.0          9.0          9.0          9.0          9.0
Nevada.........................................          9.0          7.8          7.8          7.8          7.8
New Hampshire..................................          9.0          9.0          9.0          9.0          9.0
New Jersey.....................................          9.0          9.0          9.0          9.0          9.0
New Mexico.....................................          9.0          7.8          7.8          7.8          7.8
New York.......................................          9.0          9.0          9.0          9.0          9.0
North Carolina.................................          9.0          7.8          7.8          7.8          7.8
North Dakota...................................          9.0          9.0          9.0          9.0          9.0
Ohio...........................................          9.0          9.0          9.0          9.0          9.0
Oklahoma.......................................          9.0          7.8          7.8          7.8          7.8
Oregon.........................................          9.0          7.8          7.8          7.8          7.8
Pennsylvania...................................          9.0          9.0          9.0          9.0          9.0
Rhode Island...................................          9.0          9.0          9.0          9.0          9.0
South Carolina \3\.............................          9.0          9.0          9.0          9.0          9.0
South Dakota...................................          9.0          9.0          9.0          9.0          9.0
Tennessee:.....................................                                                                 
  Knox County..................................          9.0          9.0          9.0          9.0          9.0
  All other volatility nonattainment areas.....          9.0          7.8          7.8          7.8          7.8
Texas..........................................          9.0          7.8          7.8          7.8          7.8
Utah...........................................          9.0          7.8          7.8          7.8          7.8
Vermont........................................          9.0          9.0          9.0          9.0          9.0
Virginia.......................................          9.0          7.8          7.8          7.8          7.8
Washington.....................................          9.0          9.0          9.0          9.0          9.0
West Virginia..................................          9.0          9.0          9.0          9.0          9.0
Wisconsin......................................          9.0          9.0          9.0          9.0          9.0
Wyoming........................................          9.0          9.0          9.0          9.0          9.0
----------------------------------------------------------------------------------------------------------------
\1\ Standards are expressed in pounds per square inch (psi).                                                    
\2\ The standard for 1992 through 1997 in the Denver-Boulder nonattainment area will be 9.0 for June 1 through  
  September 15.                                                                                                 
\3\ The standard for nonattainment areas in South Carolina from June 1 until September 15 in 1992 and 1993 was  
  7.8 psi.                                                                                                      

    (b) Determination of compliance. Compliance with the standards 
listed in paragraph (a) of this section shall be determined by use of 
one of the sampling methodologies as specified in appendix D of this 
part and the testing methodology specified in appendix E of this part.
    (c) Liability. Liability for violations of paragraph (a) of this 
section shall be determined according to the provisions of Sec. 80.28. 
Where the terms refiner, importer, distributor, reseller, carrier, 
ethanol blender, retailer, or wholesale purchaser-consumer are expressed 
in the singular in Sec. 80.28, these terms shall include the plural.
    (d) Special provisions for alcohol blends. (1) Any gasoline which 
meets the requirements of paragraph (d)(2) of this section shall not be 
in violation of this section if its Reid vapor pressure does not exceed 
the applicable standard in paragraph (a) of this section by more than 
one pound per square inch (1.0 psi).
    (2) In order to qualify for the special regulatory treatment 
specified in paragraph (d)(1) of this section, gasoline must contain 
denatured, anhydrous ethanol. The concentration of the ethanol, 
excluding the required denaturing agent, must be at least 9% and no more 
than 10% (by volume) of the gasoline.

[[Page 486]]

The ethanol content of the gasoline shall be determined by use of one of 
the testing methodologies specified in appendix F to this part. The 
maximum ethanol content of gasoline shall not exceed any applicable 
waiver conditions under section 211(f)(4) of the Clean Air Act.
    (3) Each invoice, loading ticket, bill of lading, delivery ticket 
and other document which accompanies a shipment of gasoline containing 
ethanol shall contain a legible and conspicuous statement that the 
gasoline being shipped contains ethanol and the percentage concentration 
of ethanol.
    (e) Testing exemptions. (1)(i) Any person may request a testing 
exemption by submitting an application that includes all the information 
listed in paragraphs (e)(3), (4), (5) and (6) of this section to:


Director (6406J), Field Operations and Support Division, U.S. 
Environmental Protection Agency, 401 M Street, SW., Washington, DC 20460


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

[[Page 487]]

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

[54 FR 11883, Mar. 22, 1989; 54 FR 27017, June 27, 1989, as amended at 
54 FR 33219, Aug. 14, 1989; 55 FR 32666, June 11, 1990; 56 FR 20548, May 
6, 1991; 56 FR 37022, Aug. 2, 1991; 56 FR 64710, Dec. 12, 1991; 57 FR 
20205, May 12, 1992; 58 FR 34370, June 25, 1993; 58 FR 14484, Mar. 17, 
1993; 58 FR 26069, Apr. 30, 1993; 58 FR 46511, Sept. 1, 1993; 59 FR 
15629, 15633, Apr. 4, 1994; 61 FR 16396, Apr. 15, 1996]



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

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

[[Page 488]]

    (1) The distributor, except as provided in paragraph (g)(3) or 
(g)(8) of this section;
    (2) The carrier (if any), if the carrier caused the gasoline to 
violate the applicable standard;
    (3) The refiner (if he is not an ethanol blender) at whose refinery 
the gasoline was produced or the importer at whose import facility the 
gasoline was imported, except as provided in paragraph (g)(2) of this 
section; and
    (4) The ethanol blender (if any) at whose ethanol blending plant the 
gasoline was produced, except as provided in paragraph (g)(6) or (g)(8) 
of this section.
    (e) Violations at branded retail outlets or wholesale purchaser-
consumer facilities. Where a violation of the applicable standard set 
forth in Sec. 80.27 is detected at a retail outlet or at a wholesale 
purchaser-consumer facility displaying the corporate, trade, or brand 
name of a gasoline refiner or any of its marketing subsidiaries, the 
following parties shall be deemed in violation:
    (1) The retailer or wholesale purchaser-consumer, except as provided 
in paragraph (g)(5) or (g)(8) of this section;
    (2) The distributor and/or reseller (if any), except as provided in 
paragraph (g)(3) or (g)(8) of this section;
    (3) The carrier (if any), if the carrier caused the gasoline to 
violate the applicable standard;
    (4) The refiner whose corporate, trade, or brand name (or that of 
any of its marketing subsidiaries) is displayed at the retail outlet or 
wholesale purchaser-consumer facility, except as provided in paragraph 
(g)(4) of this section; and
    (5) The ethanol blender (if any) at whose ethanol blending plant the 
gasoline was produced, except as provided in paragraph (g)(6) or (g)(8) 
of this section.
    (f) Violations at unbranded retail outlets or wholesale purchaser-
consumer facilities. Where a violation of the applicable standard set 
forth in Sec. 80.27 is detected at a retail outlet or at a wholesale 
purchaser-consumer facility not displaying the corporate, trade, or 
brand name of a refiner or any of its marketing subsidiaries, the 
following parties shall be deemed in violation:
    (1) The retailer or wholesale purchaser-consumer, except as provided 
in paragraph (g)(5) or (g)(8) of this section;
    (2) The distributor (if any), except as provided in paragraph (g)(3) 
or (g)(8) of this section;
    (3) The carrier (if any), if the carrier caused the gasoline to 
violate the applicable standard;
    (4) The ethanol blender (if any) at whose ethanol blending plant the 
gasoline was produced, except as provided in paragraph (g)(6) of this 
section; and
    (5) The refiner (if he is not an ethanol blender) at whose refinery 
the gasoline was produced and/or the importer at whose import facility 
the gasoline was imported, except as provided in paragraph (g)(2) of 
this section.
    (g) Defenses. (1) In any case in which a carrier would be in 
violation under paragraph (b)(1) of this section, the carrier shall not 
be deemed in violation if he can demonstrate:
    (i) That the violation was not caused by him or his employee or 
agent; and
    (ii) Evidence of an oversight program conducted by the carrier, such 
as periodic sampling and testing of incoming gasoline, for monitoring 
the volatility of gasoline stored or transported by that carrier.
    (2) In any case in which a refiner or importer would be in violation 
under paragraphs (b)(2), (d)(3), or (f)(5) of this section, the refiner 
or importer shall not be deemed in violation if he can demonstrate:
    (i) That the violation was not caused by him or his employee or 
agent; and
    (ii) Test results using the sampling and testing methodologies set 
forth in appendices D and E of this part, or any other test method where 
adequate correlation to Method 3 of appendix E of this part is 
demonstrated, which show evidence that the gasoline determined to be in 
violation was in compliance with the applicable standard when it was 
delivered to the next party in the distribution system.
    (3) In any case in which a distributor or reseller would be in 
violation under paragraph (b)(4), (c)(1), (d)(1), (e)(2), or (f)(2) of 
this section, the distributor or reseller shall not be deemed in 
violation if he can demonstrate:

[[Page 489]]

    (i) That the violation was not caused by him or his employee or 
agent; and
    (ii) Evidence of an oversight program conducted by the distributor 
or reseller, such as periodic sampling and testing of gasoline, for 
monitoring the volatility of gasoline that the distributor or reseller 
sells, supplies, offers for sale or supply, or transports.
    (4) In any case in which a refiner would be in violation under 
paragraphs (c)(3) or (e)(4) of this section, the refiner shall not be 
deemed in violation if he can demonstrate all of the following:
    (i) Test results using the sampling and testing methodologies set 
forth in appendices D and E of this part, or any other test method where 
adequate correlation to Method 3 of appendix E of this part is 
demonstrated, which show evidence that the gasoline determined to be in 
violation was in compliance with the applicable standard when 
transported from the refinery.
    (ii) That the violation was not caused by him or his employee or 
agent; and
    (iii) That the violation:
    (A) Was caused by an act in violation of law (other than the Act or 
this part), or an act of sabotage or vandalism, whether or not such acts 
are violations of law in the jurisdiction where the violation of the 
requirements of this part occurred, or
    (B) Was caused by the action of a reseller, an ethanol blender, or a 
retailer supplied by such reseller or ethanol blender, in violation of a 
contractual undertaking imposed by the refiner on such reseller or 
ethanol blender designed to prevent such action, and despite reasonable 
efforts by the refiner (such as periodic sampling and testing) to insure 
compliance with such contractual obligation, or
    (C) Was caused by the action of a retailer who is supplied directly 
by the refiner (and not by a reseller), in violation of a contractual 
undertaking imposed by the refiner on such retailer designed to prevent 
such action, and despite reasonable efforts by the refiner (such as 
periodic sampling and testing) to insure compliance with such 
contractual obligation, or
    (D) Was caused by the action of a distributor or an ethanol blender 
subject to a contract with the refiner for transportation of gasoline 
from a terminal to a distributor, ethanol blender, retailer or wholesale 
purchaser-consumer, in violation of a contractual undertaking imposed by 
the refiner on such distributor or ethanol blender designed to prevent 
such action, and despite reasonable efforts by the refiner (such as 
periodic sampling and testing) to insure compliance with such 
contractual obligation, or
    (E) Was caused by a carrier or other distributor not subject to a 
contract with the refiner but engaged by him for transportation of 
gasoline from a terminal to a distributor, ethanol blender, retailer or 
wholesale purchaser-consumer, despite reasonable efforts by the refiner 
(such as specification or inspection of equipment) to prevent such 
action, or
    (F) Occurred at a wholesale purchaser-consumer facility: Provided, 
however, That if such wholesale purchaser-consumer was supplied by a 
reseller or ethanol blender, the refiner must demonstrate that the 
violation could not have been prevented by such reseller's or ethanol 
blender's compliance with a contractual undertaking imposed by the 
refiner on such reseller or ethanol blender as provided in paragraph 
(g)(4)(iii)(B) of this section.
    (iv) In paragraphs (g)(4)(iii)(A) through (E) of this section, the 
term ``was caused'' means that the refiner must demonstrate by 
reasonably specific showings, by direct or circumstantial evidence, that 
the violation was caused or must have been caused by another.
    (5) In any case in which a retailer or wholesale purchaser-consumer 
would be in violation under paragraphs (e)(1) or (f)(1) of this section, 
the retailer or wholesale purchaser-consumer shall not be deemed in 
violation if he can demonstrate that the violation was not caused by him 
or his employee or agent.
    (6) In any case in which an ethanol blender would be in violation 
under paragraphs (b)(3), (c)(4), (d)(4), (e)(5) or (f)(4) of this 
section, the ethanol blender shall not be deemed in violation if he can 
demonstrate:
    (i) That the violation was not caused by him or his employee or 
agent; and

[[Page 490]]

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

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

[54 FR 11885, Mar. 22, 1989; 54 FR 27017, June 27, 1989, as amended at 
56 FR 64711, Dec. 12, 1991; 58 FR 14484, Mar. 17, 1993]



Sec. 80.29  Controls and prohibitions on diesel fuel quality.

    (a) Prohibited activities. (1) Beginning October 1, 1993, no person, 
including but not limited to, refiners, importers, distributors, 
resellers, carriers, retailers or wholesale purchaser-consumers, shall 
manufacture, introduce into commerce, sell, offer for sale, supply, 
dispense, offer for supply or transport any diesel fuel for use in motor 
vehicles unless the diesel fuel:
    (i) Has a sulfur percentage, by weight, no greater than 0.05 
percent;
    (ii)(A) Has a cetane index of at least 40; or
    (B) Has a maximum aromatic content of 35 volume percent; and
    (iii) Is free of visible evidence of:
    (A) The dye 1,4-dialkylamino-anthraquinone; and
    (B) Beginning October 1, 1994;
    (1) The dye solvent red 164; unless
    (2) It is used in a manner that is tax-exempt as defined under 
section 4082 of the Internal Revenue Code.

[[Page 491]]

    (2) In the case of any diesel fuel not intended for use in motor 
vehicles, no refiner or importer shall add or introduce any amount of 
the dye 1,4-dialkylamino-anthraquinone into such fuel beginning October 
1, 1994.
    (b) Determination of compliance. Any diesel fuel which does not show 
visible evidence of being dyed with either 1,4-dialkylamino-
anthraquinone (which has a characteristic blue-green color in diesel 
fuel) or dye solvent red 164 (which has a characteristic red color in 
diesel fuel) shall be considered to be available for use in diesel motor 
vehicles and motor vehicle engines, and shall be subject to the 
prohibitions of paragraph (a) of this section. Compliance with the 
standards listed in paragraph (a) of this section shall be determined by 
use of one of the sampling methodologies specified in appendix G to this 
part.
    (c) Transfer documents. (1) Any person that transfers custody or 
title of diesel fuel for use in motor vehicles which contains visible 
evidence of the dye solvent red 164 shall provide documents to the 
transferee which state that such fuel meets the applicable standards for 
sulfur and cetane index or aromatic content under these regulations and 
is only for tax-exempt use in diesel motor vehicles as defined under 
section 4082 of the Internal Revenue Code.
    (2) Any person that is the transferor or the transferee of diesel 
fuel for use in motor vehicles which contains visible evidence of the 
dye solvent red 164, shall retain the documents required under paragraph 
(c)(1) of this section for a period of five years from the date of 
transfer of such fuel and shall provide such documents to the 
Administrator or the Administrator's representative upon request.
    (d) Liability. Liability for violations of paragraph (a)(1) of this 
section shall be determined according to the provisions of Sec. 80.30. 
Any person that violates paragraph (a)(2) or (c) of this section shall 
be liable for penalties in accordance with paragraph (e) of this 
section.
    (e) Penalties. Penalties for violations of paragraph (a) or (c) of 
this section shall be determined according to the provisions of 
Sec. 80.5.

[59 FR 35858, July 14, 1994]



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

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

[[Page 492]]

standard by fuel switching, blending, mislabeling, or any other means; 
and
    (3) The refiner or importer at whose refinery or import facility the 
diesel fuel was produced or imported, except as provided in paragraph 
(g)(2) of this section.
    (e) Violations at branded retail outlets or wholesale purchaser-
consumer facilities. Where a violation of a diesel fuel standard set 
forth in Sec. 80.29 is detected at a retail outlet or at a wholesale 
purchaser-consumer facility displaying the corporate, trade, or brand 
name of a refiner or any of its marketing subsidiaries, the following 
parties shall be deemed in violation:
    (1) The retailer or wholesale purchaser-consumer, except as provided 
in paragraph (g)(5) of this section;
    (2) The distributor and/or reseller (if any), except as provided in 
paragraph (g)(3) of this section;
    (3) The carrier (if any), if the carrier caused the diesel fuel to 
violate the standard by fuel switching, blending, mislabeling, or any 
other means; and
    (4) The refiner whose corporate, trade, or brand name, or that of 
any of its marketing subsidiaries, is displayed at the retail outlet or 
wholesale purchaser-consumer facility, except as provided in paragraph 
(g)(4) of this section.
    (f) Violations at unbranded retail outlets or wholesale purchaser-
consumer facilities. Where a violation of a diesel fuel standard set 
forth in Sec. 80.29 is detected at a retail outlet or at a wholesale 
purchaser-consumer facility not displaying the corporate, trade, or 
brand name of a refiner or any of its marketing subsidiaries, the 
following parties shall be deemed in violation:
    (1) The retailer or wholesale purchaser-consumer, except as provided 
in paragraph (g)(5) of this section;
    (2) The distributor (if any), except as provided in paragraph (g)(3) 
of this section;
    (3) The carrier (if any), if the carrier caused the diesel fuel to 
violate the standard by fuel switching, blending, mislabeling, or any 
other means; and
    (4) The refiner or importer at whose refinery or import facility the 
diesel fuel was produced or imported, except as provided in paragraph 
(g)(2) of this section.
    (g) Defenses. (1) In any case in which a carrier would be in 
violation under paragraph (b)(1) of this section, the carrier shall not 
be deemed in violation if he can demonstrate:
    (i) Evidence of an oversight program conducted by the carrier, for 
monitoring the diesel fuel stored or transported by that carrier, such 
as periodic sampling and testing of the cetane index and sulfur 
percentage of incoming diesel fuel, or any other evidence that shows 
that care was taken to avoid blending the diesel fuel with anything 
which would change its cetane index or sulfur percentage; and
    (ii) That the violation was not caused by the carrier or his 
employee or agent.
    (2) In any case in which a refiner or importer would be in violation 
under paragraphs (b)(2), (d)(3), or (f)(4) of this section, the refiner 
or importer shall not be deemed in violation if he can demonstrate:
    (i) That the violation was not caused by him or his employee or 
agent; and
    (ii) Test results, performed in accordance with the sampling and 
testing methodologies set forth in appendix G to this part, ASTM 
standard test method D 2622-87 or ASTM standard test method D 4294-83 
for sulfur percentage (Entitled ``Standard Test Method for Sulfur in 
Petroleum Products by Non-Dispersive X-Ray Fluorescence Spectrometry''. 
ASTM standard test method D 4294-83 is incorporated by reference. This 
incorporation by reference was approved by the Director of the Federal 
Register in accordance with 5 U.S.C. 552(a) and 1 CFR part 51. A copy 
may be obtained from the American Society for Testing and Materials, 
1916 Race Street, Philadelphia, PA 19103. A copy may be inspected at the 
Air Docket Section (A-130), room M-1500, U.S. Environmental Protection 
Agency, Docket No. A-86-03, 401 M Street, SW., Washington, DC 20460 or 
at the Office of the Federal Register, 800 North Capitol Street, NW., 
suite 700, Washington, DC. Parties using this method must be able to 
support their data with a quality control plan and demonstrate the 
ability to accurately perform this test method. They must also have 
evidence from the manufacturer or others that

[[Page 493]]

it reliably produces results substantially equivalent to those produced 
by ASTM standard test method D 2622-87.), and ASTM standard test method 
D 1319-88 for aromatic content or ASTM standard method D 976-80 for 
cetane index, which evidence that the diesel fuel determined to be in 
violation was in compliance with the diesel fuel standards when it was 
delivered to the next party in the distribution scheme.
    (3) In any case in which a distributor or reseller would be in 
violation under paragraphs (c)(1), (d)(1), (e)(2) or (f)(2) of this 
section, the distributor or reseller shall not be deemed in violation if 
he can demonstrate:
    (i) That the violation was not caused by him or his employee or 
agent; and
    (ii) Evidence of an oversight program conducted by the distributor 
or reseller, such as periodic sampling and testing of diesel fuel, for 
monitoring the sulfur percentage and cetane index of the diesel fuel 
that the distributor or reseller sells, supplies, offers for sale or 
supply, or transports.
    (4) In any case in which a refiner would be in violation under 
paragraphs (c)(3) or (e)(4) of this section, the refiner shall not be 
deemed in violation if he can demonstrate all of the following:
    (i) Test results, performed in accordance with the sampling and 
testing methodologies set forth in appendix G to this part, ASTM 
standard test method D 2622-87 or ASTM standard test method D 4294-83 
for sulfur percentage (Parties using ASTM standard test method D 4294-83 
must be able to support their data with a quality control plan and 
demonstrate the ability to accurately perform this test method. They 
must also have evidence from the manufacturer or others that it reliably 
produces results substantially equivalent to those produced by ASTM 
standard test method D 2622-87.) and ASTM standard test method D 1319-88 
for aromatic content or ASTM standard method D 976-80 for cetane index 
at the refinery at which the diesel fuel was produced, which evidence 
that the diesel fuel was in compliance with the diesel fuel standards 
when transported from the refinery;
    (ii) That the violation was not caused by him or his employee or 
agent; and
    (iii) That the violation:
    (A) Was caused by an act in violation of law (other than the Act or 
this part), or an act of sabotage or vandalism, whether or not such acts 
are violations of law in the jurisdiction where the violation of the 
requirements of this part occurred, or
    (B) Was caused by the action of a reseller or a retailer supplied by 
such reseller, in violation of a contractual undertaking imposed by the 
refiner on such reseller designed to prevent such action, and despite 
reasonable efforts by the refiner (such as periodic sampling and 
testing) to insure compliance with such contractual obligation, or
    (C) Was caused by the action of a retailer who is supplied directly 
by the refiner (and not by a reseller), in violation of a contractual 
undertaking imposed by the refiner on such retailer designed to prevent 
such action, and despite reasonable efforts by the refiner (such as 
periodic sampling and testing) to insure compliance with such 
contractual obligation, or
    (D) Was caused by the action of a distributor subject to a contract 
with the refiner for transportation of diesel fuel from a terminal to a 
distributor, retailer or wholesale purchaser-consumer, in violation of a 
contractual undertaking imposed by the refiner on such distributor 
designed to prevent such action, and despite reasonable efforts by the 
refiner (such as periodic sampling and testing) to ensure compliance 
with such contractual obligation, or
    (E) Was caused by a carrier or other distributor not subject to a 
contract with the refiner but engaged by him for transportation of 
diesel fuel from a terminal to a distributor, retailer or wholesale 
purchaser-consumer, despite reasonable efforts by the refiner (such as 
specification or inspection of equipment) to prevent such action, or
    (F) Occurred at a wholesale purchaser-consumer facility: Provided, 
however, That if such wholesale purchaser-consumer was supplied by a 
reseller, the refiner must demonstrate that the violation could not have 
been prevented by such reseller's compliance with a contractual 
undertaking imposed by the refiner on such reseller

[[Page 494]]

as provided in paragraph (g)(4)(iii)(B) of this section.
    (iv) In paragraphs (g)(4)(iii) (A) through (E) of this section, the 
term was caused means that the refiner must demonstrate by reasonably 
specific showings, by direct or circumstantial evidence, that the 
violation was caused or must have been caused by another.
    (5) In any case in which a retailer or wholesale purchaser-consumer 
would be in violation under paragraphs (e)(1) or (f)(1) of this section, 
the retailer or wholesale purchaser-consumer shall not be deemed in 
violation if he can demonstrate that the violation was not caused by him 
or his employee or agent.
    (6) In paragraphs (g)(1)(iii), (g)(2)(i), (g)(3)(i), (g)(4)(ii) and 
(g)(5) of this section, the respective party must demonstrate by 
reasonably specific showings, by direct or circumstantial evidence, that 
it or its employee or agent did not cause the violation.
    (7) In the case of any distributor or reseller that would be in 
violation under paragraph (e)(2) or (f)(2) of this section or any 
wholesale purchaser-consumer or retailer that would be in violation 
under paragraph (e)(1) or (f)(1) of this section for diesel fuel for use 
in motor vehicles which contains visible evidence of the dye solvent red 
164, the distributor or reseller or wholesale purchaser-consumer or 
retailer shall not be deemed in violation if he can:
    (i) Demonstrate that the violation was not caused by him or his 
employee or agent,
    (ii) Demonstrate that the fuel has been supplied, offered for 
supply, transported or available for tax-exempt use as defined under 
section 4082 of the Internal Revenue Code, and
    (iii) Provide evidence from the supplier in the form of 
documentation that the fuel met the applicable standards under paragraph 
(a)(1) of this section for sulfur and cetane index or aromatics content 
for use in motor vehicles.

[55 FR 34138, Aug. 21, 1990, as amended at 59 FR 35859, July 14, 1994]



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

    After January 1, 1998 every retailer and wholesale purchaser- 
consumer handling over 13,660 gallons of liquefied petroleum gas per 
month shall equip each pump from which liquefied petroleum gas is 
introduced into motor vehicles with a nozzle that has no greater than 
2.0 cm3 dead space from which liquefied petroleum gas will be 
released upon nozzle disconnect from the vehicle, as measured from the 
nozzle face which seals against the vehicle receptacle ``O'' ring, and 
as determined by calculation of the geometric shape of the nozzle. After 
January 1, 2000 this requirement applies to every liquefied petroleum 
gas retailer and wholesale purchaser- consumer. Any dispensing pump 
shown to be dedicated to heavy-duty vehicles is exempt from this 
requirement.

[59 FR 48490, Sept. 21, 1994]



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

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

[[Page 495]]

than the cost of additional compression equipment.

[59 FR 48490, Sept. 21, 1994]



                     Subpart C--Oxygenated Gasoline



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

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

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

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

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

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

[57 FR 47771, Oct. 20, 1992]
Sec. Sec. 80.36--80.39  [Reserved]



                    Subpart D--Reformulated Gasoline

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



Sec. 80.40  Fuel certification procedures.

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



Sec. 80.41  Standards and requirements for compliance.

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

                    Simple Model Per-Gallon Standards                   
Reid vapor pressure (in pounds per square inch):                        
  Gasoline designated for VOC-Control Region 1................  X emissions performance reduction (percent).................  X emissions performance reduction (percent):                          
    Standard..................................................  X emissions performance reduction (percent):                          
  Gasoline designated as VOC-controlled.......................  X emissions performance reduction (percent):                          
  Gasoline designated as VOC-controlled:                                
    Standard..................................................  X emissions performance standards for any refinery or 
importer subject to the Phase I complex model standards shall be 
determined by evaluating all of the following parameter levels in the 
Phase I complex model (specified in Sec. 80.45) at one time:
    (1) The simple model values for benzene, RVP, and oxygen specified 
in Sec. 80.41 (a) or (b), as applicable;
    (2) The aromatics value which, together with the values for benzene, 
RVP, and oxygen determined under

[[Page 498]]

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

[[Page 499]]

    (i) The standard for toxics emissions reduction for that covered 
area beginning in the year following this subsequent failure shall be 
made more stringent by increasing the average toxics emissions reduction 
by 1.0%; and
    (ii) The standard for toxics emissions reduction for that covered 
area thereafter shall not be made less stringent regardless of the 
results of subsequent toxics emissions reduction surveys.
    (m) Effect of NOX survey failure. (1) On each occasion that a 
covered area fails a NOX emissions reduction survey conducted 
pursuant to Sec. 80.68, except in the case of Phase II complex model 
NOX standards for VOC-controlled gasoline, the NOX emissions 
reduction requirements for that covered area beginning in the year 
following the failure shall be adjusted to be more stringent as follows:
    (i) The required average NOX emissions reduction shall be 
increased by an additional 1.0%; and
    (ii) The minimum NOX emissions reduction, for each gallon of 
averaged gasoline, shall be increased by an additional 1.0%.
    (2) In the event that a covered area for which required NOX 
emissions reductions have been made more stringent passes all NOX 
emissions reduction surveys in two consecutive years, the averaging 
standards for NOX emissions reduction for that covered area 
beginning in the year following the second year of passed survey series 
shall be made less stringent as follows:
    (i) The required average NOX emissions reduction shall be 
decreased by 1.0%; and
    (ii) The minimum NOX emissions reduction shall be decreased by 
1.0%.
    (3) In the event that a covered area for which the required NOX 
emissions reductions have been made less stringent fails a subsequent 
NOX emissions reduction survey:
    (i) The required average NOX emission reductions for that 
covered area beginning in the year following this subsequent failure 
shall be made more stringent by increasing the required average and the 
minimum NOX emissions reduction by 1.0%; and
    (ii) The required NOX emission reductions for that covered area 
thereafter shall not be made less stringent regardless of the results of 
subsequent NOX emissions reduction surveys.
    (n) Effect of benzene survey failure. (1) On each occasion that a 
covered area fails a benzene content survey series, conducted pursuant 
to Sec. 80.68, the benzene content standards for that covered area 
beginning in the year following the year of the failure shall be made 
more stringent as follows:
    (i) The average benzene content shall be decreased by 0.05% by 
volume; and
    (ii) The maximum benzene content for each gallon of averaged 
gasoline shall be decreased by 0.10% by volume.
    (2) In the event that a covered area for which the benzene standards 
have been made more stringent passes all benzene content survey series 
conducted in two consecutive years, the benzene standards for that 
covered area beginning in the year following the second year of passed 
survey series shall be made less stringent as follows:
    (i) The average benzene content shall be increased by 0.05% by 
volume; and
    (ii) The maximum benzene content for each gallon of averaged 
gasoline shall be increased by 0.10% by volume.
    (3) In the event that a covered area for which the benzene standards 
have been made less stringent fails a subsequent benzene content survey 
series:
    (i) The standards for benzene content for that covered area 
beginning in the year following this subsequent failure shall be the 
more stringent standards which were in effect prior to the operation of 
paragraph (n)(2) of this section; and
    (ii) The standards for benzene content for that covered area 
thereafter shall not be made less stringent regardless of the results of 
subsequent benzene content surveys.
    (o) Effect of oxygen survey failure. (1) In any year that a covered 
area fails an oxygen content survey series, conducted pursuant to 
Sec. 80.68, the minimum oxygen content requirement for that covered area 
beginning in the year following the year of the failure is made more 
stringent by increasing the minimum oxygen content standard, for each 
gallon of averaged gasoline, by an additional 0.1%; however, in no case 
shall the minimum oxygen content standard be greater than 2.0%.

[[Page 500]]

    (2) In the event that a covered area for which the minimum oxygen 
content standard has been made more stringent passes all oxygen content 
survey series in two consecutive years, the minimum oxygen content 
standard for that covered area beginning in the year following the 
second year of passed survey series shall be made less stringent by 
decreasing the minimum oxygen content standard by 0.1%.
    (3) In the event that a covered area for which the minimum oxygen 
content standard has been made less stringent fails a subsequent oxygen 
content survey series:
    (i) The standard for minimum oxygen content for that covered area 
beginning in the year following this subsequent failure shall be made 
more stringent by increasing the minimum oxygen content standard by 
0.1%; and
    (ii) The minimum oxygen content standard for that covered area 
thereafter shall not be made less stringent regardless of the results of 
subsequent oxygen content surveys.
    (p) Effective date for changed minimum or maximum standards. In the 
case of any minimum or maximum standard that is changed to be more 
stringent by operation of paragraphs (k), (m), (n), or (o) of this 
section, the effective date for such change shall be ninety days 
following the date EPA announces the change.
    (q) Refineries, importers, and oxygenate blenders subject to 
adjusted standards. Standards for average compliance that are adjusted 
to be more or less stringent by operation of paragraphs (k), (l), (m), 
(n), or (o) of this section apply to averaged reformulated gasoline 
produced at each refinery or oxygenate blending facility, or imported by 
each importer as follows:
    (1) Adjusted standards for a covered area apply to averaged 
reformulated gasoline that is produced at a refinery or oxygenate 
blending facility if:
    (i) Any averaged reformulated gasoline from that refinery or 
oxygenate blending facility supplied the covered area during any year a 
survey was conducted which gave rise to a standards adjustment; or
    (ii) Any averaged reformulated gasoline from that refinery or 
oxygenate blending facility supplies the covered area during any year 
that the standards are more stringent than the initial standards; unless
    (iii) The refiner or oxygenate blender is able to show that the 
volume of averaged reformulated gasoline from a refinery or oxygenate 
blending facility that supplied the covered area during any year under 
paragraphs (q)(1) (i) or (ii) of this section was less than one percent 
of the reformulated gasoline produced at the refinery or oxygenate 
blending facility during that year, or 100,000 barrels, whichever is 
less.
    (2) Adjusted standards for a covered area apply to averaged 
reformulated gasoline that is imported by an importer if:
    (i) The covered area with the adjusted standard is located in 
Petroleum Administration for Defense District (PADD) I, and the gasoline 
is imported at a facility located in PADDs I, II or III;
    (ii) The covered area with the adjusted standard is located in PADD 
II, and the gasoline is imported at a facility located in PADDs I, II, 
III, or IV;
    (iii) The covered area with the adjusted standard is located in PADD 
III, and the gasoline is imported at a facility located in PADDs II, 
III, or IV;
    (iv) The covered area with the adjusted standard is located in PADD 
IV, and the gasoline is imported at a facility located in PADDs II, or 
IV; or
    (v) The covered area with the adjusted standard is located in PADD 
V, and the gasoline is imported at a facility located in PADDs III, IV, 
or V; unless
    (vi) Any gasoline which is imported by an importer at any facility 
located in any PADD supplies the covered area, in which case the 
adjusted standard also applies to averaged gasoline imported at that 
facility by that importer.
    (3) Any gasoline that is transported in a fungible manner by a 
pipeline, barge, or vessel shall be considered to have supplied each 
covered area that is supplied with any gasoline by that pipeline, or 
barge or vessel shipment, unless the refiner or importer is able to 
establish that the gasoline it produced or imported was supplied only to 
a smaller number of covered areas.

[[Page 501]]

    (4) Adjusted standards apply to all averaged reformulated gasoline 
produced by a refinery or imported by an importer identified in this 
paragraph (q), except:
    (i) In the case of adjusted VOC standards for a covered area located 
in VOC Control Region 1, the adjusted VOC standards apply only to 
averaged reformulated gasoline designated as VOC-controlled intended for 
use in VOC Control Region 1; and
    (ii) In the case of adjusted VOC standards for a covered area 
located in VOC Control Region 2, the adjusted VOC standards apply only 
to averaged reformulated gasoline designated as VOC-controlled intended 
for use in VOC Control Region 2.
    (r) Definition of PADD. For the purposes of this section only, the 
following definitions of PADDs apply:
    (1) The following states are included in PADD I:

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

    (2) The following states are included in PADD II:

Illinois
Indiana
Iowa
Kansas
Kentucky
Michigan
Minnesota
Missouri
Nebraska
North Dakota
Ohio
Oklahoma
South Dakota
Tennessee
Wisconsin

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

Alabama
Arkansas
Louisiana
Mississippi
New Mexico
Texas

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

Colorado
Idaho
Montana
Utah
Wyoming

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

Arizona
California
Nevada
Oregon
Washington

[59 FR 7813, Feb. 16, 1994, as amended at 59 FR 36958, July 20, 1994; 61 
FR 12041, Mar. 25, 1996]



Sec. 80.42  Simple emissions model.

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

Summer=The period of May 1 through September 15
Winter=The period of September 16 through April 30
EXHVOCS1=Exhaust nonmethane, nonethane VOC emissions from the fuel in 
question, in grams per mile, for VOC control region 1 during the summer 
period.
EXHVOCS2=Exhaust nonmethane, nonethane VOC emissions from the fuel in 
question, in grams per mile, for VOC control region 2 during the summer 
period.
EXHVOCW=Exhaust nonmethane, nonethane VOC emissions from the fuel in 
question, in grams per mile, during the winter period.
EVPVOCS1=Evaporative nonmethane, nonethane VOC emissions from the fuel 
in question, in grams per mile, for VOC control region 1 during the 
summer period.
EVPVOCS2=Evaporative nonmethane, nonethane VOC emissions from the fuel 
in question, in grams per mile, for VOC control region 2 during the 
summer period.

[[Page 502]]

RLVOCS1=Running loss nonmethane, nonethane VOC emissions from the fuel 
in question, in grams per mile, for VOC control region 1 during the 
summer period.
RLVOCS2=Running loss nonmethane, nonethane VOC emissions from the fuel 
in question, in grams per mile, for VOC control region 2 during the 
summer period.
REFVOCS1=Refueling nonmethane, nonethane VOC emissions from the fuel in 
question, in grams per mile, for VOC control region 1 during the summer 
period.
REFVOCS2=Refueling nonmethane, nonethane VOC emissions from the fuel in 
question, in grams per mile, for VOC control region 2 during the summer 
period.
OXCON=Oxygen content of the fuel in question, in terms of weight percent 
(as measured under Sec. 80.46)
RVP=Reid vapor pressure of the fuel in question, in pounds per square 
inch (psi)

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

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

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

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

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

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

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

EXHBEN=Exhaust benzene emissions from the fuel in question, in 
milligrams per mile
EVPBEN=Evaporative benzene emissions from the fuel in question, in 
milligrams per mile
HSBEN=Hot soak benzene emissions from the fuel in question, in 
milligrams per mile
DIBEN=Diurnal benzene emissions from the fuel in question, in milligrams 
per mile
RLBEN=Running loss benzene emissions from the fuel in question, in 
milligrams per mile
REFBEN=Refueling benzene emissions from the fuel in question, in 
milligrams per mile
MTBE=Oxygen content of the fuel in question in the form of MTBE, in 
terms of weight percent (as measured under Sec. 80.46)
ETOH=Oxygen content of the fuel in question in the form of ethanol, in 
terms of weight percent (as measured under Sec. 80.46)
ETBE=Oxygen content of the fuel in question in the form of ETBE, in 
terms of weight percent (as measured under Sec. 80.46)
FORM=Formaldehyde emissions from the fuel in question, in milligrams per 
mile
ACET=Acetaldehyde emissions from the fuel in question, in milligrams per 
mile
POM=Emissions of polycyclic organic matter from the fuel in question, in 
milligrams per mile
BUTA=Emissions of 1,3-Butadiene from the fuel in question, in milligrams 
per mile
FBEN=Fuel benzene of the fuel in question, in terms of volume percent 
(as measured under Sec. 80.46)
FAROM=Fuel aromatics of the fuel in question, in terms of volume percent 
(as measured under Sec. 80.46)
TOXREDS1=Total toxics reduction of the fuel in question during the 
summer period for VOC control region 1 in percent
TOXREDS2=Total toxics reduction of the fuel in question during the 
summer period for VOC control region 2 in percent
TOXREDW=Total toxics reduction of the fuel in question during the winter 
period in percent

    (1) The following equations shall comprise the simple model for 
toxics

[[Page 503]]

emissions in VOC control region 1 during the summer period:

TOXREDS1=[100 x (53.2-EXHBEN -EVPBEN-RLBEN-REFBEN -FORM-ACET-BUTA 
-POM)]/53.2
EXHBEN=[1.884+0.949  x  FBEN+0.113  x  (FAROM-FBEN))/100]  x  1000  x  
EXHVOCS1
EVPBEN=HSBEN+DIBEN
HSBEN=FBEN  x  (EVPVOCS1  x  0.679)  x  1000  x  [(1.4448-(0.0684  x  
MTBE/2.0)-(0.080274  x  RVP))/100]
DIBEN=FBEN  x  (EVPVOCS1  x  0.321)  x  1000  x  [(1.3758-(0.0579  x  
MTBE/2.0)-(0.080274  x  RVP))/100]
RLBEN=FBEN  x  RLVOCS1  x  1000  x  [(1.4448-(0.0684  x  MTBE/
2.0)-(0.080274  x  RVP))/100]
REFBEN=FBEN  x  REFVOCS1  x  1000  x  [(1.3972-(0.0591xMTBE/
2.0)-(0.081507  x  RVP))/100] BUTA=0.00556xEXHVOCS1x1000
POM=3.15  x  EXHVOCS1

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

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

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

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

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

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

    (ii) When calculating formaldehyde and acetaldehyde emissions using 
the equations in paragraph (b)(2)(i) of this section, oxygen in the form 
of alcohols which are more complex or have higher molecular weights than 
ethanol shall be evaluated as if it were in the form of ethanol. Oxygen 
in the form of methyl ethers other than TAME and MTBE shall be evaluated 
as if it were in the form of MTBE. Oxygen in the form of ethyl ethers 
other than ETBE shall be evaluated as if it were in the form of ETBE. 
Oxygen in the form of non-methyl, non-ethyl ethers shall be evaluated as 
if it were in the form of ETBE. Oxygen in the form of methanol or non-
alcohol, non-ether oxygenates shall not be evaluated with the Simple 
Model, but instead must be evaluated

[[Page 504]]

through vehicle testing under the Complex Model per Sec. 80.48.
    (3) The following equations shall comprise the simple model for 
toxics emissions during the winter period:

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

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

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

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

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

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

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

    Effective Date Note: At 61 FR 20738, May 8, 1996, Sec. 80.42 was 
amended by revising the table in paragraph (c)(1), effective July 8, 
1996. For the convenience of the user, the superseded text is set forth 
as follows:
Sec. 80.42  Simple emissions model.

                                * * * * *

    (c) * * *
    (1) * * *

------------------------------------------------------------------------
              Fuel parameter                           Range            
------------------------------------------------------------------------
Benzene content..........................  0-4.9 vol %                  
RVP......................................  6.6-9.0 psi                  
Oxygen content...........................  0-4.0 wt %                   
Aromatics content........................  0-55 vol %                   
------------------------------------------------------------------------

                                * * * * *

Secs. 80.43--80.44  [Reserved]



Sec. 80.45  Complex emissions model.

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

Target fuel=The fuel which is being evaluated for its emissions 
performance using the complex model
OXY=Oxygen content of the target fuel in terms of weight percent
SUL=Sulfur content of the target fuel in terms of parts per million by 
weight

[[Page 505]]

RVP=Reid Vapor Pressure of the target fuel in terms of pounds per square 
inch
E200=200  deg.F distillation fraction of the target fuel in terms of 
volume percent
E300=300  deg.F distillation fraction of the target fuel in terms of 
volume percent
ARO=Aromatics content of the target fuel in terms of volume percent
BEN=Benzene content of the target fuel in terms of volume percent
OLE=Olefins content of the target fuel in terms of volume percent
MTB=Methyl tertiary butyl ether content of the target fuel in terms of 
weight percent oxygen
ETB=Ethyl tertiary butyl ether content of the target fuel in terms of 
weight percent oxygen
TAM=Tertiary amyl methyl ether content of the target fuel in terms of 
weight percent oxygen
ETH=Ethanol content of the target fuel in terms of weight percent oxygen
exp=The function that raises the number e (the base of the natural 
logarithm) to the power in its domain
Phase I=The years 1995-1999
Phase II=Year 2000 and beyond

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

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

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

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

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

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


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


[[Page 506]]


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

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

VOCE=VOC(b)+(VOC(b) x Yvoc(t)/100)
Yvoc(t)=[(w1 x Nv)+(w2 x Hv)-1] x 100

where

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

    (i) Consolidated VOC equation for normal emitters.

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

    (ii) VOC equation for higher emitters.

v2=(-0.003626 x OXY) + (-5.40X10-\5\ x SUL) + (0.043295 x RVP) + 
(-0.013504 x E200) + (-0.062327 x E300) + (0.0282042 x ARO) + 
(-0.002858 x OLE) + (0.000106 x E200\2\) + (0.000408 x E300\2\) + 
(-0.000287 x ARO x E300)

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

[[Page 507]]

model presented in paragraph (c)(1)(iv) of this section shall be used.
    (iv) Linear extrapolations. (A) The equations in paragraphs (c)(1) 
(i) and (ii) of this section shall be used within the allowable range of 
E300, E200, and ARO for the appropriate Phase, as defined in Table 6:

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

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

YVOC(t)=100% x 0.52 x [exp(v1(et))/exp(v1(b))-1]
    +100% x 0.48 x [exp(v2(et))/exp(v2(b))-1]
    +{100%-0.52 x [exp(v1(et))/exp(v1(b))]
     x {[(0.0002144 x E200et)- 0.014470] x E200}
    +{[(0.0008174 x E300et)-0.068624
    -(0.000348 x AROet)] x E300}
    +{[(-0.000348 x E300et)+ 0.0323712] x ARO}]}
    +{100% x 0.48 x [exp(v2(et))/exp(v2(b))]
     x [{[(0.000212 x E200et)- 0.01350] x E200}
    +{[(0.000816 x E300et)-0.06233
    -(0.00029 x AROet)] x E300}
    +{[(-0.00029 x E300et)+ 0.028204] x ARO}]}
For Phase II:

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

where

v1, v2=The equations defined in paragraphs (c)(1) (i) and (ii) 
of this section
et=Collection of fuel parameters for the ``edge target'' fuel. These 
parameters are defined in paragraphs (c)(1)(iv)(C) and (D) of this 
section
v1(et)=The function v1 evaluated with ``edge target'' fuel 
parameters, which are defined in paragraphs (c)(1)(iv)(C) and (D) of 
this section
v2(et)=The function v2 evaluated with ``edge target'' fuel 
parameters, which are defined in paragraphs (c)(1)(iv)(C) and (D) of 
this section
v1(b)=The function v1 evaluated with the appropriate baseline 
fuel defined in paragraph (b)(2) of this section
v2(b)=The function v2 evaluated with the appropriate baseline 
fuel defined in paragraph (b)(2) of this section
E200et=The value of E200 for the ``edge target'' fuel, as defined 
in paragraphs (c)(1)(iv)(C) and (D) of this section
E300et=The value of E300 for the ``edge target'' fuel, as defined 
in paragraphs (c)(1)(iv)(C) and (D) of this section
AROet=The value of ARO for the ``edge target'' fuel, as defined in 
paragraphs (c)(1)(iv)(C) and (D) of this section.

    (C) During Phase I, the ``edge target'' fuel shall be identical to 
the target fuel for all fuel parameters, with the following exceptions:
    (1) If the E200 level of the target fuel is less than 33 volume 
percent, then the E200 value for the ``edge target'' fuel shall be set 
equal to 33 volume percent.
    (2) If the aromatics level of the target fuel is less than 18 volume 
percent, then the ARO value for the ``edge target'' fuel shall be set 
equal to 18 volume percent.
    (3) If the aromatics level of the target fuel is greater than 46 
volume percent, then the ARO value for the ``edge target'' fuel shall be 
set equal to 46 volume percent.
    (4) If the E300 level of the target fuel is less than 72 volume 
percent, then the E300 value for the ``edge target'' fuel shall be set 
equal to 72 volume percent.
    (5) If the E300 level of the target fuel is greater than 95 volume 
percent, then

[[Page 508]]

the E300 value of the target fuel shall be set equal to 95 volume 
percent for the purposes of calculating VOC emissions with the Phase I 
equation given in paragraph (c)(1)(iv)(B) of this section.
    (6) If [80.32+(0.390 x ARO)] exceeds 94 for the target fuel, then 
the E300 value for the ``edge target'' fuel shall be set equal to 94 
volume percent.
    (7) If the E200 level of the target fuel is less than 33 volume 
percent, then E200 shall be set equal to (E200-33 volume 
percent).
    (8) If the E200 level of the target fuel equals or exceeds 33 volume 
percent, then E200 shall be set equal to zero.
    (9) If the aromatics level of the target fuel is less than 18 volume 
percent, then ARO shall be set equal to (ARO-18 volume 
percent). If the aromatics level of the target fuel is less than 10 
volume percent, then ARO shall be set equal to -8 volume 
percent.
    (10) If the aromatics level of the target fuel is greater than 46 
volume percent, then ARO shall be set equal to (ARO-46 volume 
percent).
    (11) If neither of the conditions established in paragraphs 
(c)(1)(iv)(C)(9) and (10) of this section are met, then ARO 
shall be set equal to zero.
    (12) If the E300 level of the target fuel is less than 72 percent, 
then E300 shall be set equal to (E300-72 percent).
    (13) If the E300 level of the target fuel is greater than 94 volume 
percent and [80.32+(0.390xARO)] also is greater than 94, then 
E300 shall be set equal to (E300-94 volume percent). If the 
E300 level of the target fuel is greater than 95 volume percent and 
[80.32+(0.390 x ARO)] also is greater than 94, then E300 shall 
be set equal to 1 volume percent.
    (14) If neither of the conditions established in paragraphs 
(c)(1)(iv)(C)(12) and (13) of this section are met, then E300 
shall be set equal to zero.
    (D) During Phase II, the ``edge target'' fuel is identical to the 
target fuel for all fuel parameters, with the following exceptions:
    (1) If the E200 level of the target fuel is less than 33 volume 
percent, then the E200 value for the ``edge target'' fuel shall be set 
equal to 33 volume percent.
    (2) If the aromatics level of the target fuel is less than 18 volume 
percent, then the ARO value for the ``edge target'' fuel shall be set 
equal to 18 volume percent.
    (3) If the aromatics level of the target fuel is greater than 46 
volume percent, then the ARO value for the ``edge target'' fuel shall be 
set equal to 46 volume percent.
    (4) If the E300 level of the target fuel is less than 72 volume 
percent, then the E300 value for the ``edge target'' fuel shall be set 
equal to 72 volume percent.
    (5) If the E300 level of the target fuel is greater than 95 volume 
percent, then the E300 value of the target fuel shall be set equal to 95 
volume percent for the purposes of calculating VOC emissions with the 
Phase II equation given in paragraph (c)(1)(iv)(B) of this section.
    (6) If [79.75+(0.385 x ARO)] exceeds 94 for the target fuel, then 
the E300 value for the ``edge target'' fuel shall be set equal to 94 
volume percent.
    (7) If the E200 level of the target fuel is less than 33 volume 
percent, then E200 shall be set equal to (E200-33 volume 
percent).
    (8) If the E200 level of the target fuel equals or exceeds 33 volume 
percent, then E200 shall be set equal to zero.
    (9) If the aromatics level of the target fuel is less than 18 volume 
percent and greater than or equal to 10 volume percent, then 
ARO shall be set equal to (ARO-18 volume percent). If the 
aromatics level of the target fuel is less than 10 volume percent, then 
ARO shall be set equal to -8 volume percent.
    (10) If the aromatics level of the target fuel is greater than 46 
volume percent, then ARO shall be set equal to (ARO-46 volume 
percent).
    (11) If neither of the conditions established in paragraphs 
(c)(1)(iv)(D)(9) and (10) of this section are met, then ARO 
shall be set equal to zero.
    (12) If the E300 level of the target fuel is less than 72 percent, 
then E300 shall be set equal to (E300) x 72 percent).
    (13) If the E300 level of the target fuel is greater than 94 volume 
percent and [80.32+(0.390 x ARO)] also is greater than 94, then 
E300 shall be set equal to (E300 -94 volume percent). If the 
E300 level of the target fuel is greater than

[[Page 509]]

95 volume percent and [79.75+(0.385 x ARO)] also is greater than 94, 
then E300 shall be set equal to 1 volume percent.
    (14) If neither of the conditions established in paragraphs 
(c)(1)(iv)(D)(12) and (13) of this section are met, then E300 
shall be set equal to zero.
    (2) The winter exhaust VOC emissions performance of gasolines shall 
be given by the equations presented in paragraph (c)(1) of this section 
with the RVP value set to 8.7 psi for both the baseline and target 
fuels.
    (3) The nonexhaust VOC emissions performance of gasolines in VOC 
Control Region 1 shall be given by the following equations, where:

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

    (i) During Phase I:

VOCNE1=VOCDI1+VOCHS1+ VOCRL1+VOCRF1
VOCDI1=[0.00736  x  (RVP\2\)]-[0.0790  x  RVP]+0.2553
VOCHS1=[0.01557  x  (RVP\2\)]-[0.1671  x  RVP]+0.5399
VOCRL1=[0.00279  x  (RVP2)]+[0.1096  x  RVP] -0.7340
VOCRF1=[0.006668  x  RVP]-0.0180

    (ii) During Phase II:

VOCNE1=VOCDI1+VOCHS1+ VOCRL1+VOCRF1
VOCDI1=[0.007385  x  (RVP\2\)]-[0.08981  x  RVP]+0.3158
VOCHS1=[0.006654  x  (RVP2)] -[0.08094  x  RVP]+0.2846
VOCRL1=[0.017768  x  (RVP\2\)]-[0.18746  x  RVP]+0.6146
VOCRF1=[0.004767  x  RVP]+0.011859

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

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

    (i) During Phase I:

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

    (ii) During Phase II:

VOCNE2=VOCDI2+VOCHS2+ VOCRL2+VOCRF2
VOCDI2=[0.004775  x  (RVP\2\)]-[0.05872  x  RVP]+0.21306
VOCHS2=[0.006078  x  (RVP\2\)]-[0.07474  x  RVP]+0.27117
VOCRL2=[0.016169  x  (RVP2)] -[0.17206  x  RVP]+0.56724
VOCRF2=[0.004767  x  RVP]+0.011859

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

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

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

VOCW=(VOCE/1000)

[[Page 510]]

VOCW=Total winter VOC emissions in terms of grams per mile

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

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

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

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

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

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

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

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

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

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

where

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

    (i) Consolidated equation for normal emitters.

n1=(0.0018571 x OXY)+
    (0.0006921 x SUL)
    +(0.0090744 x RVP)+
    (0.0009310 x E200)+
    (0.0008460 x E300)+
    (0.0083632 x ARO)+
    (-0.002774 x OLE)+
    (-6.63X10-7 x SUL\2\)+
    (-0.000119 x ARO\2\)+
    (0.0003665 x OLE\2\)

    (ii) Equation for higher emitters.

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

    (iii) Flat line extrapolations. (A) During Phase I, fuels with 
olefin levels less than 3.77 volume percent shall be evaluated with the 
OLE fuel parameter set

[[Page 511]]

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

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

    (B) For fuels with SUL, OLE, and/or ARO levels outside the ranges 
defined in Table 7 of paragraph (d)(2)(iv)(A) of this section, 
Ynox(t) shall be defined as:

For Phase I:

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

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

where

n1, n2=The equations defined in paragraphs (d)(1) (i) and (ii) 
of this section.
et=Collection of fuel parameters for the ``edge target'' fuel. These 
parameters are defined in paragraphs (d)(1)(iv) (C) and (D) of this 
section.
n1(et)=The function n1 evaluated with ``edge target'' fuel 
parameters, which are defined in paragraph (d)(1)(iv)(C) of this 
section.
n2(et)=The function n2 evaluated with ``edge target'' fuel 
parameters, which are defined in paragraph (d)(1)(iv)(C) of this 
section.
n1(b)=The function n1 evaluated with the appropriate baseline 
fuel parameters defined in paragraph (b)(2) of this section.
n2(b)=The function n2 evaluated with the appropriate baseline 
fuel parameters defined in paragraph (b)(2) of this section.
SULet=The value of SUL for the ``edge target'' fuel, as defined in 
paragraph (d)(1)(iv)(C) of this section.
AROet=The value of ARO for the ``edge target'' fuel, as defined in 
paragraph (d)(1)(iv)(C) of this section.
OLEet=The value of OLE for the ``edge target'' fuel, as defined in 
paragraph (d)(1)(iv)(C) of this section.


[[Page 512]]


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

For Phase I:

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

For Phase II:

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

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

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

where

TOXICS1=Summer toxics performance in VOC Control Region 1 in terms of 
milligrams per mile.
TOXICS2=Summer toxics performance in VOC Control Region 2 in terms of 
milligrams per mile.
EXHBZ=Exhaust emissions of benzene in terms of milligrams per mile, as 
determined in paragraph (e)(4) of this section.
FORM=Emissions of formaldehyde in terms of milligrams per mile, as 
determined in paragraph (e)(5) of this section.

[[Page 513]]

ACET=Emissions of acetaldehyde in terms of milligrams per mile, as 
determined in paragraph (e)(6) of this section.
BUTA=Emissions of 1,3-butadiene in terms of milligrams per mile, as 
determined in paragraph (e)(7) of this section.
POM=Polycyclic organic matter emissions in terms of milligrams per mile, 
as determined in paragraph (e)(8) of this section.
NEBZ1=Nonexhaust emissions of benzene in VOC Control Region 1 in 
milligrams per mile, as determined in paragraph (e)(9) of this section.
NEBZ2=Nonexhaust emissions of benzene in VOC Control Region 2 in 
milligrams per mile, as determined in paragraph (e)(10) of this section.

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

For Phase I:

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

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

where

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

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

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

where

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

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

For Phase I:

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

For Phase II:

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

where

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

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

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

where

EXHBZ=Exhaust benzene emissions in milligrams/mile
YBEN(t)=Benzene performance of target fuel in terms of percentage 
change from baseline.
BENZ(b)=Baseline benzene emissions as defined in paragraph (b)(2) of 
this section for the appropriate phase and season.
Nb=exp b1(t)/exp b1(b)
Hb=exp b2(t)/exp b2(b)
w1=Weighting factor for normal emitters as defined in paragraph

[[Page 514]]

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

    (i) Consolidated equation for normal emitters.
b1=(0.0006197 x SUL) + (-0.003376 x E200)+(0.0265500 x ARO) + 
(0.2223900 x BEN)

    (ii) Equation for higher emitters.
b2=(-0.096047 x OXY) + (0.0003370 x SUL) + (0.0112510 x E300) + 
(0.0118820 x ARO) + (0.2223180 x BEN)

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

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

where

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

    (i) Consolidated equation for normal emitters.

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

    (ii) Equation for higher emitters.

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

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

[[Page 515]]

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

ACET=ACET(b) + (ACET(b) x YACET(t)/100)
YACET(t)=[(w1 x Na) + (w2 x Ha)-1] x 100

where

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

    (i) Consolidated equation for normal emitters.

a1=(0.0002631 x SUL)+ (0.0397860 x RVP) + (-0.012172 x E300) + 
(-0.005525 x ARO) + (-0.009594 x MTB) + (0.3165800 x ETB) + 
(0.2492500 x ETH)

    (ii) Equation for higher emitters.

a2=(0.0002627 x SUL)+ (-0.012157 x E300) + (-0.005548 x ARO) + 
(-0.055980 x MTB) + (0.3164665 x ETB) + (0.2493259 x ETH)

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

BUTA=BUTA(b) + (BUTA(b) x YBUTA(t)/100)
YBUTA(t)=[(w1 x Nd) + (w2 x Hd)-1] x 100

where

BUTA=Exhaust 1,3-butadiene emissions in terms of milligrams/mile
YBUTA(t)=1,3-butadiene performance of target fuel in terms of 
percentage change from baseline
BUTA(b)=Baseline 1,3-butadiene emissions as defined in paragraph (b)(2)

[[Page 516]]

of this section for the appropriate phase and season
Nd=exp d1(t)/exp d1(b)
Hd=exp d2(t)/exp d2(b)
w1=Weighting factor for normal emitters as defined in paragraph 
(b)(1) of this section for the appropriate phase
w2=Weighting factor for higher emitters as defined in paragraph 
(b)(1) of this section for the appropriate Phase.
d1(t)=Normal emitter 1,3-butadiene equation as defined in paragraph 
(e)(7)(i) of this section, evaluated using the target fuel's properties, 
subject to paragraph (e)(7)(iii) of this section.
d2(t)=Higher emitter 1,3-butadiene equation as defined in paragraph 
(e)(7)(ii) of this section, evaluated using the target fuel's 
properties, subject to paragraph (e)(7)(iii) of this section.
d1(b)=Normal emitter 1,3-butadiene equation as defined in paragraph 
(e)(7)(i) of this section, evaluated for the base fuel's properties.
d2(b)=Higher emitter 1,3-butadiene equation as defined in paragraph 
(e)(7)(ii) of this section, evaluated for the base fuel's properties.

    (i) Consolidated equation for normal emitters.

d1=(0.0001552 x SUL)+ (-0.007253 x E200) + (-0.014866 x E300) + 
(-0.004005 x ARO) + (0.0282350 x OLE)

    (ii) Equation for higher emitters.

d2=(-0.060771 x OXY)+ (-0.007311 x E200) + (-0.008058 x E300) + 
(-0.004005 x ARO) + (0.0436960 x OLE)

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

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

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

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

where

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

[[Page 517]]

mile, as determined in paragraph (c)(3) of this section.

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

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

where

NEBZ2=Nonexhaust emissions of volatile organic compounds in VOC Control 
Region 2 in milligrams per mile.
DIBZ2=Diurnal emissions of volatile organic compounds in VOC Control 
Region 2 in milligrams per mile.
HSBZ2=Hot soak emissions of volatile organic compounds in VOC Control 
Region 2 in milligrams per mile.
RLBZ2=Running loss emissions of volatile organic compounds in VOC 
Control Region 2 in milligrams per mile.
RFBZ2=Refueling emissions of volatile organic compounds in VOC Control 
Region 2 in grams per mile.
VOCDI2=Diurnal emissions of volatile organic compounds in VOC Control 
Region 2 in milligrams per mile, as determined in paragraph (c)(4) of 
this section.
VOCHS2=Hot soak emissions of volatile organic compounds in VOC Control 
Region 2 in milligrams per mile, as determined in paragraph (c)(4) of 
this section.
VOCRL2=Running loss emissions of volatile organic compounds in VOC 
Control Region 2 in milligrams per mile, as determined in paragraph 
(c)(4) of this section.
VOCRF2=Refueling emissions of volatile organic compounds in VOC Control 
Region 2 in milligrams per mile, as determined in paragraph (c)(4) of 
this section.

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

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

    (ii) For conventional gasoline:

------------------------------------------------------------------------
            Fuel property                      Acceptable range         
------------------------------------------------------------------------
Oxygen..............................  0.0-4.0 weight percent.           
Sulfur..............................  0.0-1000.0 parts per million by   
                                       weight.                          
RVP.................................  6.4-11.0 pounds per square inch.  
E200................................  30.0-70.0 percent evaporated.     
E300................................  70.0-100.0 percent evaporated.    
Aromatics...........................  0.0-550 volume percent.           
Olefins.............................  0.0-30.0 volume percent.          
Benzene.............................  0.0-4.9 volume percent.           
------------------------------------------------------------------------

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

[59 FR 7813, Feb. 16, 1994, as amended at 59 FR 36959, July 20, 1994]



Sec. 80.46  Measurement of reformulated gasoline fuel parameters.

    (a) Sulfur. Sulfur content shall be determined using American 
Society for Testing and Materials (ASTM) standard method D-2622-92, 
entitled ``Standard Test Method for Sulfur in Petroleum Products by X-
Ray Spectrometry.''
    (b) Olefins. Olefin content shall be determined using ASTM standard 
method D-1319-93, entitled ``Standard Test Method for Hydrocarbon Types 
in Liquid Petroleum Products by Fluorescent Indicator Adsorption.''
    (c) Reid vapor pressure (RVP). Reid Vapor Pressure (RVP) shall be 
determined using the procedure described in 40 CFR part 80, appendix E, 
Method 3.
    (d) Distillation. (1) Distillation parameters shall be determined 
using ASTM standard method D-86-90, entitled ``Standard Test Method for 
Distillation of Petroleum Products''; except that

[[Page 518]]

    (2) The figures for repeatability and reproducibility given in 
degrees Fahrenheit in Table 9 in the ASTM method are incorrect, and 
shall not be used.
    (e) Benzene. (1) Benzene content shall be determined using ASTM 
standard method D-3606-92, entitled ``Standard Test Method for 
Determination of Benzene and Toluene in Finished Motor and Aviation 
Gasoline by Gas Chromatography''; except that
    (2) Instrument parameters must be adjusted to ensure complete 
resolution of the benzene, ethanol and methanol peaks because ethanol 
and methanol may cause interference with ASTM standard method D-3606-92 
when present.
    (f) Aromatics. Aromatics content shall be determined by gas 
chromatography identifying and quantifying each aromatic compound as set 
forth in paragraph (f)(1) of this section.
    (1)(i) Detector. The detector is an atomic mass spectrometer 
detector (MSD). The detector may be set for either selective ion or scan 
mode.
    (ii) Method A. (A) The initial study of this method used a three 
component internal standard using the following calculations.
    (B) The calibration points are constructed by calculating an amount 
ratio and response ratio for each level of a particular peak in the 
instrument's calibration table.
    (C) The amount ratio is the amount of the compound divided by the 
amount of the internal standard for a given level.
    (D) The response ratio is the response of the compound divided by 
the response of the internal standard at this level.
    (E) The equation for the curve through the calibration points is 
calculated using the type fit and origin handling specified in the 
instrument's calibration table. In the initial study the fit was a 
second degree polynomial including a forced zero for the origin.
    (F) The response of the compound in a sample is divided by the 
response of the internal standard to provide a response ratio for that 
compound in the sample.
    (G) A corrected amount ratio for the unknown is calculated using the 
curve fit equation determined in paragragh (f)(1)(ii)(E) of this 
section.
    (H) The amount of the aromatic compound is equal to the corrected 
amount ratio times the Amount of Internal Standard.
    (I) The total aromatics in the sample is the sum of the amounts of 
the individual aromatic compounds in the sample.
    (J) An internal standard solution can be made with the following 
compounds at the listed concentrations in volume percent. Also listed is 
the Chemical Abstracts Service Registry Number (CAS), atomic mass unit 
(amu) on which the detector must be set at the corresponding retention 
time if used in the selective ion mode, retention times in minutes, and 
boiling point in  deg.C. (Other, similar, boiling point materials can be 
used which are not found in gasoline.) Retention times are approximate 
and apply only to a 60 meter capillary column used in the initial study. 
Other columns and retention times can be used.
    (1) 4-methyl-2-pentanone, 50 vol% [108-10-1], 43.0 amu, 22.8 min., 
bp 118;
    (2) benzyl alcohol, 25 vol%, [100-51-6], 108 amu, 61.7 min., bp 205;
    (3) 1-octanol, [111-87-5], 25 vol%, 56.0 amu, 76.6 min., bp 196;
    (K) At least two calibration mixtures which bracket the measured 
total aromatics concentration must be made with a representative mixture 
of aromatic compounds. The materials and concentrations used in the 
highest concentration calibration level in the initial study for this 
method are listed in this paragraph (f)(1)(ii)(K). Also listed is the 
Chemical Abstracts Service Registry Number (CAS), atomic mass unit (amu) 
on which the detector must be set for the corresponding retention time 
if used in the selective ion mode, retention times in minutes, and in 
some cases boiling point in  deg.C. The standards are made in 2,2,4-
trimethylpentane (iso-octane), [540-84-1]. Other aromatic compounds, and 
retention times may be acceptable as long as the aromatic values 
produced meet the criteria found in the quality assurance section for 
the aromatic methods.

[[Page 519]]



----------------------------------------------------------------------------------------------------------------
                                                                                                       Boiling  
           Compound                 Concentration         CAS No.       AMU       Retention time        point,  
                                      (percent)                                                         deg.C   
----------------------------------------------------------------------------------------------------------------
Benzene.......................  2.25 vol............         71-43-2       78  18.9 min............         80.1
Methylbenzene.................  10.0 vol............        108-88-3       91  25.5 min............          111
Ethylbenzene..................  5.0 vol.............        100-41-4       91  34.1 min............        136.2
1,3-Dimethylbenzene...........  5 vol...............        108-38-3       91  35.1 min............      136-138
1,4-Dimethylbenzene...........                              106-42-3                                            
1,2-dimethylbenzene...........  10 vol..............         95-47-6       91  38.1 min............          144
(1-methylethyl)-benzene.......  2.25 vol............         98-82-8      105  42.8 min............  ...........
Propylbenzene.................  2.25 vol............        103-65-1       91  48.0 min............        159.2
1-ethyl-2-methylbenzene.......  2.25 vol............        611-14-3      105  49.3 min............          165
1,2,4-trimethylbenzene........  2.25 vol............         95-63-6      105  50.9 min............          169
1,2,3-trimethylbenzene........  2.25 vol............        526-73-8      105  53.3 min............  ...........
1,3-diethylbenzene............  2.25 vol............        141-93-5      119  56.6 min............          181
Butylbenzene..................  2.25 vol............        104-51-8       91  60.7 min............          183
o-Cymene......................  2.25 vol............        527-84-4      119  63.9 min............  ...........
1-ethyl-3-methylbenzene.......  2.25 vol............        620-14-4      105  64.2 min............  ...........
m-Cymene......................  2.25 vol............        535-77-3      119  69.0 min............  ...........
p-Cymene......................  2.25 vol............         99-87-6      119  73.0 min............  ...........
Isobutylbenzene...............  2.25 vol............        538-93-2       91  75.0 min............  ...........
Indan.........................  2.25 vol............        496-11-7      117  50.0 min............  ...........
1-methyl-3-propylbenzene......  2.25 vol............       1074-43-7      105  78.9 min............  ...........
2-ethyl-1,4-dimethylbenzene...  2.25 vol............       1758-88-9      119  83.2 min............          187
1,2,4,5-tetramethylbenzene....  2.25 vol............         95-93-2      119  83.4 min............  ...........
1-ethyl-2,4-dimethylbenzene...  2.25 vol............        874-41-9      119  85.7 min............  ...........
(1,1-dimethylethyl)-3-          2.25 vol............      27138-21-2      133  87.3 min............  ...........
 methylbenzene.                                                                                                 
1-ethyl-2,3-dimethylbenzene...  2.25 vol............        933-98-2      119  88.7 min............  ...........
1-ethyl-1,4-dimethylbenzene...  2.25 vol............        874-41-9      119  94.9 min............  ...........
2-ethyl-1,3-dimethylbenzene...  2.25 vol............       2870-04-4      119  100.9 min...........  ...........
1-ethyl-3,5-dimethylbenzene...  2.25 vol............        934-74-7      119  102.5 min...........  ...........
1,2,3,5-tetramethylbenzene....  2.25 vol............        527-53-7      119  115.9 min...........  ...........
Pentylbenzene.................  2.25 vol............        538-68-1       91  116 min.............  ...........
Naphthalene...................  2.25 vol............        191-20-3      128  118.4 min...........          198
3,5-dimethyl-t-butylbenzene...  2.25 vol............         98-19-1      147  118.5 min...........        205.3
1-methylnaphthalene...........  2.25 vol............         90-12-0      142  129.0 min...........  ...........
2-methylnaphthalene...........  2.25 vol............         91-57-6      142  131.0 min...........  ...........
----------------------------------------------------------------------------------------------------------------

    (iii) Method B. (A) Use a percent normalized format to determine the 
concentration of the individual compounds. No internal standard is used 
in this method.
    (B) The calculation of the aromatic compounds is done by developing 
calibration curves for each compound using the type fit and origin 
handling specified in the instrument's calibration table.
    (C) The amount of compound in a sample (the corrected amount) is 
calculated using the equation determined in paragraph (f)(1)(ii) of this 
section for that compound.
    (D) The percent normalized amount of a compound is calculated using 
the following equation:
[GRAPHIC] [TIFF OMITTED] TR16FE94.001

where:

An = percent normalized amount of a compound
Ac = corrected amount of the compound
As = sum of all the corrected amounts for all identified compounds 
in the sample

    (E) The total aromatics is the sum of all the percent normalized 
aromatic amounts in the sample.
    (F) This method allows quantification of non-aromatic compounds in 
the sample. However, correct quantification can only be achieved if the 
instrument's calibration table can identify the compounds that are 
responsible for at least 95 volume percent of the sample and meets the 
following quality control criteria.
    (2) Quality assurance. (i) The performance standards will be from 
repeated measurement of the calibration mixture, standard reference 
material, or process control gasoline. The uncertainty in the measured 
aromatics percentages in the standards must be less than 2.0 volume 
percent in the fuel at a 95% confidence level.
    (ii) If the bias of the standard mean is greater than 2% of the 
theoretical value, then the standard measurement

[[Page 520]]

and measurements of all samples measured subsequent to the previous 
standard measurement that met the performance criteria must be repeated 
after re-calibrating the instrument.
    (iii) Replicate samples must be within 3.0 volume percent of the 
previous sample or within 2.0 volume percent of the mean at the 95% 
confidence level.
    (3) Alternative test method. (i) Prior to January 1, 1997, any 
refiner or importer may determine aromatics content using ASTM standard 
method D-1319-93, entitled ``Standard Test Method for Hydrocarbon Types 
in Liquid Petroleum Products by Fluorescent Indicator Adsorption,'' for 
purposes of meeting any testing requirement involving aromatics content; 
provided that
    (ii) The refiner or importer test result is correlated with the 
method specified in paragraph (f)(1) of this section.
    (g) Oxygen and oxygenate content analysis. Oxygen and oxygenate 
content shall be determined by the gas chromatographic procedure using 
an oxygenate flame ionization detector (GC-OFID) as set out in 
paragraphs (g) (1) through (8) of this section.
    (1) Introduction; scope of application.  (i) The following single-
column, direct-injection gas chromatographic procedure is a technique 
for quantifying the oxygenate content of gasoline.
    (ii) This method covers the quantitative determination of the 
oxygenate content of gasoline through the use of an oxygenate flame 
ionization detector (OFID). It is applicable to individual organic 
oxygenated compounds (up to 20 mass percent each) in gasoline having a 
final boiling point not greater than 220  deg.C. Samples above this 
level should be diluted to fall within the specified range.
    (iii) The total concentration of oxygen in the gasoline, due to 
oxygenated components, may also be determined with this method by 
summation of all peak areas except for dissolved oxygen, water, and the 
internal standard. Sensitivities to each component oxygenate must be 
incorporated in the calculation.
    (iv) All oxygenated gasoline components (alcohols, ethers, etc.) may 
be assessed by this method.
    (v) The total mass percent of oxygen in the gasoline due to 
oxygenated components also may be determined with this method by summing 
all peak areas except for dissolved oxygen, water, and the internal 
standard.
    (vi) Where trade names or specific products are noted in the method, 
equivalent apparatus and chemical reagents may be used. Mention of trade 
names or specific products is for the assistance of the user and does 
not constitute endorsement by the U.S. Environmental Protection Agency.
    (2) Summary of method. A sample of gasoline is spiked to introduce 
an internal standard, mixed, and injected into a gas chromatograph (GC) 
equipped with an OFID. After chromatographic resolution the sample 
components enter a cracker reactor in which they are stoichiometrically 
converted to carbon monoxide (in the case of oxygenates), elemental 
carbon, and hydrogen. The carbon monoxide then enters a methanizer 
reactor for conversion to water and methane. Finally, the methane 
generated is determined by a flame ionization detector (FID).
    (3) Sample handling and preservation. (i) Samples shall be collected 
and stored in containers which will protect them from changes in the 
oxygenated component contents of the gasoline, such as loss of volatile 
fractions of the gasoline by evaporation.
    (ii) If samples have been refrigerated they shall be brought to room 
temperature prior to analysis.
    (iii) Gasoline is extremely flammable and should be handled 
cautiously and with adequate ventilation. The vapors are harmful if 
inhaled and prolonged breathing of vapors should be avoided. Skin 
contact should be minimized.
    (4) Apparatus. (i) A GC equipped with an oxygenate flame ionization 
detector.
    (ii) An autosampler for the GC is highly recommended.
    (iii) A 60-m length, 0.25-mm ID, 1.0-m film thickness, 
nonpolar capillary GC column (J&W DB-1 or equivalent) is recommended.
    (iv) An integrator or other acceptable system to collect and process 
the GC signal.
    (v) A positive displacement pipet (200 L) for adding the 
internal standard.

[[Page 521]]

    (5) Reagents and materials. Gasoline and many of the oxygenate 
additives are extremely flammable and may be toxic over prolonged 
exposure. Methanol is particularly hazardous. Persons performing this 
procedure must be familiar with the chemicals involved and all 
precautions applicable to each.
    (i) Reagent grade oxygenates for internal standards and for 
preparation of standard solutions.
    (ii) Supply of oxygenate-free gasoline for blank assessments and for 
preparation of standard solutions.
    (iii) Calibration standard solutions containing known quantities of 
suspected oxygenates in gasoline.
    (iv) Calibration check standard solutions prepared in the same 
manner as the calibration standards.
    (v) Reference standard solutions containing known quantities of 
suspected oxygenates in gasoline.
    (vi) Glass standard and test sample containers (between 5 and 100 Ml 
capacity) fitted with a self-sealing polytetrafluoroethlene (PTFE) faced 
rubber septum crimp-on or screw-down sealing cap for preparation of 
standards and samples.
    (6) Calibration.--(i)(A) Calibration standards of reagent-grade or 
better oxygenates (such as methanol, absolute ethanol, methyl t-butyl 
ether (MTBE), di-i-propyl ether (DIPE), ethyl t-butyl ether (ETBE), and 
t-amyl methyl ether (TAME)) are to be prepared gravimetrically by 
blending with gasoline that has been previously determined by GC/OFID to 
be free of oxygenates. Newly acquired stocks of reagent grade oxygenates 
shall be analyzed for contamination by GC/FID and GC/OFID before use.
    (B) Required calibration standards (percent by volume in gasoline):

------------------------------------------------------------------------
                                                               Number of
                  Oxygenate                         Range      standards
                                                  (percent)    (minimum)
------------------------------------------------------------------------
Methanol.....................................      0.25-12.00          5
Ethanol......................................      0.25-12.00          5
t-Butanol....................................      0.25-12.00          5
MTBE.........................................      0.25-15.00          5
------------------------------------------------------------------------

    (ii) Take a glass sample container and its PTFE faced rubber septum 
sealing cap. Transfer a quantity of an oxygenate to the sample container 
and record the mass of the oxygenate to the nearest 0.1 mg. Repeat this 
process for any additional oxygenates of interest except the internal 
standard. Add oxygenate-free gasoline to dilute the oxygenates to the 
desired concentration. Record the mass of gasoline added to the nearest 
0.1 mg, and determine and label the standard according to the mass 
percent quantities of each oxygenate added. These standards are not to 
exceed 20 mass percent for any individual pure component due to 
potential hydrocarbon breakthrough and/or loss of calibration linearity.
    (iii) Inject a quantity of an internal standard (such as 2-butanol) 
and weigh the contents again. Record the difference in masses as the 
mass of internal standard to the nearest 0.1 mg. The mass of the 
internal standard shall amount to between 2 and 6 percent of the mass of 
the test sample (standard). The addition of an internal standard reduces 
errors caused by variations in injection volumes.
    (iv) Ensure that the prepared standard is thoroughly mixed and 
transfer approximately 2 Ml of the solution to a vial compatible with 
the autosampler if such equipment is used.
    (v) At least five concentrations of each of the expected oxygenates 
should be prepared. The standards should be as equally spaced as 
possible within the range and may contain more than one oxygenate. A 
blank for zero concentration assessments is also to be included. 
Additional standards should be prepared for other oxygenates of concern.
    (vi) Based on the recommended chromatographic operating conditions 
specified in paragraph (g)(7)(i) of this section, determine the 
retention time of each oxygenate component by analyzing dilute aliquots 
either separately or in known mixtures. Reference should be made to the 
Chemical Abstracts Service (CAS) registry number of each of the analytes 
for proper identification. Approximate retention times for selected 
oxygenates under these conditions are as follows:

------------------------------------------------------------------------
                                                               Retention
                  Oxygenate                          CAS          time  
                                                               (minutes)
------------------------------------------------------------------------
Dissolved oxygen.............................       7782-44-7      5.50 
Water........................................       7732-18-5      7.20 

[[Page 522]]

                                                                        
Methanol.....................................         67-56-1      9.10 
Ethanol......................................         64-17-5     12.60 
Propanone....................................         67-64-1     15.00 
2-Propanol...................................         67-63-0     15.70 
t-Butanol....................................         75-65-0     18.00 
n-Propanol...................................         71-23-8     21.10 
MTBE.........................................       1634-04-4     23.80 
2-Butanol....................................      15892-23-6     26.30 
i-Butanol....................................         78-83-1     30.30 
ETBE.........................................        637-92-3     31.10 
n-Butanol....................................         71-36-3     33.50 
TAME.........................................        994-05-8     35.30 
i-Pentanol...................................        137-32-6     38.10 
------------------------------------------------------------------------

    (vii) By GC/OFID analysis, determine the peak area of each oxygenate 
and of the internal standard.
    (viii) Obtain a calibration curve by performing a least-squares fit 
of the relative area response factors of the oxygenate standards to 
their relative mass response factors as follows:

Rao=boRmo+b1(Rmo)2

where:

Rao = relative area response factor of the oxygenate, Ao/
Ai
Rmo = relative mass response factor of the oxygenate, M/
Mi
Ao = area of the oxygenate peak
Ai = area of the internal standard peak
Mo = mass of the oxygenate added to the calibration standard
Mi = mass of internal standard added to the calibration standard
b0 = linear regression coefficient
b1 = quadratic regression coefficient

    (7) Procedure. (i) GC operating conditions:
    (A) Oxygenate-free helium carrier gas: 1.1 Ml/min (2 bar), 22.7 cm/
sec at 115  deg.C;
    (B) Carrier gas split ratio: 1:100;
    (C) Zero air FID fuel: 370 Ml/min (2 bar);
    (D) Oxygenate free hydrogen FID fuel: 15 Ml/min (2 bar);
    (E) Injector temperature: 250  deg.C;
    (F) Injection volume: 0.5 L;
    (G) Cracker reactor temperature: sufficiently high enough 
temperature to ensure reduction of all hydrocarbons to the elemental 
states (i.e., CxH2x -> C + H2, etc.);
    (H) FID temperature: 400  deg.C; and
    (I) Oven temperature program: 40  deg.C for 6 min, followed by a 
temperature increase of 5  deg.C/min to 50  deg.C, hold at 50  deg.C for 
5 min, followed by a temperature increase of 25  deg.C/min to 175 
deg.C, and hold at 175  deg.C for 2 min.
    (ii) Prior to analysis of any samples, inject a sample of oxygenate-
free gasoline into the GC to test for hydrocarbon breakthrough 
overloading the cracker reactor. If breakthrough occurs, the OFID is not 
operating effectively and must be corrected before samples can be 
analyzed.
    (iii) Prepare gasoline test samples for analysis as follows:
    (A) Tare a glass sample container and its PTFE faced rubber septum 
sealing cap. Transfer a quantity of the gasoline sample to the sample 
container and record the mass of the transferred sample to the nearest 
0.1 mg.
    (B) Inject a quantity of the same internal standard (such as 2-
butanol) used in generating the standards and weigh the contents again. 
Record the difference in masses as the mass of internal standard to the 
nearest 0.1 mg. The mass of the internal standard shall amount to 
between 2 and 6 percent of the mass of the test sample (standard). The 
addition of an internal standard reduces errors caused by variations in 
injection volumes.
    (C) Ensure that this test sample (gasoline plus internal standard) 
is thoroughly mixed and transfer approximately 2 mL of the solution to a 
vial compatible with the autosampler if such equipment is used.
    (iv) After GC/OFID analysis, identify the oxygenates in the sample 
based on retention times, determine the peak area of each oxygenate and 
of the internal standard, and calculate the relative area response 
factor for each oxygenate.
    (v) Monitor the peak area of the internal standard. A larger than 
expected peak area for the internal standard when analyzing a test 
sample may indicate that this oxygenate is present in the original 
sample. Prepare a new aliquot of the sample without addition of the 
oxygenate internal standard. If the presence of the oxygenate previously 
used as the internal standard can be detected, then either:
    (A) The concentration of this oxygenate must be assessed by the 
method of standard additions; or

[[Page 523]]

    (B) An alternative internal standard, based on an oxygenate that is 
not present in the original sample, must be utilized with new 
calibration curves.
    (vi) Calculate the relative mass response factor (Rmo) for each 
oxygenate based on the relative area response factor (Rao) and the 
calibration equation in paragraph (g)(6)(viii) of this section.
    (vii) Calculate the mass percent of the oxygenate in the test sample 
according to the following equation:
[GRAPHIC] [TIFF OMITTED] TR16FE94.002

where:

Mo% = mass percent of the oxygenate in the test sample
Ms = mass of sample to which internal standard is added

    (viii) If the mass percent exceeds the calibrated range, 
gravimetrically dilute a portion of the original sample to a 
concentration within the calibration range and analyze this sample 
starting with paragraph (g)(7)(iii) of this section.
    (ix) Report the total weight percent oxygen as follows:
    (A) Subtract the peak areas due to dissolved oxygen, water, and the 
internal standard from the total summed peak areas of the chromatogram.
    (B) Assume the total summed peak area solely due to one of the 
oxygenates that the instrument is calibrated for and determine the total 
mass percent as that oxygenate based on paragraph (g)(7)(vii) of this 
section. For simplicity, chose an oxygenate having one oxygen atom per 
molecule.
    (C) Multiply this concentration by the molar mass of oxygen and 
divide by the molar mass of the chosen oxygenate to determine the mass 
percent oxygen in the sample. For example, if the total peak area is 
based on MTBE, multiply by 16.00 (the molar mass of atomic oxygen) and 
divide by 88.15 (the molar mass of MTBE).
    (x) Sufficient sample should be retained to permit reanalysis.
    (8) Quality control procedures and accuracy. (i) The laboratory 
shall routinely monitor the repeatability (precision) of its analyses. 
The recommendations are:
    (A) The preparation and analysis of laboratory duplicates at a rate 
of one per analysis batch or at least one per ten samples, whichever is 
more frequent.
    (B) Laboratory duplicates shall be carried through all sample 
preparation steps independently.
    (C) The range (R) for duplicate samples should be less than the 
following limits:

------------------------------------------------------------------------
                                  Concentration   Upper limit for range 
            Oxygenate              mass percent        mass percent     
------------------------------------------------------------------------
Methanol........................     0.27-1.07   0.010+0.043C           
Methanol........................    1.07-12.73   0.053C                 
Ethanol.........................    1.01-12.70   0.053C                 
MTBE............................    0.25-15.00   0.069+0.029C           
DIPE............................    0.98-17.70   0.048C                 
ETBE............................    1.00-18.04   0.074C                 
TAME............................    1.04-18.59   0.060C                 
------------------------------------------------------------------------

where:

C=(Co+Cd)/2
Co=concentration of the original sample
Cd=concentration of the duplicate sample
R=Range, |Co-Cd|

    (D) If the limits in paragraph (g)(8)(i)(C) of this section are 
exceeded, the sources of error in the analysis should be determined, 
corrected, and all analyses subsequent to and including the last 
duplicate analysis confirmed to be within the compliance specifications 
must be repeated. The specification limits for the range and relative 
range of duplicate analyses are minimum performance requirements. The 
performance of individual laboratories may indeed be better than these 
minimum requirements. For this reason it is recommended that control 
charts be utilized to monitor the variability of measurements in order 
to optimally detect abnormal situations and ensure a stable measurement 
process.

[[Page 524]]

    (E) (1) For reference purposes, a single laboratory study of 
repeatability was conducted on approximately 27 replicates at each of 
five concentrations for each oxygenate. The variation of MTBE analyses 
as measured by standard deviation was very linear with respect to 
concentration. Where concentration is expressed as mass percent, over 
the concentration range of 0.25 to 15.0 mass percent this relationship 
is described by the equation:

standard deviation=0.00784 x C+0.0187

    (2) The other oxygenates of interest, methanol, ethanol, DIPE, ETBE, 
and TAME, had consistent coefficients of variation at one mass percent 
and above:

------------------------------------------------------------------------
                                                             Coefficient
                                                                  of    
                 Oxygenate                    Concentration   variation 
                                              mass percent    percent of
                                                                point   
------------------------------------------------------------------------
Methanol...................................      1.07-12.73       1.43  
Ethanol....................................      1.01-12.70       1.43  
DIPE.......................................      0.98-17.70       1.29  
ETBE.......................................      1.00-18.04       2.00  
TAME.......................................      1.04-18.59       1.62  
------------------------------------------------------------------------

    (3) The relationship of standard deviation and concentration for 
methanol between 0.27 and 1.07 mass percent was very linear and is 
described by the equation:

standard deviation=0.0118 x C+0.0027

    (4) Based on these relationships, repeatability for the selected 
oxygenates at 2.0 and 2.7 mass percent oxygen were determined to be as 
follows, where repeatability is defined as the half width of the 95 
percent confidence interval (i.e., 1.96 standard deviations) for a 
single analysis at the stated concentration:

----------------------------------------------------------------------------------------------------------------
                                                                            Concentration                       
                                                                  --------------------------------              
                            Oxygenate                                Mass       Mass      Volume   Repeatability
                                                                    percent   percent    percent    mass percent
                                                                    oxygen   oxygenate  oxygenate               
----------------------------------------------------------------------------------------------------------------
Methanol.........................................................      2.0       4.00       3.75         0.11   
Ethanol..........................................................      2.0       5.75       5.41         0.16   
MTBE.............................................................      2.00     11.00      11.00         0.21   
DIPE.............................................................      2.0      12.77      13.00         0.32   
ETBE.............................................................      2.0      12.77      12.74         0.50   
TAME.............................................................      2.0      12.77      12.33         0.41   
Methanol.........................................................      2.7       5.40       5.07         0.15   
Ethanol..........................................................      2.7       7.76       7.31         0.21   
MTBE.............................................................      2.7      14.88      14.88         0.26   
DIPE.............................................................      2.7      17.24      17.53         0.43   
ETBE.............................................................      2.7      17.24      17.20         0.67   
TAME.............................................................      2.7      17.24      16.68         0.55   
----------------------------------------------------------------------------------------------------------------

    (ii) The laboratory shall routinely monitor the accuracy of its 
analyses. The recommendations are:
    (A) Calibration check standards and calibration standards may be 
prepared from the same oxygenate stocks and by the same analyst. 
However, calibration check standards and calibration standards must be 
prepared from separate batches of the final diluted standards. For the 
specification limits listed in paragraph (g)(8)(ii)(C) of this section, 
the concentration of the check standards should be in the range given in 
paragraph (g)(8)(i)(C) of this section.
    (B) Calibration check standards shall be analyzed at a rate of at 
least one per analysis batch and at least one per 10 samples, whichever 
is more frequent.
    (C) If the measured concentration of a calibration check standard is 
outside the range of 100.0% 6.0% of the theoretical 
concentration for a selected oxygenate of 1.0 mass percent or above, the 
sources of error in the analysis should be determined, corrected, and 
all analyses subsequent to and including the last standard analysis 
confirmed to be within the compliance specifications must be repeated. 
The specification limits for the accuracy of calibration check standards 
analyses are minimum performance requirements. The performance of 
individual laboratories may indeed be better than these minimum 
requirements. For this reason it is recommended that control charts be 
utilized to monitor the variability of measurements in order to 
optimally detect abnormal situations and ensure a stable measurement 
process.
    (D) Independent reference standards should be purchased or prepared 
from materials that are independent of the calibration standards and 
calibration check standards, and must not be prepared by the same 
analyst. For the specification limits listed in paragraph (g)(8)(ii)(F) 
of this section, the concentration of the reference standards should be 
in the range given in paragraph (g)(8)(i)(C) of this section.

[[Page 525]]

    (E) Independent reference standards shall be analyzed at a rate of 
at least one per analysis batch and at least one per 100 samples, 
whichever is more frequent.
    (F) If the measured concentration of an independent reference 
standard is outside the range of 100.0% 10.0% of the 
theoretical concentration for a selected oxygenate of 1.0 mass percent 
or above, the sources of error in the analysis should be determined, 
corrected, and all analyses subsequent to and including the last 
independent reference standard analysis confirmed to be within the 
compliance specifications in that batch must be repeated. The 
specification limits for the accuracy of independent reference standards 
analyses are minimum performance requirements. The performance of 
individual laboratories may be better than these minimum requirements. 
For this reason it is recommended that control charts be utilized to 
monitor the variability of measurements in order to optimally detect 
abnormal situations and ensure a stable measurement process.
    (G) The preparation and analysis of spiked samples at a rate of one 
per analysis batch and at least one per ten samples.
    (H) Spiked samples shall be prepared by adding a volume of a 
standard to a known volume of sample. To ensure adequate method 
detection limits, the volume of the standard added to the sample shall 
be limited to 5% or less than the volume of the sample. The spiked 
sample shall be carried through the same sample preparation steps as the 
background sample.
    (I) The percent recovery of the spiked sample shall be calculated as 
follows:
[GRAPHIC] [TIFF OMITTED] TR16FE94.003

where:

Vo=Volume of sample (Ml)
Vl=Volume of spiking standard added (Ml)
Cm=Measured concentration of spiked sample
Co=Measured background concentration of sample
Cs=Known concentration of spiking standard

    (J) If the percent recovery of any individual spiked sample is 
outside the range 100% 10% from the theoretical 
concentration, then the sources of error in the analysis must be 
determined and corrected, and all analyses subsequent to and including 
the last analysis confirmed to be within the compliance specifications 
must be repeated. The maintenance of control charts is one acceptable 
method or ensuring compliance with this specification.
    (K) (1) Either the range (absolute difference) or relative range 
(but not necessarily both) for duplicate samples shall be less than the 
following limits:

------------------------------------------------------------------------
                                                                Relative
                                        Concentration             range 
               Oxygenate                   (volume      Range    (volume
                                           percent)             percent)
------------------------------------------------------------------------
Methanol..............................      1.0-12.0   .......       7.2
Ethanol...............................      3.0-12.0   .......       7.1
t-Butanol.............................      3.0-12.0   .......       9.4
MTBE..................................      3.0-15.0      0.55       9.2
------------------------------------------------------------------------

    (2) Relative range is calculated as follows:
    [GRAPHIC] [TIFF OMITTED] TR16FE94.004
    
where:

Rr=relative range
R=range
Co=concentration of the original sample
Cd=concentration of the duplicate sample

    (3) If the limits in paragraph (g)(8)(ii)(K)(1) of this section are 
exceeded, the sources of error in the analysis should be determined, 
corrected,

[[Page 526]]

and all analyses subsequent to and including the last duplicate analysis 
confirmed to be within the compliance specifications must be repeated. 
The specification limits for the range and relative range of duplicate 
analyses are minimum performance requirements. The performance of 
individual laboratories may indeed be better than these minimum 
requirements. For this reason it is recommended that control charts be 
utilized to monitor the variability of measurements in order to 
optimally detect abnormal situations and ensure a stable measurement 
process. For reference purposes, a single laboratory study of precision 
(approximately 35 replicates) yielded the following estimates of method 
precision:

------------------------------------------------------------------------
                                 Concentration  Repeatability           
           Oxygenate                (weight        (volume     (Percent)
                                    percent)       percent)             
------------------------------------------------------------------------
Methanol.......................          2.0            3.7         0.11
Ethanol........................          2.0            5.4         0.24
t-Butanol......................          2.0            8.8         0.39
MTBE...........................          2.0           11.0         0.37
------------------------------------------------------------------------

    (4) Repeatability is defined as the half width of the 95 percent 
confidence interval for a single analysis at the stated concentration.
    (iii) The laboratory shall routinely monitor the accuracy of its 
analyses. At a minimum this shall include:
    (A) Calibration check standards and calibration standards may be 
prepared from the same oxygenate stocks and by the same analyst. 
However, calibration check standards and calibration standards must be 
prepared from separate batches of the final diluted standards. For the 
specification limits listed in paragraph (g)(8)(iii)(C) of this section, 
the concentration of the check standards should be in the range given in 
paragraph (g)(8)(iii)(C) of this section.
    (B) Calibration check standards shall be analyzed at a rate of one 
per analysis batch or at least one per ten samples, whichever is more 
frequent.
    (C) If the measured concentration of a calibration check standard is 
outside the range of 100%10% percent of the theoretical 
concentration for methanol and ethanol, or 100%13% for t-
butanol and MTBE, the sources of error in the analysis should be 
determined, corrected, and all analyses subsequent to and including the 
last standard analysis confirmed to be within the compliance 
specifications must be repeated. The specification limits for the 
accuracy of calibration check standards analyses are minimum performance 
requirements. The performance of individual laboratories may indeed be 
better than these minimum requirements. For this reason it is 
recommended that control charts be utilized to monitor the variability 
of measurements in order to optimally detect abnormal situations and 
ensure a stable measurement process.
    (D) Independent reference standards shall be purchased or prepared 
from materials that are independent of the calibration standards and 
calibration check standards, and must not be prepared by the same 
analyst. For the specification limits listed in paragraph (g)(8)(iii)(F) 
of this section, the concentration of the reference standards should be 
in the range given in paragraph (g)(8)(iii)(C) of this section.
    (E) Independent reference standards shall be analyzed at a rate of 
one per analysis batch or at least one per 100 samples, whichever is 
more frequent.
    (F) If the measured concentration of an independent reference 
standard is outside the range of 100%10% of the theoretical 
concentration for methanol and ethanol, or 100%13% for t-
butanol and MTBE, the sources of error in the analysis should be 
determined, corrected, and all analyses subsequent to and including the 
last independent reference standard analysis confirmed to be within the 
compliance specifications in that batch must be repeated. The 
specification limits for the accuracy of independent reference standards 
analyses are minimum performance requirements. The performance of 
individual laboratories may indeed be better than these minimum 
requirements. For this reason it is recommended that control charts be 
utilized to monitor the variability of measurements in order to 
optimally detect abnormal situations and ensure a stable measurement 
process.
    (G) If matrix effects are suspected, then spiked samples shall be 
prepared and analyzed as follows:
    (1) Spiked samples shall be prepared by adding a volume of a 
standard to a known volume of sample. To ensure adequate method 
detection limits, the

[[Page 527]]

volume of the standard added to the sample should be minimized to 5% or 
less of the volume of the sample. The spiked sample should be carried 
through the same sample preparation steps as the background sample.
    (2) The percent recovery of spiked samples should be calculated as 
follows:
[GRAPHIC] [TIFF OMITTED] TR16FE94.005

where:

Cc=concentration of spiked sample
Co=concentration of sample without spiking
Cs=known concentration of spiking standard
Vo=volume of sample
Vs=volume of spiking standard added to the sample
    (3) If the percent recovery of a spiked sample is outside the range 
of 100% 13% of the theoretical concentration for methanol 
and ethanol, or 100% 16% for t-butanol and MTBE, the sources 
of error in the analysis should be determined, corrected, and all 
analyses subsequent to and including the last analysis confirmed to be 
within the compliance specifications must be repeated. The specification 
limits for the accuracy of the percent recovery of spiked sample 
analyses are minimum performance requirements. The performance of 
individual laboratories may indeed be better than these minimum 
requirements. For this reason it is recommended that control charts be 
utilized to monitor the variability of measurements in order to 
optimally detect abnormal situations and ensure a stable measurement 
process.
    (9)(i) Prior to January 1, 1997, and when the oxygenates present are 
limited to MTBE, ETBE, TAME, DIPE, tertiary-amyl alcohol, and C1 to 
C4 alcohols, any refiner, importer, or oxygenate blender may 
determine oxygen and oxygenate content using ASTM standard method D-
4815-93, entitled ``Standard Test Method for Determination of MTBE, 
ETBE, TAME, DIPE, tertiary-Amyl Alcohol and C1 to C4 Alcohols 
in Gasoline by Gas Chromatography,'' for purposes of meeting any testing 
requirement; provided that
    (ii) The refiner or importer test result is correlated with the 
method set forth in paragraphs (g)(1) through (g)(8) of this section.
    (h) Incorporations by reference. ASTM standard methods D-3606-92, D-
1319-93, D-4815-93, D-2622-92, and D-86-90 with the exception of the 
degrees Fahrenheit figures in Table 9 of D-86-90, are incorporated by 
reference. These incorporations by reference were approved by the 
Director of the Federal Register in accordance with 5 U.S.C. 552(A) and 
1 CFR part 51. Copies may be obtained from the American Society of 
Testing Materials, 1916 Race Street, Philadelphia, PA 19103. Copies may 
be inspected at the Air Docket Section (LE-131), room M-1500, U.S. 
Environmental Protection Agency, Docket No. A-92-12, 401 M Street SW., 
Washington, DC 20460 or at the Office of the Federal Register, 800 North 
Capitol Street, NW., suite 700, Washington, DC.

[59 FR 7813, Feb. 16, 1994, as amended at 59 FR 36961, July 20, 1994]
Sec. 80.47  [Reserved]



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

    (a) The provisions of this section apply only if a fuel claims 
emission reduction benefits from fuel parameters that are not included 
in the complex emission model or complex emission model database, or if 
the values of fuel parameters included in the complex emission model set 
forth in Sec. 80.45 fall outside the range of values for which the 
complex emission model is deemed valid.
    (b) To augment the complex emission model described at Sec. 80.45, 
the following requirements apply:

[[Page 528]]

    (1) The petitioner must obtain prior approval from the Administrator 
for the design of the test program before beginning the vehicle testing 
process. To obtain approval, the petitioner must at minimum provide the 
following information: the fuel parameter to be evaluated for emission 
effects; the number and description of vehicles to be used in the test 
fleet, including model year, model name, vehicle identification number 
(VIN), mileage, emission performance (exhaust THC emission level), 
technology type, and manufacturer; a description of the methods used to 
procure and prepare the vehicles; the properties of the fuels to be used 
in the testing program (as specified at Sec. 80.49); the pollutants and 
emission categories intended to be evaluated; the precautions used to 
ensure that the effects of the parameter in question are independent of 
the effects of other parameters already included in the model; a 
description of the quality assurance procedures to be used during the 
test program; the statistical analysis techniques to be used in 
analyzing the test data, and the identity and location of the 
organization performing the testing.
    (2) Exhaust emissions shall be measured per the requirements of this 
section and Sec. 80.49 through Sec. 80.62.
    (3) The nonexhaust emission model (including evaporative, running 
loss, and refueling VOC and toxics emissions) shall not be augmented by 
vehicle testing.
    (4) The Agency reserves the right to observe and monitor any testing 
that is performed pursuant to the requirements of this section.
    (5) The Agency reserves the right to evaluate the quality and 
suitability of data submitted pursuant to the requirements of this 
section and to reject, re-analyze, or otherwise evaluate such data as is 
technically warranted.
    (6) Upon a showing satisfactory to the Administrator, the 
Administrator may approve a petition to waive the requirements of this 
section and Sec. 80.49, Sec. 80.50(a), Sec. 80.60(d)(3), and 
Sec. 80.60(d)(4) in order to better optimize the test program to the 
needs of the particular fuel parameter. Any such waiver petition should 
provide information justifying the requested waiver, including an 
acceptable rationale and supporting data. Petitioners must obtain 
approval from the Administrator prior to conducting testing for which 
the requirements in question are waived. The Administrator may waive the 
noted requirements in whole or in part, and may impose appropriate 
conditions on any such waiver.
    (c) In the case of petitions to augment the complex model defined at 
Sec. 80.45 with a new parameter, the effect of the parameter being 
tested shall be determined separately, for each pollutant and for each 
emitter class category. If the parameter is not included in the complex 
model but is represented in whole or in part by one or more parameters 
included in the model, the petitioner shall be required to demonstrate 
the emission effects of the parameter in question independent of the 
effects of the already-included parameters. The petitioner shall also 
have to demonstrate the effects of the already-included parameters 
independent of the effects of the parameter in question. The emission 
performance of each vehicle on the fuels specified at Sec. 80.49, as 
measured through vehicle testing in accordance with Sec. 80.50 through 
Sec. 80.62, shall be analyzed to determine the effects of the fuel 
parameter being tested on emissions according to the following 
procedure:
    (1) The analysis shall fit a regression model to the natural 
logarithm of emissions measured from addition fuels 1, 2, and 3 only (as 
specified at Sec. 80.49(a) and adjusted as per paragraph (c)(1)(iv) of 
this section and Sec. 80.49(d)) that includes the following terms:
    (i) A term for each vehicle that shall reflect the effect of the 
vehicle on emissions independent of fuel compositions. These terms shall 
be of the form Di x Vi, where Di is the coefficient for 
the term and Vi is a dummy variable which shall have the value 1.0 
for the ith vehicle and the value 0 for all other vehicles.
    (ii) A linear term in the parameter being tested for each emitter 
class, of the form Ai x (P1-P1 (avg)) x Ei, where 
Ai is the coefficient for the term, P1 is the level of the 
parameter in question, P1 (avg) is the average level of the 
parameter in question for all seven test fuels specified at 
Sec. 80.49(a)(1), and Ei is a

[[Page 529]]

dummy variable representing emitter class, as defined at Sec. 80.62. For 
normal emitters, E1=1 and E2=0. For higher emitters, E1=0 
and E2=1.
    (iii) For the VOC and NOx models, a squared term in the 
parameter being tested for each emitter class, of the form 
Bi x (P1-P1 (avg))\2\ x Ei, where Bi is the 
coefficient for the term and where P1 , P1 (avg), and Ei 
are as defined in paragraph (c)(1)(ii) of this section.
    (iv) To the extent that the properties of fuels 1, 2, and 3 which 
are incorporated in the complex model differ in value among the three 
fuels, the complex model shall be used to adjust the observed emissions 
from test vehicles on those fuels to compensate for those differences 
prior to fitting the regression model.
    (v) The Ai and Bi terms and coefficients developed by the 
regression described in this paragraph (c) shall be evaluated against 
the statistical criteria defined in paragraph (e) of this section. If 
both terms satisfy these criteria, then both terms shall be retained. If 
the Bi term satisfies these criteria and the Ai term does not, 
then both terms shall be retained. If the Bi term does not satisfy 
these criteria, then the Bi term shall be dropped from the 
regression model and the model shall be re-estimated. If, after dropping 
the Bi term and re-estimating the model, the Ai term does not 
satisfy these criteria, then both terms shall be dropped, all test data 
shall be reported to EPA, and the augmentation request shall be denied.
    (2) After completing the steps outlined in paragraph (c)(1) of this 
section, the analysis shall fit a regression model to a combined data 
set that includes vehicle testing results from all seven addition fuels 
specified at Sec. 80.49(a), the vehicle testing results used to develop 
the model specified at Sec. 80.45, and vehicle testing results used to 
support any prior augmentation requests which the Administrator deems 
necessary.
    (i) The analysis shall fit the regression models described in 
paragraphs (c)(2) (ii) through (v) of this section to the natural 
logarithm of measured emissions.
    (ii) All regressions shall include a term for each vehicle that 
shall reflect the effect of the vehicle on emissions independent of fuel 
compositions. These terms shall be of the form Di x Vi, where 
Di is the coefficient for the term and Vi is a dummy variable 
which shall have the value 1.0 for the ith vehicle and the value 0 for 
all other vehicles. Vehicles shall be represented by separate terms for 
each test program in which they were tested. The vehicle terms for the 
vehicles included in the test program undertaken by the petitioner shall 
be calculated based on the results from all seven fuels specified at 
Sec. 80.49(a). Note that the Di estimates for the petitioner's test 
vehicles in this regression are likely to differ from the Di 
estimates discussed in paragraph (c)(1)(i) of this section since they 
will be based on a different set of fuels.
    (iii) All regressions shall include existing complex model terms and 
their coefficients, including those augmentations that the Administrator 
deems necessary. All terms and coefficients shall be expressed in 
centered form. The Administrator shall make available upon request 
existing complex model terms and coefficients in centered form.
    (iv) All regressions shall include the linear and squared terms, and 
their coefficients, estimated in the final regression model described in 
paragraph (c)(1) of this section.
    (v) The VOC and NOx regressions shall include those interactive 
terms with other fuel parameters, of the form Ci(1, 
j) x (P1-P1 (avg)) x (Pj-Pj (avg)) x Ei, where 
Ci(1, j) is the coefficient for the term, P1 is the level of 
the parameter being added to the model, P1 (avg) is the average 
level of the parameter being added for all seven addition fuels 
specified at Sec. 80.49(a), Pj is the level of the other fuel 
parameter, Pj (avg) is the centering value for the other fuel 
parameter used to develop the complex model or used in the other 
parameter's augmentation study, and Ei is as defined in paragraph 
(c)(1) of this section, which are found to satisfy the statistical 
criteria defined in paragraph (e) of this section. Such terms shall be 
added to the regression model in a stepwise manner.
    (3) The model described in paragraphs (c) (1) and (2) of this 
section shall be developed separately for normal-emitting

[[Page 530]]

and higher-emitting vehicles. Each emitter class shall be treated as a 
distinct population for the purposes of determining regression 
coefficients.
    (4) Once the augmented models described in paragraphs (c) (1) 
through (3) of this section have been developed, they shall be converted 
to an uncentered form through appropriate algebraic manipulation.
    (5) The augmented model described in paragraph (c)(4) of this 
section shall be used to determine the effects of the parameter in 
question at levels between the levels in Fuels 1 and 3, as defined at 
Sec. 80.49(a)(1), for all fuels which claim emission benefits from the 
parameter in question.
    (d)(1) In the case of petitions to augment the complex model defined 
at Sec. 80.45 by extending the range of an existing complex model 
parameter, the effect of the parameter being tested shall be determined 
separately, for each pollutant and for each technology group and emitter 
class category, at levels between the extension level and the nearest 
limit of the core of the data used to develop the unaugmented complex 
model as follows:

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

    (2) The emission performance of each vehicle on the fuels specified 
at Sec. 80.49(b)(2), as measured through vehicle testing in accordance 
with Secs. 80.50 through 80.62, shall be analyzed to determine the 
effects of the fuel parameter being tested on emissions according to the 
following procedure:
    (i) The analysis shall incorporate the vehicle testing data from the 
extension fuels specified at Sec. 80.49(b), the vehicle testing results 
used to develop the model specified at Sec. 80.45, and vehicle testing 
results used to support any prior augmentation requests which the 
Administrator deems necessary. A regression incorporating the following 
terms shall be fitted to the natural logarithm of emissions contained in 
this combined data set:
    (A) A term for each vehicle that shall reflect the effect of the 
vehicle on emissions independent of fuel compositions. These terms shall 
be of the form Di x Vi, where Di is the coefficient for 
the term and Vi is a dummy variable which shall have the value 1.0 
for the ith vehicle and the value 0 for all other vehicles. Vehicles 
shall be represented by separate terms for each test program in which 
they were tested. The vehicle terms for the vehicles included in the 
test program undertaken by the petitioner shall be calculated based on 
the results from all three fuels specified at Sec. 80.49(b)(2).
    (B) Existing complex model terms that do not include the parameter 
being extended and their coefficients, including those augmentations 
that the Administrator deems necessary. The centering values for these 
terms shall be identical to the centering values used to develop the 
complex model described at Sec. 80.45.
    (C) Existing complex model terms that include the parameter being 
extended. The coefficients for these terms shall be estimated by the 
regression. The centering values for these terms shall be identical to 
the centering values used to develop the complex model described at 
Sec. 80.45.
    (D) If the unaugmented VOC or NOx complex models do not contain 
a squared term for the parameter being extended, such a term should be 
added in a stepwise fashion after completing the model described in 
paragraphs (d)(2)(i)(A) through (C) of this section. The coefficient for 
this term shall be estimated by the regression. The centering value for 
this term shall be identical to the centering value used to develop the 
complex model described at Sec. 80.45.
    (E) The terms defined in paragraphs (d)(2)(i)(C) and (D) of this 
section shall be evaluated against the statistical criteria defined in 
paragraph (e) of this section.
    (ii) The model described in paragraph (d)(2)(i) of this section 
shall be developed separately for normal-emitting and higher-emitting 
vehicles, as defined at Sec. 80.62. Each emitter class shall

[[Page 531]]

be treated as a distinct population for the purposes of determining 
regression coefficients.
    (e) Statistical criteria. (1) The petitioner shall be required to 
submit evidence with the petition which demonstrates the statistical 
validity of the regression described in paragraph (c) or (d) of this 
section, including at minimum:
    (i) Evidence demonstrating that colinearity problems are not severe, 
including but not limited to variance inflation statistics of less than 
10 for the second-order and interactive terms included in the regression 
model.
    (ii) Evidence demonstrating that the regression residuals are 
normally distributed, including but not limited to the skewness and 
Kurtosis statistics for the residuals.
    (iii) Evidence demonstrating that overfitting and underfitting risks 
have been balanced, including but not limited to the use of Mallow's 
Cp criterion.
    (2) The petitioner shall be required to submit evidence with the 
petition which demonstrates that the appropriate terms have been 
included in the regression, including at minimum:
    (i) Descriptions of the analysis methods used to develop the 
regressions, including any computer code used to analyze emissions data 
and the results of regression runs used to develop the proposed 
augmentation, including intermediate regressions produced during the 
stepwise regression process.
    (ii) Evidence demonstrating that the significance level used to 
include terms in the model was equal to 0.90.
    (f) The complex emission model shall be augmented with the results 
of vehicle testing as follows:
    (1) The terms and coefficients determined in paragraph (c) or (d) of 
this section shall be used to supplement the complex emission model 
equation for the corresponding pollutant and emitter category. These 
terms and coefficients shall be weighted to reflect the contribution of 
the emitter category to in-use emissions as shown at Sec. 80.45.
    (2) If the candidate parameter is not included in the unaugmented 
complex model and is not represented in whole or in part by one or more 
parameters included in the model, the modification shall be accomplished 
by adding the terms and coefficients to the complex model equation for 
that pollutant, technology group, and emitter category.
    (3) If the parameter is included in the complex model but is being 
tested at levels beyond the current range of the model, the terms and 
coefficients determined in paragraph (d) of this section shall be used 
to supplement the complex emission model equation for the corresponding 
pollutant.
    (i) The terms and coefficients of the complex model described at 
Sec. 80.45 shall be used to evaluate the emissions performance of fuels 
with levels of the parameter being tested that are within the valid 
range of the model, as defined at Sec. 80.45.
    (ii) The emissions performance of fuels with levels of the parameter 
that are beyond the valid range of the unaugmented model shall be given 
in percentage change terms by 100-[(100+A) x (100+C)/(100+B)], where:
    (A) ``A'' shall be set equal to the percentage change in emissions 
for a fuel with identical fuel property values to the fuel being 
evaluated except for the parameter being extended, which shall be set 
equal to the nearest limit of the data core, using the unaugmented 
complex model.
    (B) ``B'' shall be set equal to the percentage change in emissions 
for the fuel described in paragraph (f)(3)(i) of this section according 
to the augmented complex model.
    (C) ``C'' shall be set equal to the percentage change in emissions 
of the actual fuel being evaluated using the augmented complex model.
    (g) EPA reserves the right to analyze the data generated during 
vehicle testing, to use such analyses to determine the validity of other 
augmentation petitions, and to use such data to update the complex model 
for use in certifying all reformulated gasolines.
    (h) Duration of acceptance of emission effects determined through 
vehicle testing:
    (1) If the Agency does not accept, modify, or reject a particular 
augmentation for inclusion in an updated complex model (performed 
through rulemaking), then the augmentation shall remain in effect until 
the next

[[Page 532]]

update to the complex model takes effect.
    (2) If the Agency does reject or modify a particular augmentation 
for inclusion in an updated complex model, then the augmentation shall 
no longer be able to be used as of the date the updated complex model is 
deemed to take effect, unless the following conditions and limitations 
apply:
    (i) The augmentation in question may continue to be used by those 
fuel suppliers which can prove, to the Administrator's satisfaction, 
that the fuel supplier had already begun producing a fuel utilizing the 
augmentation at the time the revised model is promulgated.
    (ii) The augmentation in question may only be used to evaluate the 
emissions performance of fuels in conjunction with the complex emission 
model in effect as of the date of production of the fuels.
    (iii) The augmentation may only be used for three years of fuel 
production, or a total of five years from the date the augmentation 
first took effect, whichever is shorter.
    (3) The Administrator shall determine when sufficient new 
information on the effects of fuel properties on vehicle emissions has 
been obtained to warrant development of an updated complex model.

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



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

    (a) Seven fuels (hereinafter called the ``addition fuels'') shall be 
tested for the purpose of augmenting the complex emission model with a 
parameter not currently included in the complex emission model. The 
properties of the addition fuels are specified in paragraphs (a) (1) and 
(2) of this section. The addition fuels shall be specified with at least 
the same level of detail and precision as in Sec. 80.43(c), and this 
information must be included in the petition submitted to the 
Administrator requesting augmentation of the complex emission model.
    (1) The seven addition fuels to be tested when augmenting the 
complex model specified at Sec. 80.45 with a new fuel parameter shall 
have the properties specified as follows:

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

    (i) For the purposes of vehicle testing, the ``baseline'' level of 
the parameter shall refer to the level of the parameter in Clean Air Act 
baseline gasoline. The ``candidate'' level of the parameter shall refer 
to the most extreme value of the parameter, relative to baseline levels, 
for which the augmentation shall be valid.
    (ii) If the fuel parameter for which the fuel supplier is 
petitioning EPA to augment the complex emission model (hereinafter 
defined as the ``candidate parameter'') is not specified for Clean Air 
Act summer baseline fuel, then the baseline level for the candidate 
parameter shall be set at the levels found in typical gasoline. This 
level and the justification for this level shall be included in the 
petitioner's submittal to

[[Page 533]]

EPA prior to initiating the test program, and EPA must approve this 
level prior to the start of the program.
    (iii) If the candidate parameter is not specified for Clean Air Act 
summer baseline fuel, and is not present in typical gasoline, its 
baseline level shall be zero.
    (2) The addition fuels shall contain detergent control additives in 
accordance with section 211(l) of the Clean Air Act Amendments of 1990 
and the associated EPA requirements for such additives.
    (3) The addition fuels shall be specified with at least the same 
level of detail and precision as in Sec. 80.43(c), and this information 
shall be included in the petition submitted to the Administrator 
requesting augmentation of the complex emission model.
    (i) Paraffin levels in Fuels 1 and 2 shall be altered from the 
paraffin level in Fuel 3 to compensate for the addition or removal of 
the candidate parameter, if necessary. Paraffin levels in Fuel 4 shall 
be altered from the paraffin level in Fuel 5 to compensate for the 
addition or removal of the candidate parameter, if necessary. Paraffin 
levels in Fuel 6 shall be altered from the paraffin level in Fuel 7 to 
compensate for the addition or removal of the candidate parameter, if 
necessary.
    (ii) Other properties of Fuels 4 and 6 shall not vary from the 
levels for Fuels 5 and 7, respectively, unless such variations are the 
naturally-occurring result of the changes described in paragraphs (a)(1) 
and (2) of this section. Other properties of Fuels 1 and 2 shall not 
vary from the levels for Fuel 3, unless such variations are the 
naturally- occurring result of the changes described in paragraphs 
(a)(1) and (2) of this section.
    (iii) The addition fuels shall be specified with at least the same 
level of detail and precision as defined in paragraph (a)(5)(i) of this 
section, and this information must be included in the petition submitted 
to the Administrator requesting augmentation of the complex emission 
model.
    (4) The properties of the addition fuels shall be within the 
blending tolerances defined in this paragraph (a)(4) relative to the 
values specified in paragraphs (a)(1) and (2) of this section. Fuels 
that do not meet these tolerances shall require the approval of the 
Administrator to be used in vehicle testing to augment the complex 
emission model:

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

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

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

    (ii) The 95% confidence limits for measurements of fuel parameters 
for which emission reduction benefits are claimed and for which 
tolerances are not defined in paragraph (a)(5)(i) of this

[[Page 534]]

section must be within 5% of the mean measured value.
    (iii) Each test must be conducted in the same laboratory in 
accordance with the procedures outlined at Sec. 80.46.
    (b) Three fuels (hereinafter called the ``extension fuels'') shall 
be tested for the purpose of extending the valid range of the complex 
emission model for a parameter currently included in the complex 
emission model. The properties of the extension fuels are specified in 
paragraphs (b)(2) through (4) of this section. The extension fuels shall 
be specified with at least the same level of detail and precision as in 
Sec. 80.43(c), and this information must be included in the petition 
submitted to the Administrator requesting augmentation of the complex 
emission model. Each set of three extension fuels shall be used only to 
extend the range of a single complex model parameter.
    (1) The ``extension level'' shall refer to the level to which the 
parameter being tested is to be extended. The three fuels to be tested 
when extending the range of fuel parameters already included in the 
complex model or a prior augmentation to the complex model shall be 
referred to as ``extension fuels.''
    (2) The composition and properties of the extension fuels shall be 
as described in paragraphs (b)(2) (i) and (ii) of this section.
    (i) The extension fuels shall have the following levels of the 
parameter being extended:

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

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

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

    (3) If the Complex Model for any pollutant includes one or more 
interactive terms involving the parameter being extended, then two 
additional extension fuels shall be required to be tested for each such 
interactive term. These additional extension fuels shall have the 
following properties:
    (i) The parameter being tested shall be present at its extension 
level.
    (ii) The interacting parameter shall be present at the levels 
specified in paragraph (b)(2)(i) of this section for extension Fuels 2 
and 3.
    (iii) All other parameters shall be present at the levels specified 
in paragraph (b)(2)(ii) of this section.
    (4) All extension fuels shall contain detergent control additives in 
accordance with Section 211(l) of the Clean Air Act Amendments of 1990 
and the associated EPA requirements for such additives.
    (c) The addition fuels defined in paragraph (a) of this section and 
the extension fuels defined in paragraph (b) of this section shall meet 
the following requirements for blending and measurement precision:

[[Page 535]]

    (1) The properties of the test and extension fuels shall be within 
the blending tolerances defined in this paragraph (c) relative to the 
values specified in paragraphs (a) and (b) of this section. Fuels that 
do not meet the following tolerances shall require the approval of the 
Administrator to be used in vehicle testing to augment the complex 
emission model:

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

    (2) The extension and addition fuels shall be specified with at 
least the same level of detail and precision as defined in paragraph 
(c)(2)(ii) of this section, and this information must be included in the 
petition submitted to the Administrator requesting augmentation of the 
complex emission model.
    (i) The composition and properties of the addition and extension 
fuels shall be determined by averaging a series of independent tests of 
the properties and compositional factors defined in paragraph (c)(2)(ii) 
of this section as well as any additional properties or compositional 
factors for which emission benefits are claimed.
    (ii) The number of independent tests to be conducted shall be 
sufficiently large to reduce the measurement uncertainty for each 
parameter to a sufficiently small value. At a minimum the 95% confidence 
limits (as calculated using a standard t-test) for each parameter must 
be within the following range of the mean measured value of each 
parameter:

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

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

[[Page 536]]

    (2) Calculate adjustment factors for each addition fuel as follows:
    (i) Adjustment factors shall be calculated using the formula:
    [GRAPHIC] [TIFF OMITTED] TR16FE94.006
    
where
A=the adjustment factor
P(actual)=the performance of the actual fuel used in testing according 
to the complex model
P(nominal)=the performance that would have been achieved by the test 
fuel defined in paragraph (a)(1) of this section according to the 
complex model (as described in paragraph (d)(1) of this section).

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

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



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

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



Sec. 80.51  Vehicle test procedures.

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



Sec. 80.52  Vehicle preconditioning.

    (a) Initial vehicle preconditioning and preconditioning between 
tests with different fuels shall be performed in accordance with the 
``General vehicle handling requirements'' per 40 CFR

[[Page 537]]

86.132-96, up to and including the completion of the hot start exhaust 
test.
    (b) The preconditioning procedure prescribed at 40 CFR 86.132-96 
shall be observed for preconditioning vehicles between tests using the 
same fuel.



Secs. 80.53-80.54  [Reserved]



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

    (a) Sampling for benzene and 1,3-butadiene must be accomplished by 
bag sampling as used for total hydrocarbons determination. This 
procedure is detailed in 40 CFR 86.109.
    (b) Benzene and 1,3-butadiene must be analyzed by gas 
chromatography. Expected values for benzene and 1,3-butadiene in bag 
samples for the baseline fuel are 4.0 ppm and 0.30 ppm respectively. At 
least three standards ranging from at minimum 50% to 150% of these 
expected values must be used to calibrate the detector. An additional 
standard of at most 0.01 ppm must also be measured to determine the 
required limit of quantification as described in paragraph (d) of this 
section.
    (c) The sample injection size used in the chromatograph must be 
sufficient to be above the laboratory determined limit of quantification 
(LOQ) as defined in paragraph (d) of this section for at least one of 
the bag samples. A control chart of the measurements of the standards 
used to determine the response, repeatability, and limit of quantitation 
of the instrumental method for 1,3-butadiene and benzene must be 
reported.
    (d) As in all types of sampling and analysis procedures, good 
laboratory practices must be used. See, Lawrence, Principals of 
Environmental Analysis, 55 Analytical Chemistry 14, at 2210-2218 (1983) 
(copies may be obtained from the publisher, American Chemical Society, 
1155 16th Street NW., Washington, DC 20036). Reporting reproducibility 
control charts and limits of detection measurements are integral 
procedures to assess the validity of the chosen analytical method. The 
repeatability of the test method must be determined by measuring a 
standard periodically during testing and recording the measured values 
on a control chart. The control chart shows the error between the 
measured standard and the prepared standard concentration for the 
periodic testing. The error between the measured standard and the actual 
standard indicates the uncertainty in the analysis. The limit of 
detection (LOD) is determined by repeatedly measuring a blank and a 
standard prepared at a concentration near an assumed value of the limit 
of detection. If the average concentration minus the average of the 
blanks is greater than three standard deviations of these measurements, 
then the limit of detection is at least as low as the prepared standard. 
The limit of quantitation (LOQ) is defined as ten times the standard 
deviation of these measurements. This quantity defines the amount of 
sample required to be measured for a valid analysis.
    (e) Other sampling and analytical techniques will be allowed if they 
can be proven to have equal specificity and equal or better limits of 
quantitation. Data from alternative methods that can be demonstrated to 
have equivalent or superior limits of detection, precision, and accuracy 
may be accepted by the Administrator with individual prior approval.



Sec. 80.56  Measurement methods for formaldehyde and acetaldehyde.

    (a) Formaldehyde and acetaldehyde will be measured by drawing 
exhaust samples from heated lines through either 2,4-
Dinitrophenylhydrazine (DNPH) impregnated cartridges or impingers filled 
with solutions of DNPH in acetonitrile (ACN) as described in 
Secs. 86.109 and 86.140 of this chapter for formaldehyde analysis. 
Diluted exhaust sample volumes must be at least 15 L for impingers 
containing 20 ml of absorbing solution (using more absorbing solution in 
the impinger requires proportionally more gas sample to be taken) and at 
least 4 L for cartridges. As required in Sec. 86.109 of this chapter, 
two impingers or cartridges must be connected in series to detect 
breakthrough of the first impinger or cartridge.
    (b) In addition, sufficient sample must be drawn through the 
collecting cartridges or impingers so that the measured quantity of 
aldehyde is sufficiently greater than the minimum

[[Page 538]]

limit of quantitation of the test method for at least a portion of the 
exhaust test procedure. The limit of quantitation is determined using 
the technique defined in Sec. 80.55(d).
    (c) Each of the impinger samples are quantitatively transferred to a 
25 mL volumetric flask (5 mL more than the sample impinger volume) and 
brought to volume with ACN. The cartridge samples are eluted in reversed 
direction by gravity feed with 6mL of ACN. The eluate is collected in a 
graduated test tube and made up to the 5mL mark with ACN. Both the 
impinger and cartridge samples must be analyzed by HPLC without 
additional sample preparation.
    (d) The analysis of the aldehyde derivatives collected is 
accomplished with a high performance liquid chromatograph (HPLC). 
Standards consisting of the hydrazone derivative of formaldehyde and 
acetaldehyde are used to determine the response, repeatability, and 
limit of quantitation of the HPLC method chosen for acetaldehyde and 
formaldehyde.
    (e) Other sampling and analytical techniques will be allowed if they 
can be proven to have equal specificity and equal or better limits of 
quantitation. Data from alternative methods that can be demonstrated to 
have equivalent or superior limits of detection, precision, and accuracy 
may be accepted by the Administrator with individual prior approval.
Secs. 80.57-80.58  [Reserved]



Sec. 80.59  General test fleet requirements for vehicle testing.

    (a) The test fleet must consist of only 1989-91 MY vehicles which 
are technologically equivalent to 1990 MY vehicles, or of 1986-88 MY 
vehicles for which no changes to the engine or exhaust system that would 
significantly affect emissions have been made through the 1990 model 
year. To be technologically equivalent vehicles at minimum must have 
closed-loop systems and possess adaptive learning.
    (b) No maintenance or replacement of any vehicle component is 
permitted except when necessary to ensure operator safety or as 
specifically permitted in Sec. 80.60 and Sec. 80.61. All vehicle 
maintenance procedures must be reported to the Administrator.
    (c) Each vehicle in the test fleet shall have no fewer than 4,000 
miles of accumulated mileage prior to being included in the test 
program.

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



Sec. 80.60  Test fleet requirements for exhaust emission testing.

    (a) Candidate vehicles which conform to the emission performance 
requirements defined in paragraphs (b) through (d) of this section shall 
be obtained directly from the in-use fleet and tested in their as-
received condition.
    (b) Candidate vehicles for the test fleet must be screened for their 
exhaust VOC emissions in accordance with the provisions in Sec. 80.62.
    (c) On the basis of pretesting pursuant to paragraph (b) of this 
section, the test fleet shall be subdivided into two emitter group sub-
fleets: the normal emitter group and the higher emitter group.
    (1) Each vehicle with an exhaust total hydrocarbon (THC) emissions 
rate which is less than or equal to twice the applicable emissions 
standard shall be placed in the normal emitter group.
    (2) Each vehicle with an exhaust THC emissions rate which is greater 
than two times the applicable emissions standard shall be placed in the 
higher emitter group.
    (d) The test vehicles in each emitter group must conform to the 
requirements of paragraphs (d)(1) through (4) of this section.
    (1) Test vehicles for the normal emitter sub-fleet must be selected 
from the list shown in this paragraph (d)(1). This list is arranged in 
order of descending vehicle priority, such that the order in which 
vehicles are added to the normal emitter sub-fleet must conform to the 
order shown (e.g., a ten-vehicle normal emitter group sub-fleet must 
consist of the first ten vehicles listed in this paragraph (d)(1)). If 
more vehicles are tested than the minimum number of vehicles required 
for the normal emitter sub-fleet, additional vehicles are to be added to 
the fleet in the order specified in this paragraph (d)(1), beginning

[[Page 539]]

with the next vehicle not already included in the group. The vehicles in 
the normal emitter sub-fleet must possess the characteristics indicated 
in the list. If the end of the list is reached in adding vehicles to the 
normal emitter sub-fleet and additional vehicles are desired then they 
shall be added beginning with vehicle number one, and must be added to 
the normal emitter sub-fleet in accordance with the order in Table A:

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


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

Legend:

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

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

[[Page 540]]

Sec. 80.61  [Reserved]



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

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

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

    (1) A candidate vehicle with IM240 test results <0.367 grams THC per 
vehicle mile shall be classified as a normal emitter.
    (2) A candidate vehicle with IM240 test results 0.367 
grams THC per vehicle mile shall be classified as a higher emitter.
Secs. 80.63-80.64  [Reserved]



Sec. 80.65  General requirements for refiners, importers, and oxygenate blenders.

    (a) Date requirements begin. The requirements of this subpart D 
apply to all gasoline produced, imported, transported, stored, sold, or 
dispensed:
    (1) At any location other than retail outlets and wholesale 
purchaser-consumer facilities on or after December 1, 1994; and
    (2) At any location on or after January 1, 1995.
    (b) Certification of gasoline and RBOB. Gasoline or RBOB sold or 
dispensed in a covered area must be certified under Sec. 80.40.
    (c) Standards must be met on either a per-gallon or on an average 
basis. (1) Any refiner or importer, for each batch of reformulated 
gasoline or RBOB it produces or imports, shall meet:
    (i) Those standards and requirements it designated under paragraph 
(d) of this section for per-gallon compliance on a per-gallon basis; and
    (ii) Those standards and requirements it designated under paragraph 
(d) of this section for average compliance on an average basis over the 
applicable averaging period; except that
    (iii) Refiners and importers are not required to meet the oxygen 
standard for RBOB.
    (2) Any oxygenate blender, for each batch of reformulated gasoline 
it produces by blending oxygenate with RBOB shall, subsequent to the 
addition of oxygenate, meet the oxygen standard either per-gallon or 
average over the applicable averaging period.
    (3)(i) For each averaging period, and separately for each parameter 
that may be met either per-gallon or on average, any refiner shall 
designate for each refinery, and any importer or oxygenate blender shall 
designate, its gasoline or RBOB as being subject to the standard 
applicable to that parameter on either a per-gallon or average basis. 
For any specific averaging period and parameter all batches of gasoline 
or RBOB shall be designated as being subject to the per-gallon standard, 
or all batches of gasoline and RBOB shall be designated as being subject 
to the average standard. For any specific averaging period and parameter 
a refiner for a refinery, or any importer or oxygenate blender, may not 
designate certain batches as being subject to the per-gallon standard 
and others as being subject to the average standard.
    (ii) In the event any refiner for a refinery, or any importer or 
oxygenate blender, fails to meet the requirements of paragraph (c)(3)(i) 
of this section and for a specific averaging period and parameter 
designates certain batches as being subject to the per-gallon standard 
and others as being subject to the average standard, all batches 
produced

[[Page 541]]

or imported during the averaging period that were designated as being 
subject to the average standard shall, ab initio, be redesignated as 
being subject to the per- gallon standard. This redesignation shall 
apply regardless of whether the batches in question met or failed to 
meet the per-gallon standard for the parameter in question.
    (d) Designation of gasoline. Any refiner or importer of gasoline 
shall designate the gasoline it produces or imports as follows:
    (1) All gasoline produced or imported shall be properly designated 
as either reformulated or conventional gasoline, or as RBOB.
    (2) All gasoline designated as reformulated or as RBOB shall be 
further properly designated as:
    (i) Either VOC-controlled or not VOC-controlled;
    (ii) In the case of gasoline or RBOB designated as VOC-controlled, 
either intended for use in VOC-Control Region 1 or VOC-Control Region 2 
(as defined in Sec. 80.71);
    (iii) Reformulated gasoline (but not RBOB) must be designated either 
as oxygenated fuels program reformulated gasoline, or not oxygenated 
fuels program reformulated gasoline.
    (A) Gasoline must be designated as oxygenated fuels program 
reformulated gasoline if such gasoline:
    (1) Has an oxygen content that is greater than or equal to 2.0 
weight percent; and
    (2) Arrives at a terminal from which gasoline is dispensed into 
trucks used to deliver gasoline to an oxygenated fuels control area 
within five days prior to the beginning of the oxygenated fuels control 
period for that control area.
    (B) Gasoline may be designated as oxygenated fuels program 
reformulated gasoline if such gasoline has an oxygen content that is 
greater than or equal to 2.0 weight percent, regardless of whether the 
gasoline is intended for use in any oxygenated fuels program control 
area during an oxygenated fuels program control period.
    (iv) For gasoline or RBOB produced, imported, sold, dispensed or 
used during the period January 1, 1995 through December 31, 1997, either 
as being subject to the simple model standards, or to the complex model 
standards;
    (v) For each of the following parameters, either gasoline or RBOB 
which meets the standard applicable to that parameter on a per-gallon 
basis or on average:
    (A) Toxics emissions performance;
    (B) NOX emissions performance in the case of gasoline certified 
using the complex model.
    (C) Benzene content;
    (D) With the exception of RBOB, oxygen content;
    (E) In the case of VOC-controlled gasoline or RBOB certified using 
the simple model, RVP; and
    (F) In the case of VOC-controlled gasoline or RBOB certified using 
the complex model, VOC emissions performance; and
    (vi) In the case of RBOB, as RBOB that may be blended with:
    (A) Any oxygenate;
    (B) Ether only;
    (C) Any renewable oxygenate;
    (D) Renewable ether only;
    (E) Non-VOC controlled renewable ether only.
    (3) Every batch of reformulated or conventional gasoline or RBOB 
produced or imported at each refinery or import facility, or each batch 
of blendstock produced and sold or transferred if blendstock accounting 
is required under Sec. 80.102(e), shall be assigned a number (the 
``batch number''), consisting of the EPA-assigned refiner, importer or 
oxygenate blender registration number, the EPA-assigned facility 
registration number, the last two digits of the year in which the batch 
was produced, and a unique number for the batch, beginning with the 
number one for the first batch produced or imported each calendar year 
and each subsequent batch during the calendar year being assigned the 
next sequential number (e.g., 4321-54321-95-000001, 4321-54321-95-
000002, etc.).
    (e) Determination of properties. (1) Each refiner or importer shall 
determine the value of each of the properties specified in paragraph 
(e)(2)(i) of this section for each batch of reformulated gasoline it 
produces or imports prior to the gasoline leaving the refinery or import 
facility, by collecting and analyzing a representative sample

[[Page 542]]

of gasoline taken from the batch, using the methodologies specified in 
Sec. 80.46. This collection and analysis shall be carried out either by 
the refiner or importer, or by an independent laboratory. A batch of 
simple model reformulated gasoline may be released by the refiner or 
importer prior to the receipt of the refiner's or importer's test 
results except for test results for oxygen and benzene, and RVP in the 
case of VOC-controlled gasoline.
    (2) In the event that the values of any of these properties is 
determined by the refiner or importer and by an independent laboratory 
in conformance with the requirements of paragraph (f) of this section:
    (i) The results of the analyses conducted by the refiner or importer 
for such properties shall be used as the basis for compliance 
determinations unless the absolute value of the differences of the test 
results from the two laboratories is larger than the following values:

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

    (ii) In the event the values from the two laboratories for any 
property fall outside these ranges, the refiner or importer shall use as 
the basis for compliance determinations:
    (A) The larger of the two values for the property, except the 
smaller of the two results shall be used for oxygenates; or
    (B) The refiner shall have the gasoline analyzed for the property at 
one additional independent laboratory. If this second independent 
laboratory obtains a result for the property that is within the range, 
as listed in paragraph (e)(2)(i) of this section, of the refiner's or 
importer's result for this property, then the refiner's or importer's 
result shall be used as the basis for compliance determinations.
    (f) Independent analysis requirement. (1) Any refiner or importer of 
reformulated gasoline or RBOB shall carry out a program of independent 
sample collection and analyses for the reformulated gasoline it produces 
or imports, which meets the requirements of one of the following two 
options:
    (i) Option 1. The refiner or importer shall, for each batch of 
reformulated gasoline or RBOB that is produced or imported, have the 
value for each property specified in paragraph (e)(2)(i) of this section 
determined by an independent laboratory that collects and analyzes a 
representative sample from the batch using the methodologies specified 
in Sec. 80.46.
    (ii) Option 2. The refiner or importer shall have a periodic 
independent testing program carried out for all reformulated gasoline 
produced or imported, which shall consist of the following:
    (A) An independent laboratory shall collect a representative sample 
from each batch of reformulated gasoline that the refiner or importer 
produces or imports;
    (B) EPA will identify up to ten percent of the total number of 
samples collected under paragraph (f)(1)(ii)(A) of this section; and
    (C) The designated independent laboratory shall, for each sample 
identified by EPA under paragraph (f)(1)(ii)(B) of this section, 
determine the value for each property using the methodologies specified 
in Sec. 80.46.
    (2)(i) Any refiner or importer shall designate one independent 
laboratory for each refinery or import facility at which reformulated 
gasoline or RBOB is produced or imported. This independent laboratory 
will collect samples and perform analyses in compliance with the 
requirements of this paragraph (f) of this section.
    (ii) Any refiner or importer shall identify this designated 
independent laboratory to EPA under the registration requirements of 
Sec. 80.76.
    (iii) In order to be considered independent:
    (A) The laboratory shall not be operated by any refiner or importer, 
and

[[Page 543]]

shall not be operated by any subsidiary or employee of any refiner or 
importer;
    (B) The laboratory shall be free from any interest in any refiner or 
importer; and
    (C) The refiner or importer shall be free from any interest in the 
laboratory; however
    (D) Notwithstanding the restrictions in paragraphs (f)(2)(iii) (A) 
through (C) of this section, a laboratory shall be considered 
independent if it is owned or operated by a gasoline pipeline company, 
regardless of ownership or operation of the gasoline pipeline company by 
refiners or importers, provided that such pipeline company is owned and 
operated by four or more refiners or importers.
    (iv) Use of a laboratory that is debarred, suspended, or proposed 
for debarment pursuant to the Governmentwide Debarment and Suspension 
regulations, 40 CFR part 32, or the Debarment, Suspension and 
Ineligibility provisions of the Federal Acquisition Regulations, 48 CFR 
part 9, subpart 9.4, shall be deemed noncompliance with the requirements 
of this paragraph (f).
    (v) Any laboratory that fails to comply with the requirements of 
this paragraph (f) shall be subject to debarment or suspension under 
Governmentwide Debarment and Suspension regulations, 40 CFR part 32, or 
the Debarment, Suspension and Ineligibility regulations, Federal 
Acquisition Regulations, 48 CFR part 9, subpart 9.4.
    (3) Any refiner or importer shall, for all samples collected or 
analyzed pursuant to the requirements of this paragraph (f), cause its 
designated independent laboratory:
    (i) At the time the designated independent laboratory collects a 
representative sample from a batch of reformulated gasoline, to:
    (A) Obtain the refiner's or importer's assigned batch number for the 
batch being sampled;
    (B) Determine the volume of the batch;
    (C) Determine the identification number of the gasoline storage tank 
or tanks in which the batch was stored at the time the sample was 
collected;
    (D) Determine the date and time the batch became finished 
reformulated gasoline, and the date and time the sample was collected;
    (E) Determine the grade of the batch (e.g., premium, mid-grade, or 
regular); and
    (F) In the case of reformulated gasoline produced through computer-
controlled in-line blending, determine the date and time the blending 
process began and the date and time the blending process ended, unless 
exempt under paragraph (f)(4) of this section;
    (ii) To retain each sample collected pursuant to the requirements of 
this paragraph (f) for a period of 30 days, except that this period 
shall be extended to a period of up to 180 days upon request by EPA;
    (iii) To submit to EPA periodic reports, as follows:
    (A) A report for the period January through March shall be submitted 
by May 31; a report for the period April through June shall be submitted 
by August 31; a report for the period July through September shall be 
submitted by November 30; and a report for the period October through 
December shall be submitted by February 28;
    (B) Each report shall include, for each sample of reformulated 
gasoline that was analyzed pursuant to the requirements of this 
paragraph (f):
    (1) The results of the independent laboratory's analyses for each 
property; and
    (2) The information specified in paragraph (f)(3)(i) of this section 
for such sample; and
    (iv) To supply to EPA, upon EPA's request, any sample collected or a 
portion of any such sample.
    (4) Any refiner that produces reformulated gasoline using computer-
controlled in-line blending equipment is exempt from the independent 
sampling and testing requirements specified in paragraphs (f)(1) through 
(3) of this section and from the requirement of paragraph (e)(1) of this 
section to obtain test results for each batch prior to the gasoline 
leaving the refinery, provided that such refiner:
    (i) Obtains from EPA an exemption from these requirements. In order 
to seek such an exemption, the refiner shall submit a petition to EPA, 
such petition to include:

[[Page 544]]

    (A) A description of the refiner's computer-controlled in-line 
blending operation, including a description of:
    (1) The location of the operation;
    (2) The length of time the refiner has used the operation;
    (3) The volumes of gasoline produced using the operation since the 
refiner began the operation or during the previous three years, 
whichever is shorter, by grade;
    (4) The movement of the gasoline produced using the operation to the 
point of fungible mixing, including any points where all or portions of 
the gasoline produced is accumulated in gasoline storage tanks;
    (5) The physical lay-out of the operation;
    (6) The automated control system, including the method of monitoring 
and controlling blend properties and proportions;
    (7) Any sampling and analysis of gasoline that is conducted as a 
part of the operation, including on-line, off-line, and composite, and a 
description of the methods of sampling, the methods of analysis, the 
parameters analyzed and the frequency of such analyses, and any written, 
printed, or computer-stored results of such analyses, including 
information on the retention of such results;
    (8) Any sampling and analysis of gasoline produced by the operation 
that occurs downstream from the blending operation prior to fungible 
mixing of the gasoline, including any such sampling and analysis by the 
refiner and by any purchaser, pipeline or other carrier, or by 
independent laboratories;
    (9) Any quality assurance procedures that are carried out over the 
operation; and
    (10) Any occasion(s) during the previous three years when the 
refiner adjusted any physical or chemical property of any gasoline 
produced using the operation downstream from the operation, including 
the nature of the adjustment and the reason the gasoline had properties 
that required adjustment; and
    (B) A description of the independent audit program of the refiner's 
computer-controlled in-line blending operation that the refiner proposes 
will satisfy the requirements of this paragraph (f)(4); and
    (ii) Carries out an independent audit program of the refiner's 
computer-controlled in-line blending operation, such program to include:
    (A) For each batch of reformulated gasoline produced using the 
operation, a review of the documents generated that is sufficient to 
determine the properties and volume of the gasoline produced;
    (B) Audits that occur no less frequently than annually;
    (C) Reports of the results of such audits submitted to the refiner, 
and to EPA by the auditor no later than February 28 of each year;
    (D) Audits that are conducted by an auditor that meets the non-
debarred criteria specified in Sec. 80.125 (a) and/or (d); and
    (iii) Complies with any other requirements that EPA includes as part 
of the exemption.
    (g) Marking of conventional gasoline. [Reserved]
    (h) Compliance audits. Any refiner and importer of any reformulated 
gasoline or RBOB, and any oxygenate blender of any RBOB who meets the 
oxygen standard on average, shall have the reformulated gasoline and 
RBOB it produced, imported, or blended during each calendar year audited 
for compliance with the requirements of this subpart D, in accordance 
with the requirements of subpart F, at the conclusion of each calendar 
year.
    (i) Exclusion from compliance calculations of gasoline received from 
others. Any refiner for each refinery, any oxygenate blender for each 
oxygenate blending facility, and any importer shall exclude from all 
compliance calculations the volume and properties of any reformulated 
gasoline that is produced at another refinery or oxygenate blending 
facility or imported by another importer.

[59 FR 7813, Feb. 16, 1994, as amended at 59 FR 36962, July 20, 1994; 59 
FR 39289, Aug. 2, 1994; 59 FR 60715, Nov. 28, 1994]

    Effective Date Note: At 59 FR 39289, Aug. 2, 1994, Sec. 80.65 was 
amended by revising paragraph (d)(2)(vi) effective September 1, 1994. At 
59 FR 60715, Nov. 28, 1994, the amendment was stayed effective September 
13, 1994.

[[Page 545]]



Sec. 80.66  Calculation of reformulated gasoline properties.

    (a) All volume measurements required by these regulations shall be 
temperature adjusted to 60 degrees Fahrenheit.
    (b) The percentage of oxygen by weight contained in a gasoline 
blend, based upon its percentage oxygenate by volume and density, shall 
exclude denaturants and water.
    (c) The properties of reformulated gasoline consist of per-gallon 
values separately and individually determined on a batch-by-batch basis 
using the methodologies specified in Sec. 80.46 for each of those 
physical and chemical parameters necessary to determine compliance with 
the standards to which the gasoline is subject, and per-gallon values 
for the VOC, NOX, and toxics emissions performance standards to 
which the gasoline is subject.
    (d) Per-gallon oxygen content shall be determined based upon the 
weight percent oxygen of a representative sample of gasoline, using the 
method set forth in Sec. 80.46(g). The total oxygen content associated 
with a batch of gasoline (in percent-gallons) is calculated by 
multiplying the weight percent oxygen content times the volume.
    (e) Per-gallon benzene content shall be determined based upon the 
volume percent benzene of a representative sample of a batch of gasoline 
by the method set forth in Sec. 80.46(e). The total benzene content 
associated with a batch of gasoline (in percent-gallons) is calculated 
by multiplying the volume percent benzene content times the volume.
    (f) Per-gallon RVP shall be determined based upon the measurement of 
RVP of a representative sample of a batch of gasoline by the sampling 
methodologies specified in Appendix D of this part and the testing 
methodology specified in Appendix E of this part. The total RVP value 
associated with a batch of gasoline (in RVP-gallons) is calculated by 
multiplying the RVP times the volume.
    (g)(1) Per gallon values for VOC and NOX emissions reduction 
shall be calculated using the methodology specified in Sec. 80.45 that 
is appropriate for the gasoline.
    (2) Per-gallon values for toxic emissions performance reduction 
shall be established using:
    (i) For gasoline subject to the simple model, the methodology under 
Sec. 80.42 that is appropriate for the gasoline; and
    (ii) For gasoline subject to the complex model, the methodology 
specified in Sec. 80.45 that is appropriate for the gasoline.
    (3) The total VOC, NOX, and toxic emissions performance 
reduction values associated with a batch of gasoline (in percent 
reduction-gallons) is calculated by multiplying the per-gallon percent 
emissions performance reduction times the volume of the batch.

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



Sec. 80.67  Compliance on average.

    The requirements of this section apply to all reformulated gasoline 
and RBOB produced or imported for which compliance with one or more of 
the requirements of Sec. 80.41 is determined on average (``averaged 
gasoline'').
    (a) Compliance survey required in order to meet standards on 
average. (1) Any refiner, importer, or oxygenate blender that complies 
with the compliance survey requirements of Sec. 80.68 has the option of 
meeting the standards specified in Sec. 80.41 for average compliance in 
addition to the option of meeting the standards specified in Sec. 80.41 
for per-gallon compliance; any refiner, importer, or oxygenate blender 
that does not comply with the survey requirements must meet the 
standards specified in Sec. 80.41 for per-gallon compliance, and does 
not have the option of meeting standards on average.
    (2)(i)(A) A refiner or importer that produces or imports 
reformulated gasoline that exceeds the average standards for oxygen or 
benzene (but not for other parameters that have average standards) may 
use such gasoline to offset reformulated gasoline which does not achieve 
such average standards, but only if the reformulated gasoline that does 
not achieve such average standards is sold to ultimate consumers in the 
same covered area as was the reformulated gasoline which exceeds average 
standards; provided that

[[Page 546]]

    (B) Prior to the beginning of the averaging period when the 
averaging approach described in paragraph (a)(2)(i)(A) of this section 
is used, the refiner or importer obtains approval from EPA. In order to 
seek such approval, the refiner or importer shall submit a petition to 
EPA, such petition to include:
    (1) The identification of the refiner and refinery, or importer, the 
covered area, and the averaging period; and
    (2) A detailed description of the procedures the refiner or importer 
will use to ensure the gasoline is produced by the refiner or is 
imported by the importer and is used only in the covered area in 
question and is not used in any other covered area, and the record 
keeping, reporting, auditing, and other quality assurance measures that 
will be followed to establish the gasoline is used as intended; and
    (C) The refiner or importer properly completes any requirements that 
are specified by EPA as conditions for approval of the petition.
    (ii) Any refiner or importer that meets the requirements of 
paragraph (a)(2)(i) of this section will be deemed to have satisfied the 
compliance survey requirements of Sec. 80.68 for the covered area in 
question.
    (b) Scope of averaging. (1) Any refiner shall meet all applicable 
averaged standards separately for each of the refiner's refineries;
    (2)(i) Any importer shall meet all applicable averaged standards on 
the basis of all averaged reformulated gasoline and RBOB imported by the 
importer; except that
    (ii) Any importer to whom different standards apply for gasoline 
imported at different facilities by operation of Sec. 80.41(i), shall 
meet the averaged standards separately for the averaged reformulated 
gasoline and RBOB imported into each group of facilities that is subject 
to the same standards; and
    (3) Any oxygenate blender shall meet the averaged standard for 
oxygen separately for each of the oxygenate blender's oxygenate blending 
facilities, except that any oxygenate blender may group the averaged 
reformulated gasoline produced at facilities at which gasoline is 
produced for use in a single covered area.
    (c) RVP and VOC emissions performance reduction compliance on 
average. (1) The VOC-controlled reformulated gasoline and RBOB produced 
at any refinery or imported by any importer during the period January 1 
through September 15 of each calendar year which is designated for 
average compliance for RVP or VOC emissions performance on average must 
meet the standards for RVP (in the case of a refinery or importer 
subject to the simple model standards) or the standards for VOC 
emissions performance reduction (in the case of a refinery or importer 
subject to the complex model standards) which are applicable to that 
refinery or importer as follows:
    (i) Gasoline and RBOB designated for VOC Control Region 1 must meet 
the standards for that Region which are applicable to that refinery or 
importer; and
    (ii) Gasoline and RBOB designated for VOC Control Region 2 must meet 
the standards for that Region which are applicable to that refinery or 
importer.
    (2) In the case of a refinery or importer subject to the simple 
model standards, each gallon of reformulated gasoline and RBOB 
designated as being VOC-controlled may not exceed the maximum standards 
for RVP specified in Sec. 80.41(b) which are applicable to that refiner 
or importer.
    (3) In the case of a refinery or importer subject to the complex 
model standards, each gallon of reformulated gasoline designated as 
being VOC-controlled must equal or exceed the minimum standards for VOC 
emissions performance specified in Sec. 80.41 which are applicable to 
that refinery or importer.
    (d) Toxics emissions reduction and benzene compliance on average. 
(1) The averaging period for the requirements for benzene content and 
toxics emission performance is January 1 through December 31 of each 
year.
    (2) The reformulated gasoline and RBOB produced at any refinery or 
imported by any importer during the toxics emissions performance and 
benzene averaging periods that is designated for average compliance for 
these parameters shall on average meet the standards specified for 
toxics emissions performance and benzene in Sec. 80.41

[[Page 547]]

which are applicable to that refinery or importer.
    (3) Each gallon of reformulated gasoline may not exceed the maximum 
standard for benzene content specified in Sec. 80.41 which is applicable 
to that refinery or importer.
    (e) NOX compliance on average. (1) The averaging period for 
NOX emissions performance is January 1 through December 31 of each 
year.
    (2) The requirements of this paragraph (e) apply separately to 
reformulated gasoline and RBOB in the following categories:
    (i) All reformulated gasoline and RBOB that is designated as VOC-
controlled; and
    (ii) All reformulated gasoline and RBOB that is not designated as 
VOC-controlled.
    (3) The reformulated gasoline and RBOB produced at any refinery or 
imported by any importer during the NOX averaging period that is 
designated for average compliance for NOX shall on average meet the 
standards for NOX specified in Sec. 80.41 that are applicable to 
that refinery or importer.
    (4) Each gallon of reformulated gasoline must equal or exceed the 
minimum standards for NOX emissions performance specified in 
Sec. 80.41 which are applicable to that refinery or importer.
    (f) Oxygen compliance on average. (1) The averaging period for the 
oxygen content requirements is January 1 through December 31 of each 
year.
    (2) The requirements of this paragraph (f) apply separately to 
reformulated gasoline in the following categories:
    (i) All reformulated gasoline;
    (ii) All reformulated gasoline that is not designated as being OPRG; 
and
    (iii) In the case of reformulated gasoline certified under the 
simple model, that which is designated as VOC- controlled.
    (3) The reformulated gasoline produced at any refinery or imported 
by any importer during the oxygen averaging period that is designated 
for average compliance for oxygen shall on average meet the standards 
for oxygen specified in Sec. 80.41 that is applicable to that refinery 
or importer.
    (4) The reformulated gasoline that is produced at any oxygenate 
blending facility by blending RBOB with oxygenate that is designated for 
average compliance for oxygen shall on average meet the standards for 
oxygen specified in Sec. 80.41 that is applicable to that oxygenate 
blending facility.
    (5) Each gallon of reformulated gasoline must meet the applicable 
minimum requirements, and in the case of simple model reformulated 
gasoline the minimum and maximum requirements, for oxygen content 
specified in Sec. 80.41.
    (g) Compliance calculation. To determine compliance with the 
averaged standards in Sec. 80.41, any refiner for each of its refineries 
at which averaged reformulated gasoline or RBOB is produced, any 
oxygenate blender for each of its oxygenate blending facilities at which 
oxygen averaged reformulated gasoline is produced, and any importer that 
imports averaged reformulated gasoline or RBOB shall, for each averaging 
period and for each portion of gasoline for which standards must be 
separately achieved, and for each relevant standard, calculate:
    (1)(i) The compliance total using the following formula:
    [GRAPHIC] [TIFF OMITTED] TR16FE94.007
    
where

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

and

    (ii) The actual total using the following formula:
    [GRAPHIC] [TIFF OMITTED] TR16FE94.008
    
where

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

    (2) For each standard, compare the actual total with the compliance 
total.

[[Page 548]]

    (3) For the VOC, NOX, and toxics emissions performance and 
oxygen standards, the actual totals must be equal to or greater than the 
compliance totals to achieve compliance.
    (4) For RVP and benzene standards, the actual total must be equal to 
or less than the compliance totals to achieve compliance.
    (5) If the actual total for the oxygen standard is less than the 
compliance total, or if the actual total for the benzene standard is 
greater than the compliance total, credits for these parameters must be 
obtained from another refiner, importer or (in the case of oxygen) 
oxygenate blender in order to achieve compliance:
    (i) The total number of oxygen credits required to achieve 
compliance is calculated by subtracting the actual total from the 
compliance total oxygen; and
    (ii) The total number of benzene credits required to achieve 
compliance is calculated by subtracting the compliance total from the 
actual total benzene.
    (6) If the actual total for the oxygen standard is greater than the 
compliance total, or if the actual total for the benzene standard is 
less than the compliance totals, credits for these parameters are 
generated:
    (i) The total number of oxygen credits which may be traded to 
another refinery, importer, or oxygenate blender is calculated by 
subtracting the compliance total from the actual total for oxygen; and
    (ii) The total number of benzene credits which may be traded to 
another refinery or importer is calculated by subtracting the actual 
total from the compliance total for benzene.
    (h) Credit transfers. (1) Compliance with the averaged standards 
specified in Sec. 80.41 for oxygen and benzene (but for no other 
standards or requirements) may be achieved through the transfer of 
oxygen and benzene credits provided that:
    (i) The credits were generated in the same averaging period as they 
are used;
    (ii) The credit transfer takes place no later than fifteen working 
days following the end of the averaging period in which the reformulated 
gasoline credits were generated;
    (iii) The credits are properly created;
    (iv) The credits are transferred directly from the refiner, 
importer, or oxygenate blender that creates the credits to the refiner, 
importer, or oxygenate blender that uses the credits to achieve 
compliance;
    (v) Oxygen credits are generated, transferred, and used:
    (A) In the case of gasoline subject to the simple model standards, 
only in the following categories:
    (1) VOC-controlled, non-OPRG;
    (2) Non-VOC-controlled, non-OPRG;
    (3) Non-VOC-controlled, OPRG; and
    (4) VOC-controlled, OPRG; and
    (B) In the case of gasoline subject to the complex model standards, 
only in the following categories:
    (1) OPRG; and
    (2) Non-OPRG;
    (vi) Oxygen credits generated from gasoline subject to the complex 
model standards are not used to achieve compliance for gasoline subject 
to the simple model standards;
    (vii) Oxygen credits are not used to achieve compliance with the 
minimum oxygen content standards in Sec. 80.41; and
    (viii) Benzene credits are not used to achieve compliance with the 
maximum benzene content standards in Sec. 80.41.
    (2) No party may transfer any credits to the extent such a transfer 
would result in the transferor having a negative credit balance at the 
conclusion of the averaging period for which the credits were 
transferred. Any credits transferred in violation of this paragraph are 
improperly created credits.
    (3) In the case of credits that were improperly created, the 
following provisions apply:
    (i) Improperly created credits may not be used to achieve 
compliance, regardless of a credit transferee's good faith belief that 
it was receiving valid credits;
    (ii) No refiner, importer, or oxygenate blender may create, report, 
or transfer improperly created credits; and
    (iii) Where any credit transferor has in its balance at the 
conclusion of any averaging period both credits which were properly 
created and credits which were improperly created, the

[[Page 549]]

properly created credits will be applied first to any credit transfers 
before the transferor may apply any credits to achieve its own 
compliance.
    (i) Average compliance for reformulated gasoline produced or 
imported before January 1, 1995. In the case of any reformulated 
gasoline that is intended to be used beginning January 1, 1995, but that 
is produced or imported prior to that date:
    (1) Any refiner or importer may meet standards specified in 
Sec. 80.41 for average compliance for such gasoline, provided the 
refiner or importer has the option of meeting standards on average for 
1995 under paragraph (a) of this section, and provided the refiner or 
importer elects to be subject to average standards under 
Sec. 80.65(c)(3); and
    (2) Any average compliance gasoline under paragraph (i)(1) of this 
section shall be combined with average compliance gasoline produced 
during 1995 for purposes of compliance calculations under paragraph (g) 
of this section.



Sec. 80.68  Compliance surveys.

    (a) Compliance survey option 1. In order to satisfy the compliance 
survey requirements, any refiner, importer, or oxygenate blender shall 
properly conduct a program of compliance surveys in accordance with a 
survey program plan which has been approved by the Administrator of EPA 
in each covered area which is supplied with any gasoline for which 
compliance is achieved on average that is produced by that refiner or 
oxygenate blender or imported by that importer. Such approval shall be 
based upon the survey program plan meeting the following criteria:
    (1) The survey program shall consist of at least four surveys which 
shall occur during the following time periods: one survey during the 
period January 1 through May 31; two surveys during the period June 1 
through September 15; and one survey during the period September 16 
through December 31.
    (2) The survey program shall meet the criteria stated in paragraph 
(c) of this section.
    (3) In the event that any refiner, importer, or oxygenate blender 
fails to properly carry out an approved survey program, the refiner, 
importer, or oxygenate blender shall achieve compliance with all 
applicable standards on a per-gallon basis for the calendar year in 
which the failure occurs, and may not achieve compliance with any 
standard on an average basis during this calendar year. This requirement 
to achieve compliance per-gallon shall apply ab initio to the beginning 
of any calendar year in which the failure occurs, regardless of when 
during the year the failure occurs.
    (b) Compliance survey option 2. A refiner, importer, or oxygenate 
blender shall be deemed to have satisfied the compliance survey 
requirements described in paragraph (a) of this section if a 
comprehensive program of surveys is properly conducted in accordance 
with a survey program plan which has been approved by the Administrator 
of EPA. Such approval shall be based upon the survey program plan 
meeting the following criteria:
    (1) The initial schedule for the conduct of surveys shall be as 
follows:
    (i) 120 surveys shall be conducted in 1995;
    (ii) 80 surveys shall be conducted in 1996;
    (iii) 60 surveys shall be conducted in 1997;
    (iv) 50 surveys shall be conducted in 1998 and thereafter.
    (2) This initial survey schedule shall be adjusted as follows:
    (i) In the event one or more ozone nonattainment areas in addition 
to the nine specified in Sec. 80.70, opt into the reformulated gasoline 
program, the number of surveys to be conducted in the year the area or 
areas opt into the program and in each subsequent year shall be 
increased according to the following formula:

[[Page 550]]

[GRAPHIC] [TIFF OMITTED] TR16FE94.009


where:

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

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

where:

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

    (3) The survey program shall meet the criteria stated in paragraph 
(c) of this section.
    (4) On each occasion the comprehensive survey program does not occur 
as specified in the approved plan with regard to any covered area:
    (i) Each refiner, importer, and oxygenate blender who supplied any 
reformulated gasoline or RBOB to the covered area and who has not 
satisfied the survey requirements described in paragraph (a) of this 
section shall be deemed to have failed to carry out an approved survey 
program; and
    (ii) The covered area will be deemed to have failed surveys for VOC 
and NOX emissions performance, and survey series for benzene and 
oxygen, and toxic and NOX emissions performance.
    (c) General survey requirements. (1) During the period January 1, 
1995 through December 31, 1997:
    (i) Any sample taken from a retail gasoline storage tank for which 
the three most recent deliveries were of gasoline designated as meeting:
    (A) Simple model standards shall be considered a ``simple model 
sample''; or
    (B) Complex model standards shall be considered a ``complex model 
sample.''

[[Page 551]]

    (ii) A survey shall consist of the combination of a simple model 
portion and a complex model portion, as follows:
    (A) The simple model portion of a survey shall consist of all simple 
model samples that are collected pursuant to the applicable survey 
design in a single covered area during any consecutive seven-day period 
and that are not excluded under paragraph (c)(6) of this section.
    (B) The complex model portion of a survey shall consist of all 
complex model samples that are collected pursuant to the applicable 
survey design in a single covered area during any consecutive seven-day 
period and that are not excluded under paragraph (c)(6) of this section.
    (iii)(A) The simple model portion of each survey shall be 
representative of all gasoline certified using the simple model which is 
being dispensed in the covered area.
    (B) The complex model portion of each survey shall be representative 
of all gasoline certified using the complex model which is being 
dispensed in the covered area.
    (2) Beginning on January 1, 1998:
    (i) A survey shall consist of all samples that are collected 
pursuant to the applicable survey design in a single covered area during 
any consecutive seven-day period and that are not excluded under 
paragraph (c)(6) of this section.
    (ii) A survey shall be representative of all gasoline which is being 
dispensed in the covered area.
    (3) A VOC survey, and prior to January 1, 2000, a NOX survey, 
shall consist of any survey conducted during the period June 1 through 
September 15.
    (4)(i) A toxics, oxygen, and benzene survey series shall consist of 
all surveys conducted in a single covered area during a single calendar 
year.
    (ii) A NOX survey series shall consist of all surveys conducted 
in a single covered area during the periods January 1 through May 31, 
and September 16 through December 31 during a single calendar year.
    (5)(i) Each simple model sample included in a survey shall be 
analyzed for oxygenate type and content, benzene content, aromatic 
hydrocarbon content, and RVP in accordance with the methodologies 
specified in Sec. 80.46; and
    (ii) Each complex model sample included in a survey shall be 
analyzed for oxygenate type and content, olefins, benzene, sulfur, and 
aromatic hydrocarbons, E-200, E-300, and RVP in accordance with the 
methodologies specified in Sec. 80.46.
    (6)(i) The results of each survey shall be based upon the results of 
the analysis of each sample collected during the course of the survey, 
unless the sample violates the applicable per-gallon maximum or minimum 
standards for the parameter being evaluated plus any enforcement 
tolerance that applies to the parameter (e.g., a sample that violates 
the benzene per-gallon maximum plus any benzene enforcement tolerance 
but meets other per-gallon maximum and minimum standards would be 
excluded from the benzene survey, but would be included in the surveys 
for parameters other than benzene).
    (ii) Any sample from a survey that violates any standard under 
Sec. 80.41, or that constitutes evidence of the violation of any 
prohibition or requirement under this subpart D, may be used by the 
Administrator in an enforcement action for such violation.
    (7) Each laboratory at which samples in a survey are analyzed shall 
participate in a correlation program with EPA to ensure the validity of 
analysis results.
    (8)(i) The results of each simple model VOC survey shall be 
determined as follows:
    (A) For each simple model sample from the survey, the VOC emissions 
reduction percentage shall be determined based upon the tested values 
for RVP and oxygen for that sample as applied to the VOC emissions 
reduction equation at Sec. 80.42(a)(1) for VOC-Control Region 1 and 
Sec. 80.42(a)(2) for VOC-Control Region 2;
    (B) The VOC emissions reduction survey standard applicable to each 
covered area shall be calculated by using the VOC emissions equation at 
Sec. 80.42(a)(1) with RVP=7.2 and OXCON=2.0 for covered areas located in 
VOC-Control Region 1 and using the VOC emissions equation at 
Sec. 80.42(a)(2)

[[Page 552]]

with RVP=8.1 and OXCON=2.0 for covered areas located in VOC-Control 
Region 2; and
    (C) The covered area shall have failed the simple model VOC survey 
if the VOC emissions reduction average of all survey samples is less 
than VOC emissions reduction survey standard calculated under paragraph 
(c)(8)(i)(B) of this section.
    (ii) The results of each complex model VOC emissions reduction 
survey shall be determined as follows:
    (A) For each complex model sample from the survey series, the VOC 
emissions reduction percentage shall be determined based upon the tested 
parameter values for that sample and the appropriate methodology for 
calculating VOC emissions reduction at Sec. 80.45;
    (B) The covered area shall have failed the complex model VOC survey 
if the VOC emissions reduction percentage average of all survey samples 
is less than the applicable per-gallon standard for VOC emissions 
reduction.
    (9)(i) The results of each simple model toxics emissions reduction 
survey series conducted in any covered area shall be determined as 
follows:
    (A) For each simple model sample from the survey series, the toxics 
emissions reduction percentage shall be determined based upon the tested 
parameter values for that sample and the appropriate methodology for 
calculating toxics emissions performance reduction at Sec. 80.42.
    (B) The annual average of the toxics emissions reduction percentages 
for all samples from a survey series shall be calculated according to 
the following formula:
[GRAPHIC] [TIFF OMITTED] TR16FE94.011

where

AATER = the annual average toxics emissions reduction
TER1,i = the toxics emissions reduction for sample i of gasoline 
collected during the high ozone season
TER2,i = the toxics emissions reduction for sample i of gasoline 
collected outside the high ozone season
n1 = the number of samples collected during the high ozone season
n2 = the number of samples collected outside the high ozone season

    0(C) The covered area shall have failed the simple model toxics 
survey series if the annual average toxics emissions reduction is less 
than the simple model per-gallon standard for toxics emissions 
reduction.
    (ii) The results of each complex model toxics emissions reduction 
survey series conducted in any covered area shall be determined as 
follows:
    (A) For each complex model sample from the survey series, the toxics 
emissions reduction percentage shall be determined based upon the tested 
parameter values for that sample and the appropriate methodology for 
calculating toxics emissions reduction at Sec. 80.45;
    (B) The annual average of the toxics emissions reduction percentages 
for all samples from a survey series shall be calculated according to 
the formula specified in paragraph (c)(9)(i)(B) of this section; and
    (C) The covered area shall have failed the complex model toxics 
survey series if the annual average toxics emissions reduction is less 
than the applicable per-gallon complex model standard for toxics 
emissions reduction.
    (10) The results of each NOX emissions reduction survey and 
survey series shall be determined as follows:
    (i) For each sample from the survey and survey series, the NOX 
emissions reduction percentage shall be determined based upon the tested 
parameter

[[Page 553]]

values for that sample and the appropriate methodology for calculating 
NOX emissions reduction at Sec. 80.45; and
    (ii) The covered area shall have failed the NOX survey or 
survey series if the NOX emissions reduction percentage average for 
all survey samples is less than the applicable Phase I or Phase II 
complex model per-gallon standard for NOX emissions reduction.
    (11) For any benzene content survey series conducted in any covered 
area the average benzene content for all samples from the survey series 
shall be calculated. If this annual average is greater than 1.000 
percent by volume, the covered area shall have failed a benzene survey 
series.
    (12) For any oxygen content survey series conducted in any covered 
area the average oxygen content for all samples from the survey series 
shall be calculated. If this annual average is less than 2.00 percent by 
weight, the covered area shall have failed an oxygen survey series.
    (13) Each survey program shall:
    (i) Be planned and conducted by a person who is independent of the 
refiner or importer (the surveyor). In order to be considered 
independent:
    (A) The surveyor shall not be an employee of any refiner or 
importer;
    (B) The surveyor shall be free from any obligation to or interest in 
any refiner or importer; and
    (C) The refiner or importer shall be free from any obligation to or 
interest in the surveyor; and
    (ii) Include procedures for selecting sample collection locations, 
numbers of samples, and gasoline compositions which will result in:
    (A) Simple model surveys representing all gasoline certified using 
the simple model being dispensed at retail outlets within the covered 
area during the period of the survey; and
    (B) Complex model surveys representing all gasoline certified using 
the complex model being dispensed at retail outlets within the covered 
area during the period of the survey; and
    (iii) Include procedures such that the number of samples included in 
each survey assures that:
    (A) In the case of simple model surveys, the average levels of 
oxygen, benzene, RVP, and aromatic hydrocarbons are determined with a 
95% confidence level, with error of less than 0.1 psi for RVP, 0.05% for 
benzene (by volume), and 0.1% for oxygen (by weight); and
    (B) In the case of complex model surveys, the average levels of 
oxygen, benzene, RVP, aromatic hydrocarbons, olefins, T-50, T-90, and 
sulfur are determined with a 95% confidence level, with error of less 
than 0.1 psi for RVP, 0.05% for benzene (by volume), 0.1% for oxygen (by 
weight), 0.5% for aromatic hydrocarbons (by volume), 0.5% for olefins 
(by volume), 5  deg.F. for T-50 and T-90, and 10 ppm for sulfur; and
    (iv) Require that the surveyor shall:
    (A) Not inform anyone, in advance, of the date or location for the 
conduct of any survey;
    (B) Upon request by EPA made within thirty days following the 
submission of the report of a survey, provide a duplicate of any 
gasoline sample taken during that survey to EPA at a location to be 
specified by EPA each sample to be identified by the name and address of 
the facility where collected, the date of collection, and the 
classification of the sample as simple model or complex model; and
    (C) At any time permit any representative of EPA to monitor the 
conduct of the survey, including sample collection, transportation, 
storage, and analysis; and
    (v) Require the surveyor to submit to EPA a report of each survey, 
within thirty days following completion of the survey, such report to 
include the following information:
    (A) The identification of the person who conducted the survey;
    (B) An attestation by an officer of the surveyor company that the 
survey was conducted in accordance with the survey plan and that the 
survey results are accurate;
    (C) If the survey was conducted for one refiner or importer, the 
identification of that party;
    (D) The identification of the covered area surveyed;
    (E) The dates on which the survey was conducted;
    (F) The address of each facility at which a gasoline sample was 
collected, the date of collection, and the classification of the sample 
as simple model or complex model;

[[Page 554]]

    (G) The results of the analyses of simple model samples for 
oxygenate type and oxygen weight percent, benzene content, aromatic 
hydrocarbon content, and RVP, the calculated toxics emission reduction 
percentage, and for each survey conducted during the period June 1 
through September 15 the VOC emissions reduction percentage calculated 
using the methodology specified in paragraph (c)(8)(i) of this section;
    (H) The results of the analyses of complex model samples for 
oxygenate type and oxygen weight percent, benzene, aromatic hydrocarbon, 
and olefin content, E-200, E-300, and RVP, the calculated NOX and 
toxics emissions reduction percentage, and for each survey conducted 
during the period June 1 through September 15 the calculated VOC 
emissions reduction percentage, except that beginning on January 1, 2000 
NOX emissions reduction percentages must be reported only for 
surveys conducted outside the period June 1 through September 15;
    (I) The name and address of each laboratory where gasoline samples 
were analyzed;
    (J) A description of the methodology utilized to select the 
locations for sample collection and the numbers of samples collected;
    (K) For any samples which were excluded from the survey, a 
justification for such exclusion; and
    (L) The average toxics emissions reduction percentage for simple 
model samples and the percentage for complex model samples, the average 
benzene and oxygen percentages, and for each survey conducted during the 
period June 1 through September 15, the average VOC emissions reduction 
percentage for simple model samples and the percentage for complex model 
samples, the average NOX emissions reduction percentage for all 
complex model samples collected prior to January 1, 2000, and the 
average NOX emissions reduction percentage for samples collected 
outside the period June 1 through September 15 beginning on January 1, 
2000;
    (14) Each survey shall be conducted at a time and in a covered area 
selected by EPA no earlier than two weeks before the date of the survey.
    (15) The procedure for seeking EPA approval for a survey program 
plan shall be as follows:
    (i) The survey program plan shall be submitted to the Administrator 
of EPA for EPA's approval no later than September 1 of the year 
preceding the year in which the surveys will be conducted; and
    (ii) Such submittal shall be signed by a responsible corporate 
officer of the refiner, importer, or oxygenate blender, or in the case 
of a comprehensive survey program plan, by an officer of the 
organization coordinating the survey program.
    (16)(i) No later than December 1 of the year preceding the year in 
which the surveys will be conducted, the contract with the surveyor to 
carry out the entire survey plan shall be in effect, and an amount of 
money necessary to carry out the entire survey plan shall be paid to the 
surveyor or placed into an escrow account with instructions to the 
escrow agent to pay the money over to the surveyor during the course of 
the conduct of the survey plan.
    (ii) No later than December 15 of the year preceding the year in 
which the surveys will be conducted, the Administrator of EPA shall be 
given a copy of the contract with the surveyor, proof that the money 
necessary to carry out the plan has either been paid to the surveyor or 
placed into an escrow account, and if placed into an escrow account, a 
copy of the escrow agreement.

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



Sec. 80.69  Requirements for downstream oxygenate blending.

    The requirements of this section apply to all reformulated gasoline 
blendstock for oxygenate blending, or RBOB, to which oxygenate is added 
at any oxygenate blending facility.
    (a) Requirements for refiners and importers. For any RBOB produced 
or imported, the refiner or importer of the RBOB shall:
    (1) Produce or import the RBOB such that, when blended with a 
specified type and percentage of oxygenate, it meets the applicable 
standards for reformulated gasoline;

[[Page 555]]

    (2) In order to determine the properties of RBOB for purposes of 
calculating compliance with per-gallon or averaged standards, conduct 
tests on each batch of the RBOB by:
    (i) Adding the specified type and amount of oxygenate to a 
representative sample of the RBOB; and
    (ii) Determining the properties and characteristics of the resulting 
gasoline using the methodology specified in Sec. 80.65(e);
    (3) Carry out the independent analysis requirements specified in 
Sec. 80.65(f);
    (4) Determine properties of the RBOB which are sufficient to allow 
parties downstream from the refinery or import facility to establish, 
through sampling and testing, if the RBOB has been altered or 
contaminated such that it will not meet the applicable reformulated 
gasoline standards subsequent to the addition of the specified type and 
amount of oxygenate;
    (5) Transfer ownership of the RBOB only to an oxygenate blender who 
is registered with EPA as such, or to an intermediate owner with the 
restriction that it only be transferred to a registered oxygenate 
blender;
    (6) Have a contract with each oxygenate blender who receives any 
RBOB produced or imported by the refiner or importer that requires the 
oxygenate blender, or, in the case of a contract with an intermediate 
owner, that requires the intermediate owner to require the oxygenate 
blender to:
    (i) Comply with blender procedures that are specified by the 
contract and are calculated to assure blending with the proper type and 
amount of oxygenate;
    (ii) Allow the refiner or importer to conduct quality assurance 
sampling and testing of the reformulated gasoline produced by the 
oxygenate blender;
    (iii) Stop selling any gasoline found to not comply with the 
standards under which the RBOB was produced or imported; and
    (iv) Carry out the quality assurance sampling and testing that this 
section requires the oxygenate blender to conduct;
    (7) Conduct a quality assurance sampling and testing program to be 
carried out at the facilities of each oxygenate blender who blends any 
RBOB produced or imported by the refiner or importer with any oxygenate, 
to determine whether the reformulated gasoline which has been produced 
through blending complies with the applicable standards, using the 
methodology specified in Sec. 80.46 for this determination.
    (i) The sampling and testing program shall be conducted as follows:
    (A) All samples shall be collected subsequent to the addition of 
oxygenate, and either:
    (1) Prior combining the resulting gasoline with any other gasoline; 
or
    (2) In the case of truck splash blending, subsequent to the delivery 
of the gasoline to a retail outlet or wholesale purchaser-consumer 
facility provided that the three most recent deliveries to the retail 
outlet or wholesale purchaser facility were of gasoline produced using 
that refiner's or importer's RBOB, and provided that any discrepancy 
found through the retail outlet or wholesale purchaser facility sampling 
is followed-up with measures reasonably designed to discover the cause 
of the discrepancy; and
    (B) Sampling and testing shall be at one of the following rates:
    (1) In the case of RBOB which is blended with oxygenate in a 
gasoline storage tank, a rate of not less than one sample for every 
400,000 barrels of RBOB produced or imported by that refiner or importer 
that is blended by that blender, or one sample every month, whichever is 
more frequent; or
    (2) In the case of RBOB which is blended with oxygenate in gasoline 
delivery trucks through the use of computer-controlled in-line blending 
equipment, a rate of not less than one sample for every 200,000 barrels 
of RBOB produced or imported by that refiner or importer that is blended 
by that blender, or one sample every three months, whichever is more 
frequent; or
    (3) In the case of RBOB which is blended with oxygenate in gasoline 
delivery trucks without the use of computer-controlled in-line blending 
equipment, a rate of not less than one sample for each 50,000 barrels of 
RBOB produced or imported by that refiner or importer which is blended, 
or one sample per month, whichever is more frequent;

[[Page 556]]

    (ii) In the event the test results for any sample indicate the 
gasoline does not comply with applicable standards (within the 
correlation ranges specified in Sec. 80.65(e)(2)(i)), the refiner or 
importer shall:
    (A) Immediately take steps to stop the sale of the gasoline that was 
sampled;
    (B) Take steps which are reasonably calculated to determine the 
cause of the noncompliance and to prevent future instances of 
noncompliance;
    (C) Increase the rate of sampling and testing to one of the 
following rates:
    (1) In the case of RBOB which is blended with oxygenate in a 
gasoline storage tank, a rate of not less than one sample for every 
200,000 barrels of RBOB produced or imported by that refiner or importer 
that is blended by that blender, or one sample every two weeks, 
whichever is more frequent; or
    (2) In the case of RBOB which is blended with oxygenate in gasoline 
delivery trucks through the use of computer-controlled in-line blending 
equipment, a rate of not less than one sample for every 100,000 barrels 
of RBOB produced or imported by that refiner or importer that is blended 
by that blender, or one sample every two months, whichever is more 
frequent; or
    (3) In the case of RBOB which is blended with oxygenate in gasoline 
delivery trucks without the use of computer-controlled in-line blending 
equipment, a rate of not less than one sample for each 25,000 barrels of 
RBOB produced or imported by that refiner or importer which is blended, 
or one sample every two weeks, whichever is more frequent;
    (D) Continue the increased frequency of sampling and testing until 
the results of ten consecutive samples and tests indicate the gasoline 
complies with applicable standards, at which time the sampling and 
testing may be conducted at the original frequency;
    (iii) This quality assurance program is in addition to any quality 
assurance requirements carried out by other parties;
    (8) A refiner or importer of RBOB may, in lieu of the contractual 
and quality assurance requirements specified in paragraphs (a) (6) and 
(7) of this section, base its compliance calculations on the following 
assumptions:
    (i) In the case of RBOB designated for any-oxygenate, assume that 
ethanol will be added;
    (ii) In the case of RBOB designated for ether-only, assume that MTBE 
will be added; and
    (iii) In the case of any-oxygenate and ether-only designated RBOB, 
assume that the volume of oxygenate added will be such that the 
resulting reformulated gasoline will have an oxygen content of 2.0 
weight percent;
    (9) Any refiner or importer who does not meet the contractual and 
quality assurance requirements specified in paragraphs (a) (6) and (7) 
of this section, and who does not designate its RBOB as ether-only or 
any-oxygenate, shall base its compliance calculations on the assumption 
that 4.0 volume percent ethanol is added to the RBOB; and
    (10) Specify in the product transfer documentation for the RBOB each 
oxygenate type or types and amount or range of amounts which is 
consistent with the designation of the RBOB as any-oxygenate, or ether-
only, and which, if blended with the RBOB will result in reformulated 
gasoline which:
    (i) Has VOC, toxics, or NOX emissions reduction percentages 
which are no lower than the percentages that formed the basis for the 
refiner's or importer's compliance determination for these parameters;
    (ii) Has a benzene content and RVP level which are no higher than 
the values for these characteristics that formed the basis for the 
refiner's or importer's compliance determinations for these parameters; 
and
    (iii) Will not cause the reformulated gasoline to violate any 
standard specified in Sec. 80.41.
    (b) Requirements for oxygenate blenders. For all RBOB received by 
any oxygenate blender, the oxygenate blender shall:
    (1) Add oxygenate of the type(s) and amount (or within the range of 
amounts) specified in the product transfer documents for the RBOB;
    (2) Designate each batch of the resulting reformulated gasoline as 
meeting the oxygen standard per-gallon or on average;

[[Page 557]]

    (3) Meet the standard requirements specified in Sec. 80.65(c) and 
Sec. 80.67(f), the record keeping requirements specified in Sec. 80.74, 
and the reporting requirements specified in Sec. 80.75; and
    (4) In the case of each batch of reformulated gasoline which is 
designated for compliance with the oxygen standard on average:
    (i) Determine the volume and the weight percent oxygen of the batch 
using the testing methodology specified in Sec. 80.46;
    (ii) Assign a number to the batch (the ``batch number''), beginning 
with the number one for the first batch produced each calendar year and 
each subsequent batch during the calendar year being assigned the next 
sequential number, and such numbers to be preceded by the oxygenate 
blender's registration number, the facility number, and the second two 
digits of the year in which the batch was produced (e.g., 4321-4321-95-
001, 4321-4321-95-002, etc.); and
    (iii) Meet the compliance audit requirements specified in 
Sec. 80.65(h).
    (c) Additional requirements for terminal storage tank blending. Any 
oxygenate blender who produces reformulated gasoline by blending any 
oxygenate with any RBOB in any gasoline storage tank, other than a truck 
used for delivering gasoline to retail outlets or wholesale purchaser-
consumer facilities, shall, for each batch of reformulated gasoline so 
produced determine the oxygen content and volume of this gasoline prior 
to the gasoline leaving the oxygenate blending facility, using the 
methodology specified in Sec. 80.46.
    (d) Additional requirements for distributors dispensing RBOB into 
trucks for blending. Any distributor who dispenses any RBOB into any 
truck which delivers gasoline to retail outlets or wholesale purchaser-
consumer facilities, shall for such RBOB so dispensed:
    (1) Transfer the RBOB only to an oxygenate blender who has 
registered with the Administrator of EPA as such;
    (2) Transfer any RBOB designated as ether-only RBOB only if the 
distributor has a reasonable basis for knowing the oxygenate blender 
will blend an oxygenate other than ethanol with the RBOB; and
    (3) Obtain from the oxygenate blender the oxygenate blender's EPA 
registration number.
    (e) Additional requirements for oxygenate blenders who blend 
oxygenate in trucks. Any oxygenate blender who obtains any RBOB in any 
gasoline delivery truck shall:
    (1) On each occasion it obtains RBOB from a distributor, supply the 
distributor with the oxygenate blender's EPA registration number;
    (2) Conduct a quality assurance sampling and testing program to 
determine whether the proper type and amount of oxygenate is added to 
RBOB. The program shall be conducted as follows:
    (i) All samples shall be collected subsequent to the addition of 
oxygenate, and either:
    (A) Prior combining the resulting gasoline with any other gasoline; 
or
    (B) Subsequent to the delivery of the gasoline to a retail outlet or 
wholesale purchaser-consumer facility provided that the three most 
recent deliveries to the retail outlet or wholesale purchaser facility 
were of gasoline that was produced by that oxygenate blender and that 
had the same oxygenate requirements, and provided that any discrepancy 
in oxygenate type or amount found through the retail outlet or wholesale 
purchaser facility sampling is followed-up with measures reasonably 
designed to discover the cause of the discrepancy;
    (ii) Sampling and testing shall be at one of the following rates:
    (A) In the case computer-controlled in-line blending is used, a rate 
of not less than one sample per each five hundred occasions RBOB and 
oxygenate are loaded into a truck by that oxygenate blender, or one 
sample every three months, whichever is more frequent; or
    (B) In the case computer-controlled in-line blending is not used, a 
rate of not less than one sample per each one hundred occasions RBOB and 
oxygenate are blended in a truck by that oxygenate blender, or one 
sample per month, whichever is more frequent;
    (iii) Sampling and testing shall be of the gasoline produced through 
one of the RBOB-oxygenate blends produced by that oxygenate blender;
    (iv) Samples shall be analyzed for oxygenate type and oxygen content 
using

[[Page 558]]

the testing methodology specified at Sec. 80.46; and
    (v) In the event the testing results for any sample indicate the 
gasoline does not contain the specified type and amount of oxygenate 
(within the ranges specified in Sec. 80.70(b)(2)(i)):
    (A) Immediately stop selling (or where possible, to stop any 
transferee of the gasoline from selling) the gasoline which was sampled;
    (B) Take steps to determine the cause of the noncompliance;
    (C) Increase the rate of sampling and testing to one of the 
following rates:
    (1) In the case computer-controlled in-line blending is used, a rate 
of not less than one sample per each two hundred and fifty occasions 
RBOB and oxygenate are loaded into a truck by that oxygenate blender, or 
one sample every six weeks, whichever is more frequent; or
    (2) In the case computer-controlled in-line blending is not used, a 
rate of not less than one sample per each fifty occasions RBOB and 
oxygenate are blended in a truck by that oxygenate blender, or one 
sample every two weeks, whichever is more frequent; and
    (D) This increased frequency shall continue until the results of ten 
consecutive samples and tests indicate the gasoline complies with 
applicable standards, at which time the frequency may revert to the 
original frequency.
    (f) Oxygenate blending with OPRG. Notwithstanding the requirements 
for and restrictions on oxygenate blending provided in this section, any 
oxygenate blender may blend oxygenate with reformulated gasoline that is 
designated as OPRG, without meeting the record keeping and reporting 
requirements that otherwise apply to oxygenate blenders, provided that 
the reformulated gasoline so produced is:
    (1) Used in an oxygenated fuels program control area during an 
oxygenated fuels program control period; and
    (2) ``Substantially similar'' under section 211(f)(1) of the Clean 
Air Act, or is permitted under a waiver granted by the Administrator 
under the authority of section 211(f)(4) of the Clean Air Act.

[59 FR 7813, Feb. 16, 1994, as amended at 59 FR 36964, July 20, 1994]



Sec. 80.70  Covered areas.

    For purposes of subparts D, E, and F of this part, the covered areas 
are as follows:
    (a) The Los Angeles-Anaheim-Riverside, California, area, comprised 
of:
    (1) Los Angeles County;
    (2) Orange County;
    (3) Ventura County;
    (4) That portion of San Bernadino County that lies south of latitude 
35 degrees, 10 minutes north and west of longitude 115 degrees, 45 
minutes west; and
    (5) That portion of Riverside County, which lies to the west of a 
line described as follows:
    (i) Beginning at the northeast corner of Section 4, Township 2 
South, Range 5 East, a point on the boundary line common to Riverside 
and San Bernadino Counties;
    (ii) Then southerly along section lines to the centerline of the 
Colorado River Aqueduct;
    (iii) Then southeasterly along the centerline of said Colorado River 
Aqueduct to the southerly line of Section 36, Township 3 South, Range 7 
East;
    (iv) Then easterly along the township line to the northeast corner 
of Section 6, Township 4 South, Range 9 East;
    (v) Then southerly along the easterly line of Section 6 to the 
southeast corner thereof;
    (vi) Then easterly along section lines to the northeast corner of 
Section 10, Township 4 South, Range 9 East;
    (vii) Then southerly along section lines to the southeast corner of 
Section 15, Township 4 South, Range 9 East;
    (viii) Then easterly along the section lines to the northeast corner 
of Section 21, Township 4 South, Range 10 East;
    (ix) Then southerly along the easterly line of Section 21 to the 
southeast corner thereof;
    (x) Then easterly along the northerly line of Section 27 to the 
northeast corner thereof;
    (xi) Then southerly along section lines to the southeast corner of 
Section 34, Township 4 South, Range 10 East;
    (xii) Then easterly along the township line to the northeast corner 
of Section 2, Township 5 South, Range 10 East;

[[Page 559]]

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

[[Page 560]]

    (v) Howard; and
    (2) The City of Baltimore.
    (h) The Houston-Galveston-Brazoria, Texas area, comprised of the 
following Texas counties:
    (1) Brazoria;
    (2) Fort Bend;
    (3) Galveston;
    (4) Harris;
    (5) Liberty;
    (6) Montgomery;
    (7) Waller; and
    (8) Chambers.
    (i) The Milwaukee-Racine, Wisconsin area, comprised of the following 
Wisconsin counties:
    (1) Kenosha;
    (2) Milwaukee;
    (3) Ozaukee;
    (4) Racine;
    (5) Washington; and
    (6) Waukesha.
    (j) The ozone nonattainment areas listed in this paragraph (j) are 
covered areas beginning on January 1, 1995, except that those areas 
listed in paragraphs (j)(5) (viii) and (ix), (j)(10) (i), (iii), and (v) 
through (xi) and (j)(11) of this section shall not be covered areas 
prior to EPA taking final action on the proposal to remove these areas 
as covered areas.
    (1) Sussex County, Delaware;
    (2) District of Columbia portion of the Washington ozone 
nonattainment area;
    (3) The following Kentucky counties:
    (i) Boone;
    (ii) Campbell;
    (iii) Jefferson; and
    (iv) Kenton;
    (4) Portions of the following Kentucky counties:
    (i) Portion of Bullitt County described as follows:
    (A) Beginning at the intersection of Ky 1020 and the Jefferson-
Bullitt County Line proceeding to the east along the county line to the 
intersection of county road 567 and the Jefferson-Bullitt County Line;
    (B) Proceeding south on county road 567 to the junction with Ky 1116 
(also known as Zoneton Road);
    (C) Proceeding to the south on KY 1116 to the junction with Hebron 
Lane;
    (D) Proceeding to the south on Hebron Lane to Cedar Creek;
    (E) Proceeding south on Cedar Creek to the confluence of Floyds Fork 
turning southeast along a creek that meets Ky 44 at Stallings Cemetery;
    (F) Proceeding west along Ky 44 to the eastern most point in the 
Shepherdsville city limits;
    (G) Proceeding south along the Shepherdsville city limits to the 
Salt River and west to a point across the river from Mooney Lane;
    (H) Proceeding south along Mooney Lane to the junction of Ky 480;
    (I) Proceeding west on Ky 480 to the junction with Ky 2237;
    (J) Proceeding south on Ky 2237 to the junction with Ky 61 and 
proceeding north on Ky 61 to the junction with Ky 1494;
    (K) Proceeding south on Ky 1494 to the junction with the perimeter 
of the Fort Knox Military Reservation;
    (L) Proceeding north along the military reservation perimeter to 
Castleman Branch Road;
    (M) Proceeding north on Castleman Branch Road to Ky 44;
    (N) Proceeding a very short distance west on Ky 44 to a junction 
with Ky 1020; and
    (O) Proceeding north on Ky 1020 to the beginning.
    (ii) Portion of Oldham County described as follows:
    (A) Beginning at the intersection of the Oldham-Jefferson County 
Line with the southbound lane of Interstate 71;
    (B) Proceeding to the northeast along the southbound lane of 
Interstate 71 to the intersection of Ky 329 and the southbound lane of 
Interstate 71;
    (C) Proceeding to the northwest on Ky 329 to the intersection of 
Zaring Road on Ky 329;
    (D) Proceeding to the east-northeast on Zaring Road to the junction 
of Cedar Point Road and Zaring Road;
    (E) Proceeding to the north-northeast on Cedar Point Road to the 
junction of Ky 393 and Cedar Point Road;
    (F) Proceeding to the south-southeast on Ky 393 to the junction of 
county road 746 (the road on the north side of Reformatory Lake and the 
Reformatory);
    (G) Proceeding to the east-northeast on county road 746 to the 
junction with Dawkins Lane (also known as Saddlers Mill Road) and county 
road 746;

[[Page 561]]

    (H) Proceeding to follow an electric power line east-northeast 
across from the junction of county road 746 and Dawkins Lane to the 
east-northeast across Ky 53 on to the La Grange Water Filtration Plant;
    (I) Proceeding on to the east-southeast along the power line then 
south across Fort Pickens Road to a power substation on Ky 146;
    (J) Proceeding along the power line south across Ky 146 and the 
Seaboard System Railroad track to adjoin the incorporated city limits of 
La Grange;
    (K) Then proceeding east then south along the La Grange city limits 
to a point abutting the north side of Ky 712;
    (L) Proceeding east-southeast on Ky 712 to the junction of Massie 
School Road and Ky 712;
    (M) Proceeding to the south-southwest and then north-northwest on 
Massie School Road to the junction of Ky 53 and Massie School Road;
    (N) Proceeding on Ky 53 to the north-northwest to the junction of 
Moody Lane and Ky 53;
    (O) Proceeding on Moody Lane to the south-southwest until meeting 
the city limits of La Grange;
    (P) Then briefly proceeding north following the La Grange city 
limits to the intersection of the northbound lane of Interstate 71 and 
the La Grange city limits;
    (Q) Proceeding southwest on the northbound lane of Interstate 71 
until intersecting with the North Fork of Currys Fork;
    (R) Proceeding south-southwest beyond the confluence of Currys Fork 
to the south-southwest beyond the confluence of Floyds Fork continuing 
on to the Oldham-Jefferson County Line; and
    (S) Proceeding northwest along the Oldham-Jefferson County Line to 
the beginning.
    (5) The following Maine counties:
    (i) Androscoggin;
    (ii) Cumberland;
    (iii) Kennebec;
    (iv) Knox;
    (v) Lincoln;
    (vi) Sagadahoc;
    (vii) York;
    (viii) Hancock; and
    (ix) Waldo;
    (6) The following Maryland counties:
    (i) Calvert;
    (ii) Charles;
    (iii) Frederick;
    (iv) Montgomery;
    (v) Prince Georges;
    (vi) Queen Anne's; and
    (vii) Kent;
    (7) The entire State of Massachusetts;
    (8) The following New Hampshire counties:
    (i) Strafford;
    (ii) Merrimack;
    (iii) Hillsborough; and
    (iv) Rockingham;
    (9) The following New Jersey counties:
    (i) Atlantic;
    (ii) Cape May; and
    (iii) Warren;
    (10) The following New York counties:
    (i) Albany;
    (ii) Dutchess;
    (iii) Erie;
    (iv) The portion of Essex County that consists of the portion of 
Whiteface Mountain above 4,500 feet in elevation.
    (v) Greene;
    (vi) Jefferson;
    (vii) Montgomery;
    (viii) Niagara;
    (ix) Rensselaer;
    (x) Saratoga; and
    (xi) Schenectady;
    (11) The following Pennsylvania counties:
    (i) Allegheny;
    (ii) Armstrong;
    (iii) Beaver;
    (iv) Berks;
    (v) Butler;
    (vi) Fayette;
    (vii) Washington;
    (viii) Westmoreland;
    (ix) Adams;
    (x) Blair;
    (xi) Cambria;
    (xii) Carbon;
    (xiii) Columbia;
    (xiv) Cumberland;
    (xv) Dauphin;
    (xvi) Erie;
    (xvii) Lackawanna;
    (xviii) Lancaster;
    (xix) Lebanon;
    (xx) Lehigh;
    (xxi) Luzerne;
    (xxii) Mercer;

[[Page 562]]

    (xxiii) Monroe;
    (xxiv) Northampton;
    (xxv) Perry;
    (xxvi) Somerset;
    (xxvii) Wyoming; and
    (xxviii) York;
    (12) The entire State of Rhode Island;
    (13) The following Texas counties: and
    (i) Collin;
    (ii) Dallas;
    (iii) Denton; and
    (iv) Tarrant;
    (14) The following Virginia areas:
    (i) Alexandria;
    (ii) Arlington County;
    (iii) Fairfax;
    (iv) Fairfax County;
    (v) Falls Church;
    (vi) Loudoun County;
    (vii) Manassas;
    (viii) Manassas Park;
    (ix) Prince William County;
    (x) Stafford County;
    (xi) Charles City County;
    (xii) Chesterfield County;
    (xiii) Colonial Heights;
    (xiv) Hanover County;
    (xv) Henrico County;
    (xvi) Hopewell;
    (xvii) Richmond;
    (xviii) Chesapeake;
    (xix) Hampton;
    (xx) James City County;
    (xxi) Newport News;
    (xxii) Norfolk;
    (xxiii) Poquoson;
    (xxiv) Portsmouth;
    (xxv) Suffolk;
    (xxvi) Virginia Beach;
    (xxvii) Williamsburg; and
    (xxviii) York County.
    (k) Any other area classified under 40 CFR part 81, subpart C as a 
marginal, moderate, serious, or severe ozone nonattainment area may be 
included on petition of the governor of the state in which the area is 
located. Effective one year after an area has been reclassified as a 
severe ozone nonattainment area, such severe area shall also be a 
covered area for purposes of this subpart D.

[59 FR 7813, Feb. 16, 1994, as amended at 59 FR 36964, July 20, 1994; 60 
FR 2699, Jan 11, 1995; 60 FR 35491, July 10, 1995]



Sec. 80.71   Descriptions of VOC-control regions.

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

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

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

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

[[Page 563]]

Wyoming

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



Sec. 80.72  [Reserved]



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

    In appropriate extreme and unusual circumstances (e.g., natural 
disaster or Act of God) which are clearly outside the control of the 
refiner, importer, or oxygenate blender and which could not have been 
avoided by the exercise of prudence, diligence, and due care, EPA may 
permit a refiner, importer, or oxygenate blender, for a brief period, to 
distribute gasoline which does not meet the requirements for 
reformulated gasoline, if:
    (a) It is in the public interest to do so (e.g., distribution of the 
nonconforming gasoline is necessary to meet projected shortfalls which 
cannot otherwise be compensated for);
    (b) The refiner, importer, or oxygenate blender exercised prudent 
planning and was not able to avoid the violation and has taken all 
reasonable steps to minimize the extent of the nonconformity;
    (c) The refiner, importer, or oxygenate blender can show how the 
requirements for reformulated gasoline will be expeditiously achieved;
    (d) The refiner, importer, or oxygenate blender agrees to make up 
air quality detriment associated with the nonconforming gasoline, where 
practicable; and
    (e) The refiner, importer, or oxygenate blender pays to the U.S. 
Treasury an amount equal to the economic benefit of the nonconformity 
minus the amount expended, pursuant to paragraph (d) of this section, in 
making up the air quality detriment.



Sec. 80.74  Recordkeeping requirements.

    All parties in the gasoline distribution network, as described in 
this section, shall maintain records containing the information as 
required in this section. These records shall be retained for a period 
of five years from the date of creation, and shall be delivered to the 
Administrator of EPA or to the Administrator's authorized representative 
upon request.
    (a) All regulated parties. Any refiner, importer, oxygenate blender, 
carrier, distributor, reseller, retailer, or wholesale-purchaser who 
sells, offers for sale, dispenses, supplies, offers for supply, stores, 
transports, or causes the transportation of any reformulated gasoline or 
RBOB, shall maintain records containing the following information:
    (1) The product transfer documentation for all reformulated gasoline 
or RBOB for which the party is the transferor or transferee; and
    (2) For any sampling and testing on RBOB or reformulated gasoline:
    (i) The location, date, time, and storage tank or truck 
identification for each sample collected;
    (ii) The identification of the person who collected the sample and 
the person who performed the testing;
    (iii) The results of the tests; and
    (iv) The actions taken to stop the sale of any gasoline found not to 
be in compliance, and the actions taken to identify the cause of any 
noncompliance and prevent future instances of noncompliance.
    (b) Refiners and importers. In addition to other requirements of 
this section, any refiner and importer shall, for all reformulated 
gasoline and RBOB produced or imported, maintain records containing the 
following information:
    (1) Results of the tests to determine reformulated gasoline 
properties and characteristics specified in Sec. 80.65;
    (2) Results of the tests for the presence of the marker specified in 
Sec. 80.82;
    (3) The volume of gasoline associated with each of the above test 
results using the method normally employed at the refinery or import 
facility for this purpose;
    (4) In the case of RBOB:
    (i) The results of tests to ensure that, following blending, RBOB 
meets applicable standards; and
    (ii) Each contract with each oxygenate blender to whom the refiner 
or importer transfers RBOB; or

[[Page 564]]

    (iii) Compliance calculations described in Sec. 80.69(a)(8) based on 
an assumed addition of oxygenate;
    (5) In the case of any refinery or importer subject to the simple 
model standards, the calculations used to determine the 1990 baseline 
levels of sulfur, T-90, and olefins, and the calculations used to 
determine compliance with the standards for these parameters; and
    (6) In the case of any refinery or importer subject to the complex 
model standards before January 1, 1998, the calculations used to 
determine the baseline levels of VOC, toxics, and NOx emissions 
performance.
    (c) Refiners, importers and oxygenate blenders of averaged gasoline. 
In addition to other requirements of this section, any refiner, 
importer, and oxygenate blender who produces or imports any reformulated 
gasoline for which compliance with one or more applicable standard is 
determined on average shall maintain records containing the following 
information:
    (1) The calculations used to determine compliance with the relevant 
standards on average, for each averaging period and for each quantity of 
gasoline for which standards must be separately achieved; and
    (2) For any credits bought, sold, traded or transferred pursuant to 
Sec. 80.67(h), the dates of the transactions, the names and EPA 
registration numbers of the parties involved, and the number(s) and 
type(s) of credits transferred.
    (d) Oxygenate blenders. In addition to other requirements of this 
section, any oxygenate blender who blends any oxygenate with any RBOB 
shall, for each occasion such terminal storage tank blending occurs, 
maintain records containing the following information:
    (i) The date, time, location, and identification of the blending 
tank or truck in which the blending occurred;
    (ii) The volume and oxygenate requirements of the RBOB to which 
oxygenate was added; and
    (iii) The volume, type, and purity of the oxygenate which was added, 
and documents which show the source(s) of the oxygenate used.
    (e) Distributors who dispense RBOB into trucks. In addition to other 
requirements of this section, any distributor who dispenses any RBOB 
into a truck used for delivering gasoline to retail outlets shall, for 
each occasion RBOB is dispensed into such a truck, obtain records 
identifying:
    (1) The name and EPA registration number of the oxygenate blender 
that received the RBOB; and
    (2) The volume and oxygenate requirements of the RBOB dispensed.
    (f) Conventional gasoline requirement. In addition to other 
requirements of this section, any refiner and importer shall, for all 
conventional gasoline produced or imported, maintain records showing the 
blending of the marker required under Sec. 80.82 into conventional 
gasoline, and the results of the tests showing the concentration of this 
marker subsequent to its addition.
    (g) Retailers before January 1, 1998. Prior to January 1, 1998 any 
retailer that sells or offers for sale any reformulated gasoline shall 
maintain at each retail outlet the product transfer documentation for 
the most recent three deliveries to the retail outlet of each grade of 
reformulated gasoline sold or offered for sale at the retail outlet, and 
shall make such documentation available to any person conducting any 
gasoline compliance survey pursuant to Sec. 80.68.



Sec. 80.75  Reporting requirements.

    Any refiner, importer, and oxygenate blender shall report as 
specified in this section, and shall report such other information as 
the Administrator may require.
    (a) Quarterly reports for reformulated gasoline. Any refiner or 
importer that produces or imports any reformulated gasoline or RBOB, and 
any oxygenate blender that produces reformulated gasoline meeting the 
oxygen standard on average, shall submit quarterly reports to the 
Administrator for each refinery or oxygenate blending facility at which 
such reformulated gasoline or RBOB was produced and for all such 
reformulated gasoline or RBOB imported by each importer.
    (1) The quarterly reports shall be for all such reformulated 
gasoline or RBOB produced or imported during the following time periods:

[[Page 565]]

    (i) The first quarterly report shall include information for 
reformulated gasoline or RBOB produced or imported from January 1 
through March 31, and shall be submitted by May 31 of each year 
beginning in 1995;
    (ii) The second quarterly report shall include information for 
reformulated gasoline or RBOB produced or imported from April 1 through 
June 30, and shall be submitted by August 31 of each year beginning in 
1995;
    (iii) The third quarterly report shall include information for 
reformulated gasoline or RBOB produced or imported from July 1 through 
September 30, and shall be submitted by November 30 of each year 
beginning in 1995; and
    (iv) The fourth quarterly report shall include information for 
reformulated gasoline or RBOB produced or imported from October 1 
through December 31, and shall be submitted by the last day of February 
of each year beginning in 1996.
    (2) The following information shall be included in each quarterly 
report for each batch of reformulated gasoline or RBOB which is included 
under paragraph (a)(1) of this section:
    (i) The batch number;
    (ii) The date of production;
    (iii) The volume of the batch;
    (iv) The grade of gasoline produced (i.e., premium, mid-grade, or 
regular);
    (v) For any refiner or importer:
    (A) Each designation of the gasoline, pursuant to Sec. 80.65; and
    (B) The properties, pursuant to Secs. 80.65 and 80.66;
    (vi) For any importer, the PADD in which the import facility is 
located; and
    (vii) For any oxygenate blender, the oxygen content.
    (3) Information pertaining to gasoline produced or imported during 
1994 shall be included in the first quarterly report in 1995.
    (b) Reports for gasoline or RBOB produced or imported under the 
simple model--(1) RVP averaging reports. (i) Any refiner or importer 
that produced or imported any reformulated gasoline or RBOB under the 
simple model that was to meet RVP standards on average (``averaged 
reformulated gasoline'') shall submit to the Administrator, with the 
third quarterly report, a report for each refinery or importer for such 
averaged reformulated gasoline or RBOB produced or imported during the 
previous RVP averaging period. This information shall be reported 
separately for the following categories:
    (A) Gasoline or RBOB which is designated as VOC-controlled intended 
for areas in VOC-Control Region 1; and
    (B) Gasoline or RBOB which is designated as VOC-controlled intended 
for VOC-Control Region 2.
    (ii) The following information shall be reported:
    (A) The total volume of averaged reformulated gasoline or RBOB in 
gallons;
    (B) The compliance total value for RVP; and
    (C) The actual total value for RVP.
    (2) Sulfur, olefins and T90 averaging reports. (i) Any refiner or 
importer that produced or imported any reformulated gasoline or RBOB 
under the simple model shall submit to the Administrator, with the 
fourth quarterly report, a report for such reformulated gasoline or RBOB 
produced or imported during the previous year:
    (A) For each refinery or importer; or
    (B) In the case of refiners who operate more than one refinery, for 
each grouping of refineries as designated by the refiner pursuant to 
Sec. 80.41(h)(2)(iii).
    (ii) The following information shall be reported:
    (A) The total volume of reformulated gasoline or RBOB in gallons;
    (B) The applicable sulfur content standard under Sec. 80.41(h)(2)(i) 
in parts per million;
    (C) The average sulfur content in parts per million;
    (D) The difference between the applicable sulfur content standard 
under Sec. 80.41(h)(2)(i) in parts per million and the average sulfur 
content under paragraph (b)(2)(ii)(C) of this section in parts per 
million, indicating whether the average is greater or lesser than the 
applicable standard;
    (E) The applicable olefin content standard under Sec. 80.41(h)(2)(i) 
in volume percent;
    (F) The average olefin content in volume percent;
    (G) The difference between the applicable olefin content standard 
under Sec. 80.41(h)(2)(i) in volume percent and

[[Page 566]]

the average olefin content under paragraph (b)(2)(ii)(F) of this section 
in volume percent, indicating whether the average is greater or lesser 
than the applicable standard;
    (H) The applicable T90 distillation point standard under 
Sec. 80.41(h)(2)(i) in degrees Fahrenheit;
    (I) The average T90 distillation point in degrees Fahrenheit; and
    (J) The difference between the applicable T90 distillation point 
standard under Sec. 80.41(h)(2)(i) in degrees Fahrenheit and the average 
T90 distillation point under paragraph (b)(2)(ii)(I) of this section in 
degrees Fahrenheit, indicating whether the average is greater or lesser 
than the applicable standard.
    (c) VOC emissions performance averaging reports. (1) Any refiner or 
importer that produced or imported any reformulated gasoline or RBOB 
under the complex model that was to meet the VOC emissions performance 
standards on average (``averaged reformulated gasoline'') shall submit 
to the Administrator, with the third quarterly report, a report for each 
refinery or importer for such averaged reformulated gasoline produced or 
imported during the previous VOC averaging period. This information 
shall be reported separately for the following categories:
    (i) Gasoline or RBOB which is designated as VOC-controlled intended 
for areas in VOC-Control Region 1; and
    (ii) Gasoline or RBOB which is designated as VOC-controlled intended 
for VOC-Control Region 2.
    (2) The following information shall be reported:
    (i) The total volume of averaged reformulated gasoline or RBOB in 
gallons;
    (ii) The compliance total value for VOC emissions performance; and
    (iii) The actual total value for VOC emissions performance.
    (d) Benzene content averaging reports. (1) Any refiner or importer 
that produced or imported any reformulated gasoline or RBOB that was to 
meet the benzene content standards on average (``averaged reformulated 
gasoline'') shall submit to the Administrator, with the fourth quarterly 
report, a report for each refinery or importer for such averaged 
reformulated gasoline that was produced or imported during the previous 
toxics averaging period.
    (2) The following information shall be reported:
    (i) The volume of averaged reformulated gasoline or RBOB in gallons;
    (ii) The compliance total content of benzene;
    (iii) The actual total content of benzene;
    (iv) The number of benzene credits generated as a result of actual 
total benzene being less than compliance total benzene;
    (v) The number of benzene credits required as a result of actual 
total benzene being greater than compliance total benzene;
    (vi) The number of benzene credits transferred to another refinery 
or importer; and
    (vii) The number of benzene credits obtained from another refinery 
or importer.
    (e) Toxics emissions performance averaging reports. (1) Any refiner 
or importer that produced or imported any reformulated gasoline or RBOB 
that was to meet the toxics emissions performance standards on average 
(``averaged reformulated gasoline'') shall submit to the Administrator, 
with the fourth quarterly report, a report for each refinery or importer 
for such averaged reformulated gasoline that was produced or imported 
during the previous toxics averaging period.
    (2) The following information shall be reported:
    (i) The volume of averaged reformulated gasoline or RBOB in gallons;
    (ii) The compliance value for toxics emissions performance; and
    (iii) The actual value for toxics emissions performance.
    (f) Oxygen averaging reports. (1) Any refiner, importer, or 
oxygenate blender that produced or imported any reformulated gasoline 
that was to meet the oxygen standards on average (``averaged 
reformulated gasoline'') shall submit to the Administrator, with the 
fourth quarterly report, a report for each refinery and oxygenate 
blending facility at which such averaged reformulated gasoline was 
produced and for all such averaged reformulated gasoline imported by 
each importer during the previous oxygen averaging period.

[[Page 567]]

    (2)(i) The following information shall be included in each report 
required by paragraph (f)(1) of this section:
    (A) The total volume of averaged RBOB in gallons;
    (B) The total volume of averaged reformulated gasoline in gallons;
    (C) The compliance total content for oxygen;
    (D) The actual total content for oxygen;
    (E) The number of oxygen credits generated as a result of actual 
total oxygen being greater than compliance total oxygen;
    (F) The number of oxygen credits required as a result of actual 
total oxygen being less than compliance total oxygen;
    (G) The number of oxygen credits transferred to another refinery, 
importer, or oxygenate blending facility; and
    (H) The number of oxygen credits obtained from another refinery, 
importer, or oxygenate blending facility.
    (ii) The information required by paragraph (f)(2)(i) of this section 
shall be reported separately for the following categories:
    (A) For gasoline subject to the simple model standards:
    (1) Gasoline which is designated as VOC-controlled and oxygenated 
fuels program reformulated gasoline (OPRG);
    (2) Gasoline which is designated as VOC-controlled and non-OPRG;
    (3) Gasoline which is designated as non-VOC-controlled and OPRG; and
    (4) Gasoline which is designated as non-VOC-controlled and non-OPRG; 
and
    (B) For gasoline subject to the Phase I or Phase II complex model 
standards:
    (1) Gasoline which is designated as OPRG; and
    (2) Gasoline which is designated as non-OPRG.
    (iii) The results of the compliance calculations required in 
Sec. 80.67(f) shall also be included in each report required by 
paragraph (f)(1) of this section, for each of the following categories:
    (A) All reformulated gasoline;
    (B) Gasoline which is designated as non-OPRG; and
    (C) For gasoline subject to the simple model standards, gasoline 
which is designated as VOC-controlled.
    (g) NOX emissions performance averaging reports. (1) Any 
refiner or importer that produced or imported any reformulated gasoline 
or RBOB that was to meet the NOX emissions performance standard on 
average (``averaged reformulated gasoline'') shall submit to the 
Administrator, with the fourth quarterly report, a report for each 
refinery or importer for such averaged reformulated gasoline that was 
produced or imported during the previous NOX averaging period.
    (2) The following information shall be reported:
    (i) The volume of averaged reformulated gasoline or RBOB in gallons;
    (ii) The compliance value for NOX emissions performance; and
    (iii) The actual value for NOX emissions performance.
    (3) The information required by paragraph (g)(2) of this section 
shall be reported separately for the following categories:
    (i) Gasoline and RBOB which is designated as VOC-controlled; and
    (ii) Gasoline and RBOB which is not designated as VOC-controlled.
    (h) Credit transfer reports. (1) As an additional part of the fourth 
quarterly report required by this section, any refiner, importer, and 
oxygenate blender shall, for each refinery, importer, or oxygenate 
blending facility, supply the following information for any oxygen or 
benzene credits that are transferred from or to another refinery, 
importer, or oxygenate blending facility:
    (i) The names, EPA-assigned registration numbers and facility 
identification numbers of the transferor and transferee of the credits;
    (ii) The number(s) and type(s) of credits that were transferred; and
    (iii) The date(s) of transaction(s).
    (2) For purposes of this paragraph (h), oxygen credit transfers 
shall be reported separately for each of the following oxygen credit 
types:
    (i) For gasoline subject to the simple model standards:
    (A) VOC controlled, oxygenated fuels program reformulated gasoline 
(OPRG) oxygen credits;

[[Page 568]]

    (B) VOC controlled, non-OPRG oxygen credits;
    (C) Non-VOC controlled, OPRG oxygen credits; and
    (D) Non-VOC controlled, non-OPRG oxygen credits; and
    (ii) For gasoline subject to the Phase I or Phase II complex model 
standards:
    (A) OPRG oxygen credits; and
    (B) Non-OPRG oxygen credits.
    (i) Covered areas of gasoline use report. Any refiner or oxygenate 
blender that produced or imported any reformulated gasoline that was to 
meet any reformulated gasoline standard on average (``averaged 
reformulated gasoline'') shall, for each refinery and oxygenate blending 
facility at which such averaged reformulated gasoline was produced 
submit to the Administrator, with the fourth quarterly report, a report 
that contains the identity of each covered area that was supplied with 
any averaged reformulated gasoline produced at each refinery or blended 
by each oxygenate blender during the previous year.
    (j) Additional reporting requirements for certain importers. In the 
case of any importer to whom different standards apply for gasoline 
imported at different facilities by operation of Sec. 80.41(q)(2), such 
importer shall submit separate reports for gasoline imported into 
facilities subject to different standards.
    (k) Reporting requirements for early use of the complex model. Any 
refiner for any refinery, or any importer, that elects to be subject to 
complex model standards under Sec. 80.41(i)(1) shall report such 
election in writing to the Administrator no later than sixty days prior 
to the beginning of the calendar year during which such standards would 
apply. This report shall include the refinery's or importer's baseline 
values for VOC, NOX, and toxics emissions performance, in 
milligrams per mile.
    (l) Reports for per-gallon compliance gasoline. In the case of 
reformulated gasoline or RBOB for which compliance with each of the 
standards set forth in Sec. 80.41 is achieved on a per-gallon basis, the 
refiner, importer, or oxygenate blender shall submit to the 
Administrator, by the last day of February of each year beginning in 
1996, a report of the volume of each designated reformulated gasoline or 
RBOB produced or imported during the previous calendar year for which 
compliance is achieved on a per-gallon basis, and a statement that each 
gallon of this reformulated gasoline or RBOB met the applicable 
standards.
    (m) Reports of compliance audits. Any refiner, importer, and 
oxygenate blender shall cause to be submitted to the Administrator, by 
May 31 of each year, the report of the compliance audit required by 
Sec. 80.65(h).
    (n) Report submission. The reports required by this section shall 
be:
    (1) Submitted on forms and following procedures specified by the 
Administrator; and
    (2) Signed and certified as correct by the owner or a responsible 
corporate officer of the refiner, importer, or oxygenate blender.

[59 FR 7813, Feb. 16, 1994, as amended at 59 FR 36964, July 20, 1994; 60 
FR 65574, Dec. 20, 1995]



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

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

[[Page 569]]

blending facility, or in the case of importers, the registered address;
    (ii) If records are kept off-site, the primary off-site storage 
facility name, physical location, contact name, and telephone number; 
and
    (iii) The name, address, contact name and telephone number of the 
independent laboratory used to meet the independent analysis 
requirements of Sec. 80.65(f).
    (d) EPA will supply a registration number to each refiner, importer, 
and oxygenate blender, and a facility registration number for each 
refinery and oxygenate blending facility that is identified, which shall 
be used in all reports to the Administrator.
    (e)(1) Any refiner, importer, or oxygenate blender shall submit 
updated registration information to the Administrator within thirty days 
of any occasion when the registration information previously supplied 
becomes incomplete or inaccurate; except that
    (2) EPA must be notified in writing of any change in designated 
independent laboratory at least thirty days in advance of such change.

[59 FR 7813, Feb. 16, 1994, as amended at 59 FR 36965, July 20, 1994]



Sec. 80.77  Product transfer documentation.

    On each occasion when any person transfers custody or title to any 
reformulated gasoline or RBOB, other than when gasoline is sold or 
dispensed for use in motor vehicles at a retail outlet or wholesale 
purchaser-consumer facility, the transferor shall provide to the 
transferee documents which include the following information:
    (a) The name and address of the transferor;
    (b) The name and address of the transferee;
    (c) The volume of gasoline which is being transferred;
    (d) The location of the gasoline at the time of the transfer;
    (e) The date of the transfer;
    (f) The proper identification of the gasoline as conventional or 
reformulated;
    (g) In the case of reformulated gasoline or RBOB:
    (1) The proper identification as:
    (i)(A) VOC-controlled for VOC-Control Region 1; or VOC-controlled 
for VOC-Control Region 2; or Not VOC-controlled; or
    (B) In the case of gasoline or RBOB that is VOC-controlled for VOC-
Control Region 1, the gasoline may be identified as suitable for use 
either in VOC-Control Region 1 or VOC-Control Region 2;
    (ii) Oxygenated fuels program reformulated gasoline; or Not 
oxygenated fuels program reformulated gasoline; and
    (iii) Prior to January 1, 1998, certified under the simple model 
standards or certified under the complex model standards; and
    (2) The minimum and/or maximum standards with which the gasoline or 
RBOB conforms for:
    (i) Benzene content;
    (ii) Except for RBOB, oxygen content;
    (iii) In the case of VOC-controlled gasoline subject to the simple 
model standards, RVP;
    (iv) In the case of gasoline subject to the complex model standards:
    (A) Prior to January 1, 1998, the NOx emissions performance minimum, 
and for VOC-controlled gasoline the VOC emissions performance minimum, 
in milligrams per mile; and
    (B) Beginning on January 1, 1998, the NOx emissions performance 
minimum, and for VOC-controlled gasoline the VOC emissions performance 
minimum; and
    (3) Identification of VOC-controlled reformulated gasoline or RBOB 
as gasoline or RBOB which contains ethanol, or which does not contain 
any ethanol.
    (h) Prior to January 1, 1998, in the case of reformulated gasoline 
or RBOB subject to the complex model standards:
    (1) The name and EPA registration number of the refinery at which 
the gasoline was produced, or importer that imported the gasoline; and
    (2) Instructions that the gasoline or RBOB may not be combined with 
any other gasoline or RBOB that was produced at any other refinery or 
was imported by any other importer;
    (i) In the case of reformulated gasoline blendstock for which 
oxygenate blending is intended:

[[Page 570]]

    (1) Identification of the product as RBOB and not reformulated 
gasoline;
    (2) The designation of the RBOB as suitable for blending with:
    (A) Any-oxygenate;
    (B) Ether-only; or
    (C) Other specified oxygenate type(s) and amount(s); and
    (3) The oxygenate type(s) and amount(s) which the RBOB requires in 
order to meet the properties claimed by the refiner or importer of the 
RBOB;
    (4) Instructions that the RBOB may not be combined with any other 
RBOB except other RBOB having the same requirements for oxygenate 
type(s) and amount(s), or, prior to blending, with reformulated 
gasoline; and
    (j) In the case of transferrers or transferees who are refiners, 
importers or oxygenate blenders, the EPA-assigned registration number of 
those persons.

[59 FR 7813, Feb. 16, 1994, as amended at 59 FR 36965, July 20, 1994]



Sec. 80.78  Controls and prohibitions on reformulated gasoline.

    (a) Prohibited activities. (1) No person may manufacture and sell or 
distribute, offer for sale or distribution, dispense, supply, offer for 
supply, store, transport, or cause the transportation of any gasoline 
represented as reformulated and intended for sale or use in any covered 
area:
    (i) Unless each gallon of such gasoline meets the applicable benzene 
maximum standard specified in Sec. 80.41;
    (ii) Unless each gallon of such gasoline meets the applicable oxygen 
content:
    (A) Minimum standard specified in Sec. 80.41; and
    (B) In the case of gasoline subject to simple model standards, 
maximum standard specified in Sec. 80.41;
    (iii) Unless each gallon is properly designated as oxygenated fuels 
program reformulated gasoline, within any oxygenated gasoline program 
control areas during the oxygenated gasoline control period;
    (iv) Unless the product transfer documentation for such gasoline 
complies with the requirements in Sec. 80.77; and
    (v) During the period May 1 through September 15 for all persons 
except retailers and wholesale purchaser-consumers, and during the 
period June 1 through September 15 for all persons including retailers 
and wholesale purchaser-consumers:
    (A) Unless each gallon of such gasoline is VOC-controlled for the 
proper VOC Control Region, except that gasoline designated for VOC-
Control Region 1 may be used in VOC-Control Region 2;
    (B) Unless each gallon of such gasoline that is subject to simple 
model standards has an RVP which is less than or equal to the applicable 
RVP maximum specified in Sec. 80.41;
    (C) Unless each gallon of such gasoline that is subject to complex 
model standards has a VOC and NOx emissions reduction percentage which 
is greater than or equal to the applicable minimum specified in 
Sec. 80.41.
    (2) No refiner or importer may produce or import any gasoline 
represented as reformulated or RBOB, and intended for sale or use in any 
covered area:
    (i) Unless such gasoline meets the definition of reformulated 
gasoline or RBOB; and
    (ii) Unless the properties of such gasoline or RBOB correspond to 
the product transfer documents.
    (3) No person may manufacture and sell or distribute, or offer for 
sale or distribution, dispense, supply, or offer for supply, store, 
transport or cause the transportation of gasoline represented as 
conventional which does not contain at least the minimum concentration 
of the conventional gasoline marker specified in Sec. 80.82.
    (4) Gasoline shall be presumed to be intended for sale or use in a 
covered area unless:
    (i) Product transfer documentation as described in Sec. 80.77 
accompanying such gasoline clearly indicates the gasoline is intended 
for sale and use only outside any covered area; or
    (ii) The gasoline is contained in the storage tank of a retailer or 
wholesale purchaser-consumer outside any covered area.
    (5) No person may combine any reformulated gasoline with any non-
oxygenate blendstock except:
    (i) A person that meets each requirement specified for a refiner 
under this subpart; and

[[Page 571]]

    (ii) The blendstock that is added to reformulated gasoline meets all 
reformulated gasoline standards without regard to the properties of the 
reformulated gasoline to which the blendstock is added.
    (6) No person may add any oxygenate to reformulated gasoline, except 
that oxygenate may be added to reformulated gasoline that is designated 
as OPRG provided that such gasoline is used in an oxygenated fuels 
program control area during an oxygenated fuels control period.
    (7) No person may combine any reformulated gasoline blendstock for 
oxygenate blending with any other gasoline, blendstock, or oxygenate 
except:
    (i) Oxygenate of the type and amount (or within the range of 
amounts) specified by the refiner or importer at the time the RBOB was 
produced or imported; or
    (ii) Other RBOB for which the same oxygenate type and amount (or 
range of amounts) was specified by the refiner or importer.
    (8) No person may combine any VOC-controlled reformulated gasoline 
that is produced using ethanol with any VOC-controlled reformulated 
gasoline that is produced using any other oxygenate during the period 
January 1 through September 15.
    (9) Prior to January 1, 1998:
    (i) No person may combine any reformulated gasoline or RBOB that is 
subject to the simple model standards with any reformulated gasoline or 
RBOB that is subject to the complex model standards, except that such 
gasolines may be combined at a retail outlet or wholesale purchaser-
consumer facility;
    (ii) No person may combine any reformulated gasoline subject to the 
complex model standards that is produced at any refinery or is imported 
by any importer with any other reformulated gasoline that is produced at 
a different refinery or is imported by a different importer, unless the 
other refinery or importer has an identical baseline for meeting complex 
model standards during this period; and
    (iii) No person may combine any RBOB subject to the complex model 
standards that is produced at any refinery or is imported by any 
importer with any RBOB that is produced at a different refinery or is 
imported by a different importer, unless the other refinery or importer 
has an identical baseline for meeting complex model standards during 
this period.
    (10) No person may combine any reformulated gasoline with any 
conventional gasoline and sell the resulting mixture as reformulated 
gasoline.
    (b) Liability. Liability for violations of paragraph (a) of this 
section shall be determined according to the provisions of Sec. 80.79.
    (c) Determination of compliance. Compliance with the standards 
listed in paragraph (a) of this section shall be determined by use of 
one of the testing methodologies specified in Sec. 80.46, except that 
where test results using the testing methodologies specified in 
Sec. 80.46 are not available or where such test results are available 
but are in question, EPA may establish noncompliance with standards 
using any information, including the results of testing using methods 
that are not included in Sec. 80.46.
    (d) Dates controls and prohibitions begin. The controls and 
prohibitions specified in paragraph (a) of this section apply at any 
location other than retail outlets and wholesale purchaser-consumer 
facilities on or after December 1, 1994, at any location on or after 
January 1, 1995.

[59 FR 7813, Feb. 16, 1994, as amended at 59 FR 36965, July 20, 1994]



Sec. 80.79  Liability for violations of the prohibited activities.

    (a) Persons liable. Where the gasoline contained in any storage tank 
at any facility owned, leased, operated, controlled or supervised by any 
refiner, importer, oxygenate blender, carrier, distributor, reseller, 
retailer, or wholesale purchaser-consumer is found in violation of the 
prohibitions described in Sec. 80.78(a), the following persons shall be 
deemed in violation:
    (1) Each refiner, importer, oxygenate blender, carrier, distributor, 
reseller, retailer, or wholesale purchaser-consumer who owns, leases, 
operates, controls or supervises the facility where the violation is 
found;
    (2) Each refiner or importer whose corporate, trade, or brand name, 
or

[[Page 572]]

whose marketing subsidiary's corporate, trade, or brand name, appears at 
the facility where the violation is found;
    (3) Each refiner, importer, oxygenate blender, distributor, and 
reseller who manufactured, imported, sold, offered for sale, dispensed, 
supplied, offered for supply, stored, transported, or caused the 
transportation of any gasoline which is in the storage tank containing 
gasoline found to be in violation; and
    (4) Each carrier who dispensed, supplied, stored, or transported any 
gasoline which is in the storage tank containing gasoline found to be in 
violation, provided that EPA demonstrates, by reasonably specific 
showings by direct or circumstantial evidence, that the carrier caused 
the violation.
    (b) Defenses for prohibited activities. (1) In any case in which a 
refiner, importer, oxygenate blender, carrier, distributor, reseller, 
retailer, or wholesale purchaser-consumer would be in violation under 
paragraph (a) of this section, it shall be deemed not in violation if it 
can demonstrate:
    (i) That the violation was not caused by the regulated party or its 
employee or agent;
    (ii) That product transfer documents account for all of the gasoline 
in the storage tank found in violation and indicate that the gasoline 
met relevant requirements; and
    (iii)(A) That it has conducted a quality assurance sampling and 
testing program, as described in paragraph (c) of this section; except 
that
    (B) A carrier may rely on the quality assurance program carried out 
by another party, including the party that owns the gasoline in 
question, provided that the quality assurance program is carried out 
properly.
    (2)(i) Where a violation is found at a facility which is operating 
under the corporate, trade or brand name of a refiner, that refiner must 
show, in addition to the defense elements required by paragraph (b)(1) 
of this section, that the violation was caused by:
    (A) An act in violation of law (other than the Act or this part), or 
an act of sabotage or vandalism;
    (B) The action of any reseller, distributor, oxygenate blender, 
carrier, or a retailer or wholesale purchaser- consumer supplied by any 
of these persons, in violation of a contractual undertaking imposed by 
the refiner designed to prevent such action, and despite periodic 
sampling and testing by the refiner to ensure compliance with such 
contractual obligation; or
    (C) The action of any carrier or other distributor not subject to a 
contract with the refiner but engaged by the refiner for transportation 
of gasoline, despite specification or inspection of procedures and 
equipment by the refiner which are reasonably calculated to prevent such 
action.
    (ii) In this paragraph (b), to show that the violation ``was 
caused'' by any of the specified actions the party must demonstrate by 
reasonably specific showings, by direct or circumstantial evidence, that 
the violation was caused or must have been caused by another.
    (c) Quality assurance program. In order to demonstrate an acceptable 
quality assurance program for reformulated gasoline at all points in the 
gasoline distribution network, other than at retail outlets and 
wholesale purchaser-consumer facilities, a party must present evidence:
    (1) Of a periodic sampling and testing program to determine if the 
applicable maximum and/or minimum standards for oxygen, benzene, RVP, or 
VOC or NOX emission performance are met; and
    (2) That on each occasion when gasoline is found in noncompliance 
with one of the requirements referred to in paragraph (c)(1) of this 
section:
    (i) The party immediately ceases selling, offering for sale, 
dispensing, supplying, offering for supply, storing, transporting, or 
causing the transportation of the violating product; and
    (ii) The party promptly remedies the violation (such as by removing 
the violating product or adding more complying product until the 
applicable standards are achieved).



Sec. 80.80  Penalties.

    (a) Any person that violates any requirement or prohibition of 
subpart D, E, or F of this part shall be liable to the United States for 
a civil penalty of not more than the sum of $25,000 for every day of 
each such violation and

[[Page 573]]

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

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

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

[[Page 574]]



Sec. 80.81  Enforcement exemptions for California gasoline.

    (a)(1) The requirements of subparts D, E, and F of this part are 
modified in accordance with the provisions contained in this section in 
the case of California gasoline.
    (2) For the purposes of this section, ``California gasoline'' means 
any gasoline that is sold, intended for sale, or made available for sale 
as a motor vehicle fuel in the State of California and that:
    (i) Is manufactured within the State of California;
    (ii) Is imported into the State of California from outside the 
United States; or
    (iii) Is imported into the State of California from inside the 
United States and that is manufactured at a refinery that does not 
produce reformulated gasoline for sale in any covered area outside the 
State of California.
    (b)(1) Any refiner, importer, or oxygenate blender of gasoline that 
is sold, intended for sale, or made available for sale as a motor fuel 
in the State of California is, with regard to such gasoline, exempt from 
the compliance survey provisions contained in Sec. 80.68.
    (2) Any refiner, importer, or oxygenate blender of California 
gasoline is, with regard to such gasoline, exempt from the independent 
analysis requirements contained in Sec. 80.65(f).
    (3) Any refiner, importer, or oxygenate blender of California 
gasoline that elects to meet any benzene content, oxygen content, or 
toxics emission reduction standard specified in Sec. 80.41 on average 
for any averaging period specified in Sec. 80.67 that is in part before 
March 1, 1996, and in part subsequent to such date, shall, with regard 
to such gasoline that is produced or imported prior to such date, 
demonstrate compliance with each of the standards specified in 
Sec. 80.41 for each of the following averaging periods in lieu of those 
specified in Sec. 80.67:
    (i) January 1 through December 31, 1995; and
    (ii) March 1, 1995, through February 29, 1996.
    (4) The compliance demonstration required by paragraph (b)(3)(ii) of 
this section shall be submitted no later than May 31, 1996, along with 
the report for the first quarter of 1996 required to be submitted under 
Sec. 80.75(a)(1)(i).
    (c) Any refiner, importer, or oxygenate blender of California 
gasoline that is manufactured or imported subsequent to March 1, 1996, 
and that meets the requirements of the California Phase 2 reformulated 
gasoline regulations, as set forth in Title 13, California Code of 
Regulations, sections 2260 et seq., is, with regard to such gasoline, 
exempt from the following requirements (in addition to the requirements 
specified in paragraph (b) of this section):
    (1) The parameter value reconciliation requirements contained in 
Sec. 80.65(e)(2);
    (2) The designation of gasoline requirements contained in 
Sec. 80.65(d), except in the case of RBOB that is designated as ``any 
renewable oxygenate,'' ``non-VOC controlled renewable ether only'', or 
``renewable ether only'';
    (3) The reformulated gasoline and RBOB compliance requirements 
contained in Sec. 80.65(c);
    (4) The marking of conventional gasoline requirements contained in 
Secs. 80.65(g) and 80.82;
    (5) The annual compliance audit requirements contained in 
Sec. 80.65(h), except where such audits are required with regard to the 
renewable oxygenate requirements contained in Sec. 80.83;
    (6) The downstream oxygenate blending requirements contained in 
Sec. 80.69, except where such requirements apply to the renewable 
oxygenate requirements contained in Sec. 80.83;
    (7) The record keeping requirements contained in Secs. 80.74 and 
80.104, except that records required to be maintained under Title 13, 
California Code of Regulations, section 2270, shall be maintained for a 
period of five years from the date of creation and shall be delivered to 
the Administrator or to the Administrator's authorized representative 
upon request;
    (8) The reporting requirements contained in Secs. 80.75 and 80.105;
    (9) The product transfer documentation requirements contained in 
Sec. 80.77; and

[[Page 575]]

    (10) The compliance attest engagement requirements contained in 
subpart F of this part, except where such requirements apply to the 
renewable oxygenate requirements contained in Sec. 80.83.
    (d) Any refiner, importer, or oxygenate blender that produces or 
imports gasoline that is sold, intended for sale, or made available for 
sale as a motor vehicle fuel in the State of California subsequent to 
March 1, 1996, shall demonstrate compliance with the standards specified 
in Secs. 80.41 and 80.90 by excluding the volume and properties of such 
gasoline from all conventional gasoline and reformulated gasoline that 
it produces or imports that is not sold, intended for sale, or made 
available for sale as a motor vehicle fuel in the State of California 
subsequent to such date. The exemption provided in this section does not 
exempt any refiner or importer from demonstrating compliance with such 
standards for all gasoline that it produces or imports.
    (e)(1) The exemption provisions contained in paragraphs (b)(2), 
(b)(3), and (c) of this section shall not apply under the circumstances 
set forth in paragraphs (e)(2) and (e)(3) of this section.
    (2)(i) Such exemption provisions shall not apply to any refiner, 
importer, or oxygenate blender of California gasoline if any gasoline 
formulation that it produces or imports is certified under Title 13, 
California Code of Regulations, section 2265 or section 2266, unless 
such refiner, importer, or oxygenate blender within 30 days of the 
issuance of such certification:
    (A) Notifies the Administrator of such certification;
    (B) Submits to the Administrator copies of the applicable 
certification order issued by the State of California and of the 
application for certification submitted by the regulated party to the 
State of California; and
    (C) Submits to the Administrator a written demonstration that the 
certified gasoline formulation meets each of the complex model per-
gallon standards specified in Sec. 80.41(c).
    (ii) If the Administrator determines that the written demonstration 
submitted under paragraph (e)(2)(i)(C) of this section does not 
demonstrate that the certified gasoline formulation meets each of the 
complex model per-gallon standards specified in Sec. 80.41(c), the 
Administrator shall provide notice to the party (by first class mail) of 
such determination and of the date on which the exemption provisions 
specified in paragraph (e)(1) of this section shall no longer be 
applicable, which date shall be no earlier than 90 days after the date 
of the Administrator's notification.
    (3)(i) Such exemption provisions shall not apply to any refiner, 
importer, or oxygenate blender of California gasoline who has been 
assessed a civil, criminal or administrative penalty for a violation of 
subpart D, E or F of this part or for a violation of the California 
Phase 2 reformulated gasoline regulations set forth in Title 13, 
California Code of Regulations, sections 2260 et seq., effective 90 days 
after the date of final agency or district court adjudication of such 
penalty assessment.
    (ii) Any refiner, importer, or oxygenate blender subject to the 
provisions of paragraph (e)(3)(i) of this section may submit a petition 
to the Administrator for relief, in whole or in part, from the 
applicability of such provisions, for good cause. Good cause may include 
a showing that the violation for which a penalty was assessed was not a 
substantial violation of the federal or California reformulated gasoline 
regulations.
    (f) In the case of any gasoline that is sold, intended for sale, or 
made available for sale as a motor vehicle fuel in the State of 
California subsequent to March 1, 1996, any person that manufactures, 
sells, offers for sale, dispenses, supplies, offers for supply, stores, 
transports, or causes the transportation of such gasoline is, with 
regard to such gasoline, exempt from the following prohibited activities 
provisions:
    (1) The oxygenated fuels provisions contained in 
Sec. 80.78(a)(1)(iii);
    (2) The product transfer provisions contained in 
Sec. 80.78(a)(1)(iv);
    (3) The oxygenate blending provisions contained in Sec. 80.78(a)(7); 
and
    (4) The segregation of simple and complex model certified gasoline 
provision contained in Sec. 80.78(a)(9).
    (g)(1) Any refiner that operates a refinery located outside the 
State of

[[Page 576]]

California at which California gasoline (as defined in paragraph 
(a)(2)(iii) of this section) is produced shall, with regard to such 
gasoline, provide to any person to whom custody or title of such 
gasoline is transferred, and each transferee shall provide to any 
subsequent transferee, documents which include the following 
information:
    (i) The name and address of the transferor;
    (ii) The name and address of the transferee;
    (iii) The volume of gasoline which is being transferred;
    (iv) The location of the gasoline at the time of the transfer;
    (v) The date and time of the transfer;
    (vi) The identification of the gasoline as California gasoline; and
    (vii) In the case of transferrors and transferrees who are refiners, 
importers or oxygenate blenders, the EPA- assigned registration number 
of such persons.
    (2) Each refiner and transferee of such gasoline shall maintain 
copies of the product transfer documents required to be provided by 
paragraph (g)(1) of this section for a period of five years from the 
date of creation and shall deliver such documents to the Administrator 
or to the Administrator's authorized representative upon request.
    (h) For purposes of the batch sampling and analysis requirements 
contained in Sec. 80.65(e)(1), any refiner, importer or oxygenate 
blender of California gasoline may, with regard to such gasoline, use a 
sampling and/or analysis methodology prescribed in Title 13, California 
Code of Regulations, sections 2260 et seq., in lieu of any applicable 
methodology specified in Sec. 80.46.
    (i) The exemption provisions contained in this section shall not be 
applicable after December 31, 1999.

[59 FR 7813, Feb. 16, 1994, as amended at 59 FR 36965, July 20, 1994; 59 
FR 39289, Aug. 2, 1994; 59 FR 60715, Nov. 28, 1994]

    Effective Date Note: At 59 FR 39289, Aug. 2, 1994, Sec. 80.81 was 
amended by revising paragraphs (c)(2), (c)(5), (c)(6), and (c)(10) 
effective September 1, 1994. At 59 FR 60715, Nov. 28, 1994, the 
amendment was stayed effective September 13, 1994.
Sec. 80.82  Conventional gasoline marker. [Reserved]



Sec. 80.83  Renewable oxygenate requirements.

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

[[Page 577]]

to be used in the production of gasoline, shall maintain documents that 
state the renewable source of the oxygenate, and shall supply to any 
transferee of the oxygenate documents which state the oxygenate is from 
a renewable source.
    (B) Any person who imports oxygenate that is represented by the 
importer to be renewable oxygenate, as defined in paragraph (a) of this 
section, shall maintain documents, obtained from the person who produced 
the oxygenate, that include a certification signed by the owner or chief 
executive officer of the company that produced the oxygenate that 
states:
    (1) The nature of the feedstock for the oxygenate; and
    (2) A description of the manner in which the oxygenate meets the 
renewable definition under paragraph (a) of this section.
    (iii) No person may represent any oxygenate as renewable unless the 
oxygenate meets the renewable definition under paragraph (a) of this 
section.
    (5) For purposes of this section, an oxygenate shall be considered 
to be derived from non-fossil fuel feedstocks only if the oxygenate is:
    (i) Derived from a source other than petroleum, coal, natural gas, 
or peat; or
    (ii) Derived from a product:
    (A) That was produced using petroleum, coal, natural gas, or peat 
through a substantial transformation of the fossil fuel;
    (B) When the product was initially produced, it was not commonly 
used to generate energy (e.g. automobile tires); and
    (C) The product was sold or transferred for a use other than energy 
generation, and was later treated as a waste product.
    (b) Renewable oxygenate standard. (1) The reformulated gasoline and 
reformulated gasoline produced using RBOB that is produced by any 
refiner at each refinery, or is imported by any importer, shall contain 
a volume of renewable oxygenate such that the reformulated gasoline and 
reformulated gasoline produced using RBOB, on average, has an oxygen 
content from such renewable oxygenate that is equal to or greater than 
0.30 wt% for the period of December 1, 1994 through December 31, 1995, 
and 0.60 wt% beginning on January 1, 1996.
    (2) The averaging period for the renewable oxygenate standard 
specified in paragraph (b)(1) of this section shall be:
    (i) Each calendar year; except that
    (ii)Any reformulated gasoline and RBOB that is produced or imported 
prior to January 1, 1995 shall be averaged with reformulated gasoline 
and RBOB produced or imported during 1995.
    (3)(i) The oxygenate used to meet the standard under paragraph 
(b)(1) of this section may also be used to meet any oxygen standard 
under Sec. 80.41; except that
    (ii) The renewable oxygenate added by a downstream oxygenate blender 
shall not be used by any refiner or importer to meet the oxygen standard 
under Sec. 80.41, except through the transfer of oxygen credits.
    (c) Downstream oxygenate blending using renewable oxygenate. (1) In 
the case of any refiner that produces RBOB, or any importer that imports 
RBOB, the oxygenate that is blended with the RBOB may be included with 
the refiner's or importer's compliance calculations under paragraph (d) 
of this section only if:
    (i) The oxygenate meets the applicable renewable oxygenate 
definition under paragraph (a) of this section; and
    (ii) The refiner or importer meets the downstream oxygenate blending 
oversight requirements specified in Secs. 80.69(a)(6) and (7); or
    (iii)(A) In the case of RBOB designated for ``any renewable 
oxygenate'' the refiner or importer assumes that ethanol will be blended 
with the RBOB;
    (B) In the case of RBOB designated for ``renewable ether only'' or 
``non-VOC controlled renewable ether only ``, the refiner or importer 
assumes that ETBE will be blended with the RBOB; and
    (C) In the case of ``any renewable oxygenate,'' ``non-VOC controlled 
renewable ether only'' and ``renewable ether only RBOB,'' the refiner or 
importer assumes that the volume of oxygenate added will be such that 
the resulting reformulated gasoline will have an oxygen content of 2.0 
wt%.

[[Page 578]]

    (2)(i) No person may combine any oxygenate with RBOB designated as 
``any renewable oxygenate'' unless the oxygenate meets the criteria 
specified in paragraph (a) of this section.
    (ii) No person may combine any oxygenate with RBOB designated as 
``renewable ether only'' or ``non-VOC controlled renewable ether only'' 
unless the oxygenate meets the criteria specified in paragraph (a) of 
this section.
    (d) Compliance calculation. (1) Any refiner for each of its 
refineries, and any importer shall, for each averaging period, determine 
compliance with the renewable oxygenate standard by calculating:
    (i) Prior to January 1, 1996, renewable oxygen compliance total 
using the following formula:
[GRAPHIC] [TIFF OMITTED] TR02AU94.000

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

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

    (iii) The renewable oxygen actual total using the following formula:
    [GRAPHIC] [TIFF OMITTED] TR02AU94.002
    
where
ATro=the actual total for renewable oxygen
Vi=the volume of gasoline or RBOB batch i
ROi=the oxygen content, in wt%, in the form of renewable oxygenate 
of gasoline or RBOB batch i
n=the number of batches of gasoline or RBOB produced or imported during 
the averaging period

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

[[Page 579]]

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

[[Page 580]]

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

[59 FR 39290, Aug. 2, 1994]

    Effective Date Note: At 59 FR 39290, Aug. 2, 1994, Sec. 80.83 was 
added effective September 1, 1994, except for paragraphs (g) and (h), 
which will not become effective until approval has been given by the 
Office of Management and Budget. A document will be published in the 
Federal Register once approval has been obtained. At 59 FR 60715, Nov. 
28, 1994, this section was stayed, effective September 13, 1994.
Secs. 80.84-80.89   [Reserved]



                         Subpart E--Anti-Dumping

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



Sec. 80.90  Conventional gasoline baseline emissions determination.

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


[[Page 581]]


where

BASELINE=annual average baseline value of the facility,
SUMRBASE=summer baseline value of the facility,
SUMRVOL=summer baseline gasoline volume of the facility, per Sec. 80.91,
WNTRBASE=winter baseline value of the facility,
WNTRVOL=winter baseline gasoline volume of the facility, per Sec. 80.91.
    (b) Baseline exhaust benzene emissions--simple model. (1) Simple 
model exhaust benzene emissions of conventional gasoline shall be 
determined using the following equation:

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

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

    (2) The simple model annual average baseline exhaust benzene 
emissions for any facility of a refiner or importer of conventional 
gasoline shall be determined as follows:
    (i) The simple model baseline exhaust benzene emissions shall be 
determined separately for summer and winter using the facility's 
oxygenated individual baseline fuel parameter values for summer and 
winter (per Sec. 80.91), respectively, in the equation specified in 
paragraph (b)(1) of this section.
    (ii) The simple model annual average baseline exhaust benzene 
emissions of the facility shall be determined using the emissions values 
determined in paragraph (b)(2)(i) of this section in the equation 
specified in paragraph (a) of this section.
    (c) Baseline exhaust benzene emissions--complex model. The complex 
model annual average baseline exhaust benzene emissions for any facility 
of a refiner or importer of conventional gasoline shall be determined as 
follows:
    (1) The summer and winter complex model baseline exhaust benzene 
emissions shall be determined separately using the facility's oxygenated 
individual baseline fuel parameter values for summer and winter (per 
Sec. 80.91), respectively, in the appropriate complex model for exhaust 
benzene emissions described in Sec. 80.45.
    (2) The complex model annual average baseline exhaust benzene 
emissions of the facility shall be determined using the emissions values 
determined in paragraph (c)(1) of this section in the equation specified 
in paragraph (a) of this section.
    (d) Baseline exhaust toxics emissions. The annual average baseline 
exhaust toxics emissions for any facility of a refiner or importer of 
conventional gasoline shall be determined as follows:
    (1) The summer and winter baseline exhaust emissions of benzene, 
formaldehyde, acetaldehyde, 1,3-butadiene, and polycyclic organic matter 
shall be determined using the oxygenated individual baseline fuel 
parameter values for summer and winter (per Sec. 80.91), respectively, 
in the appropriate complex model for each exhaust toxic (per 
Sec. 80.45).
    (2) The summer and winter baseline total exhaust toxics emissions 
shall be determined separately by summing the summer and winter baseline 
exhaust emissions of each toxic (per paragraph (d)(1) of this section), 
respectively.
    (3) The annual average baseline exhaust toxics emissions of the 
facility shall be determined using the emissions values determined in 
paragraph (d)(2) of this section in the equation specified in paragraph 
(a) of this section.
    (e) Baseline NOX emissions. The annual average baseline 
NOX emissions for any facility of a refiner or importer of 
conventional gasoline shall be determined as follows:
    (1) The summer and winter baseline NOX emissions shall be 
determined using the baseline individual baseline fuel parameter values 
for summer and winter (per Sec. 80.91), respectively, in the appropriate 
complex model for NOX (per Sec. 80.45).
    (2) The annual average baseline NOX emissions of the facility 
shall be determined using the emissions values determined in paragraph 
(e)(1) of this section in the equation specified in paragraph (a) of 
this section.
    (3) The requirements specified in paragraphs (e) (1) and (2) of this 
section shall be determined separately using

[[Page 582]]

the oxygenated and nonoxygenated individual baseline fuel parameters, 
per Sec. 80.91.
    (f) Applicability of Phase I and Phase II models. The requirements 
of paragraphs (d) and (e) of this section shall be determined separately 
for the applicable Phase I and Phase II complex models specified in 
Sec. 80.45.
    (g) Calculation accuracy. Emissions values calculated per the 
requirements of this section shall be determined to four (4) significant 
figures. Sulfur, olefin and T90 values calculated per the requirements 
of this section shall be determined to the same number of decimal places 
as the corresponding value listed in Sec. 80.91(c)(5).

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



Sec. 80.91  Individual baseline determination.

    (a) Baseline definition. (1) The ``baseline'' or ``individual 
baseline'' of a refinery, refiner or importer, as applicable, shall 
consist of:
    (i) An estimate of the quality, composition and volume of its 1990 
gasoline, or allowable substitute, based on the requirements specified 
in Secs. 80.91 through 80.93; and
    (ii) Its baseline emissions values calculated per paragraph (f) of 
this section; and
    (iii) Its 1990-1993 blendstock-to-gasoline ratios calculated per 
Sec. 80.102.
    (2)(i) The quality and composition of the 1990 gasoline of a 
refinery, refiner or importer, as applicable, shall be the set of values 
of the following fuel parameters: benzene content; aromatic content; 
olefin content; sulfur content; distillation temperature at 50 and 90 
percent by volume evaporated; percent evaporated at 200  deg.F and 300 
deg.F; oxygen content; RVP.
    (ii) A refiner, per paragraph (b)(3)(i) of this section, shall also 
determine the API gravity of its 1990 gasoline.
    (3) The methodology outlined in this section shall be followed in 
determining a baseline value for each fuel parameter listed in paragraph 
(a)(2) of this section.
    (b) Requirements for refiners, blenders and importers--(1) 
Requirements for producers of gasoline and gasoline blendstocks. (i) A 
refinery engaged in the production of gasoline blendstocks from crude 
oil and/or crude oil derivatives, and the subsequent mixing of those 
blendstocks to form gasoline, shall have its baseline fuel parameter 
values determined from Method 1, 2 and/or 3-type data as described in 
paragraph (c) of this section, provided the refinery was in operation 
for at least 6 months in 1990.
    (ii) A refinery which was in operation for at least 6 months in 
1990, was shut down after 1990, and which restarts after June 15, 1994, 
and for which insufficient 1990 and post-1990 data was collected prior 
to January 1, 1995 from which to determine an individual baseline, shall 
have the values listed in paragraph (c)(5) of this section as its 
individual baseline parameters.
    (iii) A refinery which was in operation for less than 6 months in 
1990 shall have the values listed in paragraph (c)(5) of this section as 
its individual baseline parameters.
    (2) Requirements for producers or importers of gasoline blendstocks 
only. A refiner or importer of gasoline blendstocks which did not 
produce or import gasoline in 1990 and which produces or imports post-
1994 gasoline shall have the values listed in paragraph (c)(5) of this 
section as its individual baseline parameters.
    (3) Requirements for purchasers of gasoline and/or gasoline 
blendstocks. (i) A refiner or refinery, as applicable, solely engaged in 
the production of gasoline from gasoline blendstocks and/or gasoline 
which are simply purchased and blended to form gasoline shall have its 
individual baseline determined using Method 1-type data (per paragraph 
(c) of this section) from every batch of 1990 gasoline.
    (ii) If Method 1-type data on every batch of the refiner's or 
refinery's 1990 gasoline does not exist, that refiner or refinery shall 
have the values listed in paragraph (c)(5) of this section as its 
individual baseline parameters.
    (4) Requirements for importers of gasoline and/or gasoline 
blendstocks. (i) An importer of gasoline shall determine an individual 
baseline value for each fuel parameter listed in paragraph (a)(2) of 
this section using Method 1-type data on every batch of gasoline 
imported by

[[Page 583]]

that importer into the United States in 1990.
    (ii) An importer which is also a foreign refiner must determine its 
individual baseline using Method 1, 2 and/or 3-type data (per paragraph 
(c) of this section) if it imported at least 75 percent, by volume, of 
the gasoline produced at its foreign refinery in 1990 into the United 
States in 1990.
    (iii) An importer which cannot meet the criteria of paragraphs 
(b)(4)(i) or (ii) of this section for baseline determination shall have 
the parameter values listed in paragraph (c)(5) of this section as its 
individual baseline parameter values.
    (5) Requirements for exporters of gasoline and/or gasoline 
blendstocks. A refiner shall not include quality or volume data on its 
1990 exports of gasoline blendstocks or gasoline in its baseline 
determination.
    (c) Data types--(1) Method 1-type data. (i) Method 1-type data shall 
consist of quality (composition and property data) and volume records of 
gasoline produced in or shipped from the refinery in 1990, excluding 
exported gasoline. The measured fuel parameter values and volumes of 
batches, or shipments if not batch blended, shall be used except that 
data on produced gasoline which was also shipped shall be included only 
once.
    (ii) Gasoline blendstock which left a facility in 1990 and which 
could become gasoline solely upon the addition of oxygenate shall be 
included in the baseline determination.
    (A) Fuel parameter values of such blendstock shall be accounted for 
as if the gasoline blendstock were blended with ten (10.0) volume 
percent ethanol.
    (B) If the refiner or importer can provide evidence that such 
gasoline blendstock was not blended per paragraph (c)(1)(ii)(A) of this 
section, and that such gasoline blendstock was blended with another 
oxygenate or a different volume of ethanol, the fuel parameter values of 
the final gasoline (including oxygenate) shall be included in the 
baseline determination.
    (C) If the refiner or importer can provide evidence that such 
gasoline blendstock was not blended per paragraph (c)(1)(ii)(A) or (B) 
of this section, and that such gasoline blendstock was sold with out 
further changes downstream, the fuel parameter values of the original 
product shall be included in the baseline determination.
    (iii) Data on 1990 gasoline purchased or otherwise received, 
including intracompany transfers, shall not be included in the baseline 
determination of a refiner's or importer's facility if the gasoline 
exited the receiving refinery unchanged from its arrival state.
    (2) Method 2-type data. Method 2-type data shall consist of 1990 
gasoline blendstock quality data and 1990 blendstock production records, 
specifically the measured fuel parameter values and volumes of 
blendstock used in the production of gasoline within the refinery. 
Blendstock data shall include volumes purchased or otherwise received, 
including intracompany transfers, if the volumes were blended as part of 
the refiner's or importer's 1990 gasoline. Henceforth in Secs. 80.91 
through 80.93, ``blendstock(s)'' or ``gasoline blendstock(s)'' shall 
include those products or streams commercially blended to form gasoline.
    (3) Method 3-type data. (i) Method 3-type data shall consist of 
post-1990 gasoline blendstock and/or gasoline quality data and 1990 
blendstock and gasoline production records, specifically the measured 
fuel parameter values and volumes of blendstock used in the production 
of gasoline within the refinery. Blendstock data shall include volumes 
purchased or otherwise received, including intracompany transfers, if 
the volumes were blended as part of the refiner's or importer's 1990 
gasoline.
    (ii) In order to use Method 3-type data, the refiner or importer 
must do all of the following:
    (A) Include a detailed discussion comparing its 1990 and post-1990 
refinery operations and all other differences which would cause the 1990 
and post-1990 fuel parameter values to differ; and
    (B) Perform the appropriate calculations so as to adjust for the 
differences determined in paragraph (c)(3)(ii)(A) of this section; and
    (C) Include a narrative, discussing the methodology and reasoning 
for the adjustments made per paragraph (c)(3)(ii)(B) of this section.

[[Page 584]]

    (iii) In order to use post-1990 gasoline data, either of the 
following must be shown for each blendstock-type included in 1990 
gasoline, excluding butane:
    (A) The post-1990 volumetric fraction of a blendstock is within (+/
-)10.0 percent of the volumetric fraction of that blendstock in 1990 
gasoline. For example, if a 1990 blendstock constituted 30 volume 
percent of 1990 gasoline, this criterion would be met if the post-1990 
volumetric fraction of the blendstock in post-1990 gasoline was 27.0-
33.0 volume percent.
    (B) The post-1990 volumetric fraction of a blendstock is within (+/
-)2.0 volume percent of the absolute value of the 1990 volumetric 
fraction. For example, if a 1990 blendstock constituted 5 volume percent 
of 1990 gasoline, this criterion would be met if the post-1990 
volumetric fraction of the blendstock in post-1990 gasoline was 3-7 
volume percent.
    (iv) If using post-1990 gasoline data, post-1990 gasoline blendstock 
which left a facility and which could become gasoline solely upon the 
addition of oxygenate shall be included in the baseline determination, 
per the requirements specified in paragraph (c)(1)(ii) of this section.
    (4) Hierarchy of data use. (i) A refiner or importer must determine 
a baseline fuel parameter value using only Method 1-type data if 
sufficient Method 1-type data is available, per paragraph (d)(1)(ii) of 
this section.
    (ii) If a refiner has insufficient Method 1-type data for a baseline 
parameter value determination, it must supplement that data with all 
available Method 2-type data, until it has sufficient data, per 
paragraph (d)(1)(iii) of this section.
    (iii) If a refiner has insufficient Method 1- and Method 2-type data 
for a baseline parameter value determination, it must supplement that 
data with all available Method 3-type data, until it has sufficient 
data, per paragraph (d)(1)(iii) of this section.
    (iv) The protocol for the determination of baseline fuel parameter 
values in paragraphs (c)(4)(i) through (iii) of this section shall be 
applied to each fuel parameter one at a time.
    (5) Anti-dumping statutory baseline. (i) The summer anti-dumping 
statutory baseline shall have the set of fuel parameter values 
identified as ``summer'' in Sec. 80.45(b)(2). The anti-dumping summer 
API gravity shall be 57.4  deg.API.
    (ii) The winter anti-dumping statutory baseline shall have the set 
of fuel parameter values identified as ``winter'' in Sec. 80.45(b)(2), 
except that winter RVP shall be 8.7 psi. The anti-dumping winter API 
gravity shall be 60.2 API.
    (iii) The annual average anti-dumping statutory baseline shall have 
the following set of fuel parameter values:

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

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

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

    (d) Data collection and testing requirements--(1) Minimum sampling 
requirements--(i) General requirements. (A) Data shall have been 
obtained for at least three months of the refiner's or importer's 
production of summer gasoline and at least three months of its 
production of winter gasoline. When method 1 per batch RVP data is 
available, a month is considered equivalent to 4 weeks of seasonal data.
    (1) Method 1, per batch, actual RVP data will be used to define that 
batch as either summer fuel or winter fuel. Summer fuel is defined as 
fuel produced and intended for sale to satisfy federal summer volatility 
standards. When such per batch actual RVP data is not available, data is 
allocated per month as follows. A summer month is

[[Page 585]]

defined as any month during which more than 50 percent (by volume) of 
the gasoline produced by a refiner met the federal summer gasoline 
volatility requirements. Winter shall be any month which could not be 
considered a summer month under this definition.
    (2) The three months which compose the summer and the winter data do 
not have to be consecutive nor within the same year.
    (3) If, in 1990, a refiner marketed all of its gasoline only in an 
area or areas which experience no seasonal changes relative to gasoline 
requirements, e.g., Hawaii, only 3 months of data are required.
    (B) Once the minimum sampling requirements have been met, data 
collection may cease. Additional data may only be included for the 
remainder of the calendar year in which the minimum sampling 
requirements were met. In any case, all data collected through the date 
of collection of the last data point included in the determination of a 
baseline fuel parameter value must be utilized in the baseline 
determination of that fuel parameter.
    (C) Less than the minimum requirements specified in paragraph (d)(1) 
of this section may be allowed, upon petition and approval (per 
Sec. 80.93), if it can be shown that the available data is sufficient in 
quality and quantity to use in the baseline determination.
    (ii) Method 1 sampling requirements. At least half of the batches, 
or shipments if not batch blended, in a calendar month shall have been 
sampled over a minimum of six months in 1990.
    (iii) Method 2 sampling requirements. (A) Continuous blendstock 
streams shall have been sampled at least weekly over a minimum of six 
months in 1990.
    (B) For blendstocks produced on a batch basis, at least half of all 
batches of a single blendstock type produced in a calendar month shall 
have been sampled over a minimum of six months in 1990.
    (iv) Method 3 sampling requirements--(A) Blendstock data. (1) Post-
1990 continuous blendstock streams shall have been sampled at least 
weekly over a minimum of six months.
    (2) For post-1990 blendstocks produced on a batch basis, at least 
half of all batches of a single blendstock type produced in a calendar 
month shall have been sampled over a minimum of six months.
    (B) Gasoline data. At least half of the post-1990 batches, or 
shipments if not batch blended, in a calendar month shall have been 
sampled over a minimum of six months in order to use post-1990 gasoline 
data.
    (2) Sampling beyond today's date. The necessity and actual 
occurrence of data collection after today's date must be shown.
    (3) Negligible quantity sampling. Testing of a blendstock stream for 
a fuel parameter listed in this paragraph (d)(3) is not required if the 
refiner can show that the fuel parameter exists in the stream at less 
than or equal to the amount, on average, shown in this paragraph (d)(3) 
for that fuel parameter. Any fuel parameter shown to exist in a refinery 
stream in negligible amounts shall be assigned a value of 0.0:

Aromatics, volume percent--1.0
Benzene, volume percent--0.15
Olefins, volume percent--1.0
Oxygen, weight percent--0.2
Sulfur, ppm--30.0

    (4) Sample compositing. (i) Samples of gasoline or blendstock which 
have been retained, but not analyzed, may be mixed prior to analysis and 
analyzed, as described in paragraphs (d)(4)(iii) (A) through (H) of this 
section, for the required fuel parameters. Samples must be from the same 
season and year and must be of a single grade or of a single type of 
batch-produced blendstock.
    (ii) Blendstock samples of a single blendstock type obtained from 
continuous processes over a calendar month may be mixed together in 
equal volumes to form one blendstock sample and the sample subsequently 
analyzed for the required fuel parameters.
    (iii)(A) Samples shall have been collected and stored per the method 
normally employed at the refinery in order to prevent change in product 
composition with regard to baseline properties and to minimize loss of 
volatile fractions of the sample.
    (B) Properties of the retained samples shall be adjusted for loss of 
butane by comparing the RVP measured right

[[Page 586]]

after blending with the RVP determined at the time that the supplemental 
properties are measured.
    (C) The volume of each batch or shipment sampled shall have been 
noted and the sum of the volumes calculated to the nearest hundred (100) 
barrels.
    (D) For each batch or shipment sampled, the ratio of its volume to 
the total volume determined in paragraph (d)(4)(iii)(C) of this section 
shall be determined to three (3) decimal places. This shall be the 
volumetric fraction of the shipment in the mixture.
    (E) The total minimum volume required to perform duplicate analyses 
to obtain values of all of the required fuel parameters shall be 
determined.
    (F) The volumetric fraction determined in paragraph (d)(4)(iii)(D) 
of this section for each batch or shipment shall be multiplied by the 
value determined in paragraph (d)(4)(iii)(E) of this section.
    (G) The resulting value determined in paragraph (d)(4)(iii)(F) of 
this section for each batch or shipment shall be the volume of each 
batch or shipment's sample to be added to the mixture. This volume shall 
be determined to the nearest milliliter.
    (H) The appropriate volumes of each shipment's sample shall be 
thoroughly mixed and the solution analyzed per the methods normally 
employed at the refinery.
    (5) Test methods. (i) If the test methods used to obtain fuel 
parameter values of gasoline and gasoline blendstocks differ or are 
otherwise not equivalent in precision or accuracy to the corresponding 
test method specified in Sec. 80.46, results obtained under those 
procedures will only be acceptable, upon petition and approval (per 
Sec. 80.93), if the procedures are or were industry-accepted procedures 
for measuring the properties of gasoline and gasoline blendstocks at the 
time the measurement was made.
    (ii) Oxygen content may have been determined analytically or from 
oxygenate blending records.
    (A) The fuel parameter values, other than oxygen content, specified 
in paragraph (a) of this section, must be established as for any 
blendstock, per the requirements of this paragraph (d).
    (B) All oxygen associated with allowable gasoline oxygenates per 
Sec. 80.2(jj) shall be included in the determination of the baseline 
oxygen content, if oxygen content was determined analytically.
    (C) Oxygen content shall be assumed to be contributed solely by the 
oxygenate which is indicated on the blending records, if oxygen content 
was determined from blending records.
    (6) Data quality. Data may be excluded from the baseline 
determination if it is shown to the satisfaction of the Director of the 
Office of Mobile Sources, or designee, that it is not within the normal 
range of values expected for the gasoline or blendstock sample, 
considering unit configuration, operating conditions, etc.; due to:
    (i) Improper labeling; or
    (ii) Improper testing; or
    (iii) Other reasons as verified by the auditor specified in 
Sec. 80.92.
    (e) Baseline fuel parameter determination--(1) Closely integrated 
gasoline producing facilities. Each refinery or blending facility must 
determine a set of baseline fuel parameter values per this paragraph 
(e). A single set of baseline fuel parameters may be determined, upon 
petition and approval, for two or more facilities under either of the 
following circumstances:
    (i) Two or more refineries or sets of gasoline blendstock-producing 
units of a refiner engaged in the production of gasoline per paragraph 
(b)(1) of this section which are geographically proximate to each other, 
yet not within a single refinery gate, and whose 1990 operations were 
significantly interconnected.
    (ii) A gasoline blending facility operating per paragraph (b)(3) of 
this section received at least 75 percent of its 1990 blendstock volume 
from a single refinery, or from one or more refineries which are part of 
an aggregate baseline per Sec. 80.101(h). The blending facility and 
associated refinery(ies) must be owned by the same refiner.
    (2) Equations--(i) Parameter determinations. Average baseline fuel 
parameters shall be determined separately for summer and winter using 
summer and winter data (per paragraph (d)(1)(i)(A) of this section), 
respectively, in the applicable equation listed in paragraphs

[[Page 587]]

(e)(2) (ii) through (iv) of this section, except that average baseline 
winter RVP shall be 8.7 psi.
    (ii) Product included in parameter determinations. In each of the 
equations listed in paragraphs (e)(2) (ii) through (iv) of this section, 
the following shall apply:
    (A) All gasoline produced to meet EPA's 1990 summertime volatility 
requirements shall be considered summer gasoline. All other gasoline 
shall be considered winter gasoline.
    (B)(1) Baseline total annual 1990 gasoline volume shall be the 
larger of the total volume of gasoline produced in or shipped from the 
refinery in 1990.
    (2) Baseline summer gasoline volume shall be the total volume of low 
volatility gasoline which met EPA's 1990 summertime volatility 
requirements. Baseline summer gasoline volume shall be determined on the 
same basis (produced or shipped) as baseline total annual gasoline 
volume.
    (3) Baseline winter gasoline volume shall be the baseline total 
annual gasoline volume minus the baseline summer gasoline volume.
    (C) Fuel parameter values shall be determined in the same units and 
at least to the same number of decimal places as the corresponding fuel 
parameter listed in paragraph (c)(5) of this section.
    (D) Volumes shall be reported to the nearest barrel or to the degree 
at which historical records were kept.
    (iii) Method 1. Summer and winter Method 1-type data, per paragraph 
(c)(1) of this section, shall be evaluated separately according to the 
following equation:
[GRAPHIC] [TIFF OMITTED] TR16FE94.013

where:

Xbs=summer or winter baseline value of fuel parameter X for the 
refinery
s=season, summer or winter, per paragraph (d)(1)(i)(A)(1) of this 
section
g=separate grade of season s gasoline produced by the refinery in 1990
ps=total number of different grades of season s gasoline produced 
by the refinery in 1990
Tgs=total volume of season s grade g gasoline produced in 1990
Ns=total volume of season s gasoline produced by the refinery in 
1990
i=separate batch or shipment of season s 1990 gasoline sampled
ngs=total number of season s samples of grade g gasoline
Xgis=parameter value of grade g gasoline sample i in season s
Vgis=volume of season s grade g gasoline sample i
SGgis=specific gravity of season s grade g gasoline sample i (used 
only for fuel parameters measured on a weight basis)

    (iv) Method 2. Summer and winter Method 2-type data, per paragraph 
(c)(2) of this section, shall be evaluated separately according to the 
following equation:

[[Page 588]]

[GRAPHIC] [TIFF OMITTED] TR20JY94.000


where

Xbs=Summer or winter baseline value of fuel parameter X for the 
refinery
s=season, summer or winter, per paragraph (d)(1)(i)(A)(1) of this 
section
j=type of blendstock (e.g., reformate, isomerate, alkylate, etc.)
ms=total types of blendstocks in season s 1990 gasoline
Tjs=total 1990 volume of blendstock j used in the refinery's season 
s gasoline
Ns=total volume of season s gasoline produced in the refinery in 
1990
i=sample of blendstock j
njs=number of samples of season s blendstock j from continuous 
process streams
Xijs=parameter value of sample i of season s blendstock j
pjs=number of samples of season s batch-produced blendstock j
Vijs=volume of batch of sample i of season s blendstock j
SGijs=specific gravity of sample i of season s blendstock j (used 
only for fuel parameters measured on a weight basis)

    (v) Method 3. (A) Post-1990 Blendstock. Summer and winter Method 3-
type data, per paragraph (c)(3) of this section, shall be evaluated 
separately according to the following equation:
[GRAPHIC] [TIFF OMITTED] TR16FE94.015

 where

Xbs=Summer or winter baseline value of fuel parameter X for the 
refinery
s=season, summer or winter, per paragraph (d)(1)(i)(A)(1) of this 
section
j=type of blendstock (e.g., reformate, isomerate, alkylate, etc.)
ms=total types of blendstocks in season s 1990 gasoline
Tjs=total 1990 volume of blendstock j used in the refinery's season 
s gasoline
Ns=total volume of season s gasoline produced in the refinery in 
1990
i=sample of post-1990 season s blendstock j
njs=number of samples of post-1990 season s blendstock j from 
continuous process streams
Xijs=parameter value of sample i of post-1990 season s blendstock j
pjs=number of samples of post-1990 season s batch-produced 
blendstock j
Vijs=volume of post-1990 batch of sample i of season s blendstock j
SGijs=specific gravity of sample i of season s blendstock j (used 
only for fuel parameters measured on a weight basis)

    (B) Post-1990 gasoline. Summer and winter Method 3-type gasoline 
data, per paragraph (c)(3) of this section, shall be evaluated 
separately according tothe following equation:

[[Page 589]]

[GRAPHIC] [TIFF OMITTED] TR16FE94.016


where:
Xbs=Summer or winter baseline value of fuel parameter X for the 
refinery
s=season, summer or winter, per paragraph (d)(1)(i)(A)(1) of this 
section
g=separate grade of season s gasoline produced by the refinery in 1990
ps=total number of different grades of season s gasoline produced 
by the refinery in 1990
Tgs=total volume of season s grade g gasoline produced in 1990
Ns=total volume of season s gasoline produced by the refinery in 
1990
i=separate batch or shipment of post-1990 season s gasoline sampled
ngs=total number of samples of post-1990 season s grade g gasoline
Xgis=parameter value of post-1990 grade g season s gasoline sample 
i
Vgis=volume of post-1990 season s grade g gasoline sample i
SGgis=specific gravity of post-1990 season s grade g gasoline 
sample i (used only for fuel parameters measured on a weight basis)

    (3) Percent evaporated determination. (i) Baseline E200 and E300 
values shall be determined directly from actual measurement data.
    (ii) If the data per paragraph (e)(3)(i) of this section are 
unavailable, upon petition and approval, baseline E200 and E300 values 
shall be determined from the following equations using the baseline T50 
and T90 values, if the baseline T50 and T90 values are otherwise 
acceptable:

E200=147.91-(0.49 x T50)
E300=155.47-(0.22 x T90)

    (4) Oxygen in the baseline. Baseline fuel parameter values shall be 
determined on both an oxygenated and non-oxygenated basis.
    (i) If baseline values are determined first on an oxygenated basis, 
per paragraph (e) of this section, the calculations in paragraphs 
(e)(4)(i) (A) through (C) of this section shall be performed to 
determine the value of each baseline parameter on a non-oxygenated 
basis.
    (A) Benzene, aromatic, olefin and sulfur content shall be determined 
on a non-oxygenated basis according to the following equation:

UV = [AV/(100-OV)] x 100
where

UV=non-oxygenated parameter value
AV=oxygenated parameter value
OV=1990 oxygenate volume as a percent of total production

    (B) Reid vapor pressure (RVP) shall be determined on a non-
oxygenated basis according to the following equation:
[GRAPHIC] [TIFF OMITTED] TR20JY94.001

where

UR=non-oxygenated RVP (baseline value)
BR=oxygenated RVP
i=type of oxygenate used in 1990
n=total number of different types of oxygenates used in 1990
OVi=1990 volume, as a percent of total production, of oxygenate i
ORi=blending RVP of oxygenate i

    (C) Test data and engineering judgement shall be used to estimate 
T90, T50, E300 and E200 baseline values on a non-oxygenated basis. 
Allowances shall

[[Page 590]]

be made for physical dilution and distillation effects only, and not for 
refinery operational changes, e.g., decreased reformer severity required 
due to the octane value of oxygenate which would reduce aromatics.
    (ii) If baseline values are determined first on a non-oxygenated 
basis, the calculations in paragraphs (e)(4)(ii) (A) through (C) of this 
section shall be performed to determine the value of each baseline 
parameter on an oxygenated basis.
    (A) Benzene, aromatic, olefin and sulfur content shall be determined 
on an oxygenated basis according to the following equation:

AV = UV x (100-OV)/100
where

AV=oxygenated parameter value
UV = non-oxygenated parameter value
OV=1990 oxygenate volume as a percent of total production

    (B) Reid vapor pressure (RVP) shall be determined on an oxygenated 
basis according to the following equation:
[GRAPHIC] [TIFF OMITTED] TR20JY94.002

where

BR=oxygenated RVP
UR=non-oxygenated RVP
i=type of oxygenate
n=total number of different types of oxygenates
OVi=1990 volume, as a percent of total production, of oxygenate i
ORi=blending RVP of oxygenate i

    (C) Test data and engineering judgement shall be used to estimate 
T90, T50, E300 and E200 baseline values on an oxygenated basis. 
Allowances shall be made for physical dilution and distillation effects 
only, and not for refinery operational changes, e.g., decreased reformer 
severity required due to the octane value of oxygenate which would 
reduce aromatics.
    (5) Work-in-progress. A refiner may, upon petition and approval (per 
Sec. 80.93), be allowed to account for work- in-progress at one or more 
of its refineries in 1990 in the determination of that refinery's 
baseline fuel parameters using Method 1, 2 or 3-type data if it meets 
the requirements specified in this paragraph (e)(5).
    (i) Work-in-progress shall include:
    (A) Refinery modification projects involving gasoline blendstock or 
distillate producing units which were under construction in 1990; or
    (B) Refinery modification projects involving gasoline blendstock or 
distillate producing units which were contracted for prior to or in 1990 
such that the refiner was committed to purchasing materials and 
constructing the project.
    (ii) The modifications discussed in paragraph (e)(5)(i) of this 
section must have been initiated with intent of complying with a 
legislative or regulatory environmental requirement enacted or 
promulgated prior to January 1, 1991.
    (iii) When comparing emissions or parameter values determined with 
and without the anticipated work-in-progress adjustment, at least one of 
the following situations results when comparing annual average baseline 
values per Sec. 80.90:
    (A) A 2.5 percent or greater difference in exhaust benzene emissions 
(per Sec. 80.90); or
    (B) A 2.5 percent or greater difference in total exhaust toxics 
emissions (per Sec. 80.90(d)); or
    (C) A 2.5 percent or greater difference in NOX emissions (per 
Sec. 80.90(e)); or
    (D) A 10.0 percent or greater difference in sulfur values; or
    (E) A 10.0 percent or greater difference in olefin values; or
    (F) A 10.0 percent or greater difference in T90 values.
    (iv) The requirements of paragraph (e)(5)(iii) of this section shall 
be determined according to the following equation:

[[Page 591]]

[GRAPHIC] [TIFF OMITTED] TR16FE94.020


    (v) The capital involved in the work-in-progress is at least:
    (A) 10.0 percent of the refinery's depreciated book value as of the 
work-in-progress start-up date; or
    (B) $10 million.
    (vi) Sufficient data shall have been obtained since reliable 
operation of the work-in-progress was achieved. Such data shall be used 
in the determination of the baseline value, due to the work-in-progress, 
of each of the fuel parameters specified in Sec. 80.91(a)(2)(i) and as 
verification of the effect of the work-in-progress.
    (A) The baseline value, due to the work-in-progress, of each of the 
fuel parameters specified in Sec. 80.91(a)(2)(i) shall be used in the 
determination of the emissions specified in Sec. 80.90.
    (B) The baseline values of sulfur, olefins and E300, due to the 
work-in-progress, shall be used in the determination of the emissions 
specified in Sec. 80.41(j)(3).
    (vii) The annual average baseline values of exhaust benzene 
emissions, per Sec. 80.90(b) and Sec. 80.90(c), exhaust toxics 
emissions, per Sec. 80.90(d), and NOX emissions, per Sec. 80.90(e), 
are the values resulting from the work-in-progress baseline adjustment, 
not to exceed the larger of:
    (A) The unadjusted annual average baseline value of each emission 
specified in this paragraph (e)(5)(vii); or
    (B) The following values:
    (1) Exhaust benzene emissions, simple model, 6.77;
    (2) Exhaust benzene emissions, complex model, 34.68 mg/mile;
    (3) Exhaust toxics emissions, 53.20 mg/mile in Phase I, 109.7 mg/
mile in Phase II;
    (4) NOX emissions, 750.1 mg/mile in Phase I, 1534. mg/mile in 
Phase II.
    (viii) When compliance is achieved using the simple model, per 
Sec. 80.41 and/or Sec. 80.101, the baseline values of sulfur, olefins 
and T90 are the values resulting from the work-in-progress baseline 
adjustment, not to exceed the larger of:
    (A) The unadjusted annual average baseline value of each fuel 
parameter specified in paragraph (e)(5)(viii) of this section; or
    (B) The following values:
    (1) Sulfur, 355 ppm;
    (2) Olefins, 11.3 volume percent;
    (3) T90, 349  deg.F; or
    (C) An adjusted annual average baseline fuel parameter value for 
sulfur, olefins and T90 such that exhaust emissions of VOC, toxics, and 
NOX do not exceed the complex model emission levels specified in 
paragraph (e)(5)(vii)(B) of this section. In the petition for a work-in-
progress adjustment, the refiner shall specify sulfur, olefins and T90 
values that meet these emission levels.
    (ix) All work-in-progress adjustments must be accompanied by:
    (A) Unadjusted and adjusted fuel parameters, emissions, and volumes; 
and
    (B) A description of the current status of the work-in-progress 
(i.e., the refinery modification project) and the date on which normal 
operations were achieved; and
    (C) A narrative describing the situation, the types of calculations, 
and the reasoning supporting the types of calculations done to determine 
the adjusted values.
    (6) Baseline adjustment for extenuating circumstances. (i) Baseline 
adjustments may be allowed, upon petition and approval (per Sec. 80.93), 
if a refinery had downtime of a gasoline blendstock producing unit for 
30 days or more in 1990 due to:
    (A) Unplanned, unforeseen circumstances; or
    (B) Non-annual maintenance (turnaround).
    (ii) Fuel parameter and volume adjustments shall be made by assuming 
that the downtime did not occur in 1990.
    (iii) All extenuating circumstance adjustments must be accompanied 
by:
    (A) Unadjusted and adjusted fuel parameters, emissions, and volumes; 
and

[[Page 592]]

    (B) A description of the current status of the extenuating 
circumstance and the date on which normal operations were achieved; and
    (C) A narrative describing the situation, the types of calculations, 
and the reasoning supporting the types of calculations done to determine 
the adjusted values.
    (7) Baseline adjustments for 1990 JP-4 production. (i) Baseline 
adjustments may be allowed, upon petition and approval (per Sec. 80.93), 
if a refinery produced JP-4 jet fuel in 1990 and meets all of the 
following requirements:
    (A) The refinery is the only refinery of a refiner such that it 
cannot form an aggregate baseline with another refinery (per paragraph 
(f) of this section) or all of the refineries of a refiner produced JP-4 
in 1990 and each of the refineries also meets the requirements specified 
in paragraphs (e)(7)(i) (B) and (C) of this section.
    (B) The refinery will not produce reformulated gasoline. If the 
refinery produces reformulated gasoline at any time in a calendar year, 
its compliance baseline shall revert to its unadjusted baseline values 
for that year and all subsequent years.
    (C) The ratio of the refinery's 1990 JP-4 production to its 1990 
gasoline production equals or exceeds 0.5.
    (ii) Fuel parameter and volume adjustments shall be made by assuming 
that no JP-4 was produced in 1990.
    (iii) All adjustments due to 1990 JP-4 production must be 
accompanied by:
    (A) Unadjusted and adjusted fuel parameters, emissions, and volumes; 
and
    (B) A narrative describing the situation, the types of calculations, 
and the reasoning supporting the types of calculations done to determine 
the adjusted values.
    (iv) The provisions of Sec. 80.91(e)(7)(i)(A) through (C) are stayed 
until October 19, 1995, for all refiners which meet the following 
requirements:
    (A) Baseline adjustments may be allowed, upon petition and approval 
(per Sec. 80.93), if a refinery produced JP-4 jet fuel in 1990 and all 
of the following requirements are also met:
    (1) The type of refinery must be described as one of the following:
    (i) The refinery is the only refinery of a refiner such that it 
cannot form an aggregate baseline with another refinery (per paragraph 
(f) of this section); or
    (ii) The refinery is one refinery of a multi-refinery refiner for 
which all of its refineries produced JP-4 in 1990 and each of the 
refineries also meets the requirements specified in paragraphs 
(e)(7)(iv)(A)(2) and (3); or
    (iii) The refinery is one refinery of a multi-refinery refiner for 
which not all of the refiner's refineries produced JP-4 in 1990.
    (2) No refinery of the refiner produces reformulated gasoline. If 
any refinery of the refiner produces reformulated gasoline at any time 
in a calendar year, the compliance baseline of all its refineries 
receiving a baseline adjustment per this paragraph (e)(7)(A) shall 
revert to each refinery's unadjusted baseline for that year and all 
subsequent years.
    (3) 1990 JP-4 to gasoline ratio.
    (i) For a refiner per paragraph (e)(7)(iv)(A)(1)(i) of this section, 
the ratio of its refinery's 1990 JP-4 production to its 1990 gasoline 
production must equal or exceed 0.15.
    (ii) For a refiner per paragraph (e)(7)(iv)(A)(1)(ii) of this 
section, the ratio of each of its refinery's 1990 JP-4 production to its 
1990 gasoline production must equal or exceed 0.15.
    (iii) For a refiner per paragraph (e)(7)(iv)(A)(1)(iii) of this 
section, the ratio of the refiner's 1990 JP-4 production to its 1990 
gasoline production must equal or exceed 0.15, when determined across 
all of its refineries.
    (B) [Reserved]
    (f) Baseline volume and emissions determination--(1) Individual 
baseline volume. (i) The individual baseline volume of a refinery 
described in paragraph (b)(1)(i) of this section shall be the larger of 
the total gasoline volume produced in or shipped from the refinery in 
1990, excluding gasoline blendstocks and exported gasoline, and 
including the oxygenate volume associated with any product meeting the 
requirements specified in paragraph (c)(1)(ii) of this section.
    (ii) Gasoline brought into the refinery in 1990 which exited the 
refinery, in 1990, unchanged shall not be included in determining the 
refinery's baseline volume.

[[Page 593]]

    (iii) If a refiner is allowed to adjust its baseline per paragraphs 
(e)(5) through (e)(7) of this section, its individual baseline volume 
shall be the volume determined after the adjustment.
    (iv) The individual baseline volume for facilities deemed closely 
integrated, per paragraph (e)(1) of this section, shall be the combined 
1990 gasoline production of the facilities, so long as mutual volumes 
are not double-counted, i.e., volumes of blendstock sent from the 
refinery to the blending facility should not be included in the blending 
facility's volume.
    (v) The baseline volume of a refiner, per paragraph (b)(3) of this 
section, shall be the larger of the total gasoline volume produced in or 
shipped from the refinery in 1990, excluding gasoline blendstocks and 
exported gasoline.
    (vi) The baseline volume of an importer, per paragraph (b)(4) of 
this section, shall be the total gasoline volume imported into the U.S. 
in 1990.
    (2) Individual baseline emissions. (i) Individual annual average 
baseline emissions (per Sec. 80.90) shall be determined for every 
refinery, refiner or importer, as applicable.
    (ii) If the baseline fuel value for aromatics, olefins, and/or 
benzene (determined per paragraph (e) of this section) is higher than 
the high end of the valid range limits specified in Sec. 80.42(c)(1) if 
compliance is being determined under the Simple Model, or in 
Sec. 80.45(f)(1)(ii) if compliance is being determined under the Complex 
Model, then the valid range limits may be extended for conventional 
gasoline in the following manner:
    (A) The new high end of the valid range for aromatics is determined 
from the following equation:

NAROLIM = AROBASE + 5.0 volume percent

where

NAROLIM = The new high end of the valid range limit for aromatics, in 
volume percent
AROBASE = The seasonal baseline fuel value for aromatics, in volume 
percent
    (B) The new high end of the valid range for olefins is determined 
from the following equation:

NOLELIM = OLEBASE + 3.0 volume percent

where

NOLELIM = The new high end of the valid range limit for olefins, in 
volume percent
OLEBASE = The seasonal baseline fuel value for olefins, in volume 
percent
    (C) The new high end of the valid range for benzene is determined 
from the following equation:

NBENLIM = BENBASE + 0.5 volume percent

where

NBENLIM = The new high end of the valid range limit for benzene, in 
volume percent
BENBASE = The seasonal baseline fuel value for benzene, in volume 
percent
    (D) The extension of the valid range is limited to the applicable 
summer or winter season in which the baseline fuel values for aromatics, 
olefins, and/or benzene exceed the high end of the valid range as 
described in paragraph (f)(2)(ii) of this section. Also, the extension 
of the valid range is limited to use by the refiner whose baseline value 
for aromatics, olefins, and/or benzene was higher than the valid range 
limits as described in paragraph (f)(2)(ii) of this section.
    (E) Any extension of the Simple Model valid range limits is 
applicable only to the Simple Model. Likewise any extension of the 
Complex Model valid range limits is applicable only to the Complex 
Model.
    (F) The valid range extensions calculated in paragraphs 
(f)(2)(ii)(A), (B), and (C) of this section are applicable to both the 
baseline fuel and target fuel for the purposes of determining the 
compliance status of conventional gasolines. The extended valid range 
limit represents the maximum value for that parameter above which fuels 
cannot be evaluated with the applicable compliance model.
    (G) Under the Simple Model, baseline and compliance calculations 
shall subscribe to the following limitations:
    (1) If the aromatics valid range has been extended per paragraph 
(f)(2)(ii)(A) of this section, an aromatics value equal to the high end 
of the valid range specified in Sec. 80.42(c)(1)

[[Page 594]]

shall be used for the purposes of calculating the exhaust benzene 
fraction.
    (2) If the fuel benzene valid range has been extended per paragraph 
(f)(2)(ii)(C) of this section, a benzene value equal to the high end of 
the valid range specified in Sec. 80.42(c)(1) shall be used for the 
purposes of calculating the exhaust benzene fraction.
    (H) Under the Complex Model, baseline and compliance calculations 
shall subscribe to the following limitations:
    (1) If the aromatics valid range has been extended per paragraph 
(f)(2)(ii)(A) of this section, an aromatics value equal to the high end 
of the valid range specified in Sec. 80.45(f)(1)(ii) shall be used for 
the purposes of calculating emissions performances.
    (2) If the olefins valid range has been extended per paragraph 
(f)(2)(ii)(B) of this section, an olefins value equal to the high end of 
the valid range specified in Sec. 80.45(f)(1)(ii) shall be used for the 
target fuel for the purposes of calculating emissions performances.
    (3) If the benzene valid range has been extended per paragraph 
(f)(2)(ii)(C) of this section, a benzene value equal to the high end of 
the valid range specified in Sec. 80.45(f)(1)(ii) shall be used for the 
target fuel for the purposes of calculating emissions performances.
    (iii) Facilities deemed closely integrated, per paragraph (e)(1) of 
this section, shall have a single set of annual average individual 
baseline emissions.
    (iv) Aggregate baselines (per Sec. 80.101(h)) must have the NOX 
emissions of all refineries in the aggregate determined on the same 
basis, using either oxygenated or non-oxygenated baseline fuel 
parameters.
    (3) Geographic considerations requiring individual conventional 
gasoline compliance baselines. (i) Anyone may petition EPA to establish 
separate baselines for refineries located in and providing conventional 
gasoline to an area with a limited gasoline distribution system if it 
can show that the area is experiencing increased toxics emissions due to 
an ozone nonattainment area opting into the reformulated gasoline 
program pursuant to section 211(k)(6) of the Act.
    (ii) If EPA agrees with the finding of paragraph (f)(4)(i) of this 
section, it shall require that the baselines of such refineries be 
separate from refineries not located in the area.
    (iii) If two (2) or more of a refiner's refineries are located in 
the geographic area of concern, the refiner may aggregate the baseline 
emissions and sulfur, olefin and T90 values of the refineries or have an 
individual baseline for one or more of the refineries, per paragraph 
(f)(3) of this section.
    (4) Baseline recalculations. Aggregate baseline exhaust emissions 
(per Sec. 80.90) and baseline sulfur, olefin and T90 values and 
aggregate baseline volumes shall be recalculated under the following 
circumstances:
    (i) A refinery included in an aggregate baseline is entirely 
shutdown. If the shutdown refinery was part of an aggregate baseline, 
the aggregate baseline emissions, aggregate baseline sulfur, olefin and 
T90 values and aggregate volume shall be recalculated to account for the 
removal of the shutdown refinery's contributions to the aggregate 
baseline.
    (ii) A refinery exchanges owners.
    (A) All aggregate baselines affected by the exchange shall be 
recalculated to reflect the addition or subtraction of the baseline 
exhaust emissions, sulfur, olefin and T90 values and volumes of that 
refinery.
    (B) The new owner may elect to establish an individual baseline for 
the refinery or to include it in an aggregate baseline.
    (C) If the refinery was part of an aggregate of three or more 
refineries, the remaining refineries in the aggregate from which that 
refinery was removed will have a new aggregate baseline. If the refinery 
was part of an aggregate of only two refineries, the remaining refinery 
will have an individual baseline.
    (g) Inability to meet the requirements of this section. If a refiner 
or importer is unable to comply with one or more of the requirements 
specified in paragraphs (a) through (f) of this section, it may, upon 
petition and approval, accommodate the lack of compliance in a 
reasonable, logical, technically sound manner, considering the 
appropriateness of the alternative. A narrative of

[[Page 595]]

the situation, as well as any calculations and results determined, must 
be documented.

[59 FR 7860, Feb. 16, 1994, as amended at 59 FR 36966, July 20, 1994; 60 
FR 6032, Feb. 1, 1995; 60 FR 40008, Aug. 4, 1995]



Sec. 80.92  Baseline auditor requirements.

    (a) General requirements. (1) Each refiner or importer is required 
to have its individual baseline determination methodology, resulting 
baseline fuel parameter, volume and emissions values, and 1990-1993 
blendstock-to-gasoline ratios (per Sec. 80.102) verified by an auditor 
which meets the requirements described in this section. A refiner or 
importer which has the anti-dumping statutory baseline as its individual 
baseline is exempt from this requirement.
    (2) An auditor may be an individual or organization, and may utilize 
contractors and subcontractors to assist in the verification of a 
baseline.
    (3) If an auditor is an organization, one or more persons shall be 
designated as primary analyst(s). The primary analyst(s) shall meet the 
requirements described in paragraphs (c) (2) and (3) of this section and 
shall be responsible for the baseline audit per paragraph (f) of this 
section.
    (b) Independence. The auditor, its contractors, subcontractors and 
their organizations shall be independent of the submitting organization. 
All of the criteria listed in paragraphs (b) (1) and (2) of this section 
must be met by every individual involved in substantive aspects of the 
baseline verification.
    (1) Previous employment criteria. (i) None of the auditing 
personnel, including any contractor or subcontractor personnel, involved 
in the baseline verification for a refiner or importer shall have been 
employed by the refiner or importer at any time during the three (3) 
years preceding the date of hire of the auditor by the refiner or 
importer for baseline verification purposes.
    (ii) Auditor personnel may have been a contractor or subcontractor 
to the refiner or importer, as long as all other criteria listed in this 
section are met.
    (iii) Auditor personnel may also have developed the baseline of the 
refiner or importer whose baseline they are auditing, but not as an 
employee (per paragraph (b)(1)(i) of this section). Those involved only 
in the development of the baseline of the refiner or importer need not 
meet the requirements specified in this section.
    (2) Financial criteria. Neither the primary analyst, nor the 
auditing organization nor any organization or individual which may be 
contracted or subcontracted to supply baseline verification expertise 
shall:
    (i) Have received more than one quarter of its revenue from the 
refiner or importer during the year prior to the date of hire of the 
auditor by the refiner or importer for auditing purposes. Income 
received from the refiner or importer to develop the baseline being 
audited is excepted; nor
    (ii) Have a total of more than 10 percent of its net worth with the 
refiner or importer; nor
    (iii) Receive compensation for the audit which is dependent on the 
outcome of the audit.
    (c) Technical ability. All of the following criteria must be met by 
the auditor in order to demonstrate its technical capability to perform 
the baseline audit:
    (1) The auditor shall be technically capable of evaluating a 
baseline determination. It shall have personnel familiar with petroleum 
refining processes, including associated computational procedures, 
methods of product analysis and economics, and expertise in conducting 
the auditing process, including skills for effective data gathering and 
analysis.
    (2) The primary analyst must understand all technical details of the 
entire baseline audit process.
    (3)(i) The primary analyst shall have worked at least five (5) years 
in either refinery operations or as a consultant for the refining 
industry.
    (ii) If one or more computer models designed for refinery planning 
and/or economic analysis are used in the verification of an individual 
baseline, the primary analyst must have at least three (3) years 
experience working with the model(s) utilized in the verification.
    (iii) EPA may, upon petition, waive one or more of the requirements 
specified in paragraph (c)(3) of this section

[[Page 596]]

if the technical capability of the primary analyst is demonstrated to 
the satisfaction of the Director of the Office of Mobile Sources, or 
designee.
    (d) Auditor qualification statement. A statement documenting the 
qualifications of the auditor, primary analyst(s), contractors, 
subcontractors and their organizations must be submitted to EPA (Fuel 
Studies and Standards Branch, Baseline Auditor, U.S. EPA, 2565 Plymouth 
Rd., Ann Arbor, MI 48105).
    (1) Timing. (i) The auditor qualification statement may be submitted 
by the refiner or importer prior to baseline submission (per Sec. 80.93) 
or by a potential auditor at any time. The auditor will be deemed 
certified when all qualifications are met, to the satisfaction of the 
Director of the Office of Mobile Sources, or designee. If no response is 
received from EPA within 45 days of application or today's date, 
whichever is later, the auditor shall be deemed certified.
    (ii) The auditor qualification statement may be submitted by the 
refiner or importer with its baseline submission (per Sec. 80.93). If 
the auditor does not meet the criteria specified in this section, the 
baseline submission will not be accepted.
    (2) Content. The auditor qualification statement must contain all of 
the following information and may contain additional information which 
may aid EPA's review of the qualification statement:
    (i) The name and address of each person and organization involved in 
substantive aspects of the baseline audit, including the auditor, 
primary analyst(s), others within the organization, and contractors and 
subcontractors;
    (ii) The refiners and/or importers for which the auditor, its 
contractors and subcontractors and their organizations do not meet the 
independence criteria described in paragraph (b) of this section; and
    (iii) The technical qualifications and experience of each person 
involved in the baseline audit, including a showing that the 
requirements described in paragraph (c) of this section are met.
    (e) Refiner and importer responsibility. (1) Each refiner and 
importer required to have its baseline verified by an auditor (per 
paragraph (a)(1) of this section) is responsible for utilizing an 
auditor for baseline verification which meets the requirements specified 
in paragraphs (b) and (c) of this section.
    (2) A refiner's or importer's baseline submission will not be 
accepted until it has been verified using an auditor which meets the 
requirements specified in paragraphs (b) and (c) of this section.
    (f) Auditor responsibilities. (1) The auditor must verify that all 
baseline submission requirements are fulfilled. This includes, but is 
not limited to, the following:
    (i) Verifying that all data is correctly accounted for;
    (ii) Verifying that all calculations are performed correctly;
    (iii) Verifying that all adjustments to the data and/or calculations 
to account for post-1990 data, work-in-progress, and/or extenuating or 
other circumstances, as allowed per Sec. 80.91, are valid and performed 
correctly.
    (2) The primary analyst shall prepare and sign a statement, to be 
included in the baseline submission of the refiner or importer, stating 
that:
    (i) He/she has thoroughly reviewed the sampling methodology and 
baseline calculations; and
    (ii) To the best of his/her knowledge, the requirements and 
intentions of the rulemaking are met in the baseline determination; and
    (iii) He/she agrees with the final baseline parameter, volume and 
emission values listed in the baseline submission.
    (3) The auditor may be subject to debarment under U.S.C. 1001 if it 
displays gross incompetency, intentionally commits an error in the 
verification process or misrepresents itself or information in the 
baseline verification.



Sec. 80.93  Individual baseline submission and approval.

    (a) Submission timing. (1) Each refiner, blender or importer shall 
submit two copies of its individual baseline to EPA (Fuel Studies and 
Standards Branch, Baseline Submission, U.S. EPA, 2565 Plymouth Rd., Ann 
Arbor, MI 48105) not later than June 1, 1994.
    (2) If a refiner must collect data after December 15, 1993 (per 
Sec. 80.91(d)(2)), it

[[Page 597]]

shall submit two copies of its individual baseline to EPA (per 
Sec. 80.93(a)(1)) by September 1, 1994.
    (3)(i) All petitions required for baseline adjustments or 
methodology deviations will be approved or disapproved by the Director 
of the Office of Mobile Sources, or designee. All instances where a 
``showing'' or other proof is required are also subject to approval by 
the Director of the Office of Mobile Sources, or designee.
    (ii) Petitions, ``showings,'' and other associated proof may be 
submitted to EPA prior to submittal of the individual baseline (per 
paragraphs (a)(1) and (a)(2) of this section). EPA will attempt to 
review and approve, disapprove or otherwise comment on the petition, 
etc., prior to the deadline for baseline submittal.
    (iii) In the event that EPA does not comment on the petition prior 
to the deadline for baseline submittal, the refiner or importer must 
still comply with the applicable baseline submittal deadline.
    (iv) Petitions submitted prior to the deadline for baseline 
submittals shall be submitted to the EPA at the following address: Fuels 
Studies and Standards Branch, Baseline Petition, U.S. EPA, 2565 Plymouth 
Road, Ann Arbor, Michigan 48105.
    (4) If a baseline recalculation is required per Sec. 80.91(f), 
documentation and recalculation of all affected baselines shall be 
submitted to EPA within 30 days of the previous baseline(s) becoming 
inaccurate due to the circumstances outlined in Sec. 80.91(f).
    (b) Submission content. (1) Individual baseline submissions shall 
include, at minimum, the information specified in this paragraph (b).
    (i) During its review and evaluation of the baseline submission, EPA 
may require a refiner or importer to submit additional information in 
support of the baseline determination.
    (ii) Additional information which may assist EPA during its review 
and evaluation of the baseline may be included at the submitter's 
discretion.
    (2) Administrative information shall include:
    (i) Name and business address of the refiner or importer;
    (ii) Name, business address and business phone number of the company 
contact;
    (iii) Address and physical location of each refinery, terminal or 
import facility;
    (iv) Address and physical location where documents which are 
supportive of the baseline determination for each facility are kept;
    (3) The chief executive officer statement shall be:
    (i) A statement signed by the chief executive officer of the 
company, or designee, which states that:
    (A) The company is complying with the requirements as a refiner, 
blender or importer, as appropriate;
    (B) The data used in the baseline determination is the extent of the 
data available for the determination of all required baseline fuel 
parameters;
    (C) All calculations and procedures followed per Secs. 80.90 through 
80.93 have been done correctly;
    (D) Proper adjustments have been made to the data or in the 
calculations, as applicable;
    (E) The requirements and intentions of the rulemaking have been met 
in determining the baseline fuel parameters; and
    (F) The baseline fuel parameter values determined for each facility 
represent that facility's 1990 gasoline to the fullest extent possible.
    (ii) A refiner or importer which is permitted to utilize the 
parameter values specified in Sec. 80.91(c)(5), and does so, shall 
submit a statement signed by the chief executive officer of the company, 
or designee, indicating that insufficient data exist for a baseline 
determination by the types of data allowed for that entity, as specified 
in Sec. 80.91.
    (4) The auditor-related requirements are:
    (i) Name, address, telephone number and date of hire of each auditor 
hired for baseline verification, whether or not the auditor was retained 
through the baseline approval process.
    (ii) Identification of the auditor responsible for the verification. 
A copy of this auditor's qualification statement, per Sec. 80.92, must 
be included if the auditor has not been approved by EPA, per Sec. 80.92;

[[Page 598]]

    (iii) Indication of the primary analyst(s) involved in each 
refinery's baseline verification; and
    (iv) The signed auditor verification statement, per Sec. 80.92.
    (5) The following baseline information for each refinery, refiner or 
importer, as applicable, shall be provided:
    (i) Individual baseline fuel parameter values, on an oxygenated and 
non-oxygenated basis, and on a summer and winter basis, per Sec. 80.91;
    (ii) Individual baseline exhaust emissions shall be shown 
separately, on a summer, winter and annual average basis (per 
Sec. 80.90) as follows:
    (A) Simple model exhaust benzene emissions;
    (B) Complex model exhaust benzene emissions;
    (C) Complex model exhaust toxics emissions, for Phase I;
    (D) Complex model exhaust NOX emissions, for Phase I, using 
oxygenated individual baseline fuel parameters;
    (E) Complex model exhaust NOX emissions, for Phase I, using 
non-oxygenated individual baseline fuel parameters;
    (F) Complex model exhaust toxics emissions, for Phase II;
    (G) Complex model exhaust NOX emissions, for Phase II, using 
oxygenated individual baseline fuel parameters; and
    (H) Complex model exhaust NOX emissions, for Phase II, using 
non-oxygenated individual baseline fuel parameters;
    (iii) Individual 1990 baseline gasoline volumes, per Sec. 80.91, 
shall be shown separately on a summer, winter and annual average basis; 
and
    (iv) Blendstock-to-gasoline ratios for each calendar year 1990 
through to 1993, per Sec. 80.102.
    (6) Confidential business information.
    (i) Upon approval of an individual baseline, EPA will publish the 
individual annualized baseline exhaust emissions, on an annual average 
basis, specified in paragraph (b)(5)(ii) of this section. Such 
individual baseline exhaust emissions shall not be considered 
confidential. In addition, the reporting information required under 
Sec. 80.75(b)(2)(ii) (D), (G) and (J), and Sec. 80.105(a)(4)(i) (E), (H) 
and (K) shall not be considered confidential.
    (ii) Information in the baseline submission which the submitter 
desires to be considered confidential business information (per 40 CFR 
part 2, subpart B) must be clearly identified. If no claim of 
confidentiality accompanies a submission when it is received by EPA, the 
information may be made available to the public without further notice 
to the submitter pursuant to the provisions of 40 CFR part 2, subpart B.
    (7) Information related to baseline determination as specified in 
Sec. 80.91 and paragraph (c) of this section.
    (c) Additional baseline submission requirements when Method 1-, 2- 
and/or 3-type data is utilized. All requirements of this paragraph shall 
be reported separately for each facility, unless the facilities are 
closely integrated, per Sec. 80.91.
    (1) General. The following information shall be provided:
    (i) The number of months in 1990 during which the facility was 
operating;
    (ii) 1990 summer gasoline production volume, per Sec. 80.91, total 
and by grade, for all gasoline produced but not exported;
    (iii) 1990 winter gasoline production volume, per Sec. 80.91, total 
and by grade, for all gasoline produced, excluding gasoline exported; 
and
    (iv) Whether this facility is actually two facilities which are 
closely integrated, per Sec. 80.91.
    (2) Baseline values. The following shall be included for each fuel 
parameter for which a baseline value is required, per Sec. 80.91:
    (i) Narrative of the development of the baseline value of the fuel 
parameter, including discussion of the sampling and calculation 
methodologies, technical judgment used, effects of petition results on 
calculated values, and any additional information which may assist EPA 
in its review of the baseline;
    (ii) Identification of the data-type(s), per Sec. 80.91, used in the 
determination of a given fuel parameter;
    (iii) Identification of test method. If not per Sec. 80.46, include 
a narrative, explain differences and describing adequacy, per 
Sec. 80.91;

[[Page 599]]

    (iv) Documentation that the minimum sampling requirements per 
Sec. 80.91 have been met;
    (v) Petition and narrative, if needed, for use of less than the 
minimum required data, per Sec. 80.91;
    (vi) Identification of instances of sample compositing per 
Sec. 80.91;
    (vii) Identification of streams for which one or more parameter 
values were deemed negligible per Sec. 80.91; and
    (viii) Discussion of the calculation of oxygenated or non-oxygenated 
fuel parameter values from non-oxygenated or oxygenated values, 
respectively, per Sec. 80.91.
    (3) Method 1. If Method 1-type data is utilized in the baseline 
determination, the following information on 1990 batches of gasoline, or 
shipments if not batch blended, are required by grade shall be provided:
    (i) First and last sampling dates;
    (ii) The following shall be indicated separately on a summer and 
winter basis, by month:
    (A) Number of months sampled;
    (B) Number of 1990 batches, or shipments if not batch blended;
    (C) Total volume of all batches or shipments;
    (D) Number of batches or shipments sampled;
    (E) Total volume of all batches or shipments sampled;
    (F) Baseline fuel parameter value, per Sec. 80.91; and
    (iii) A showing that data was available on every batch of 1990 
gasoline, if applicable, per Sec. 80.91 (b)(3) or (b)(4).
    (4) Method 2. If Method 2-type data is utilized in the baseline 
determination, the following information on each type of 1990 blendstock 
used in the refinery's gasoline are required, by blendstock type shall 
be provided:
    (i) First and last sampling dates; and
    (ii) The following shall be indicated separately on a summer and 
winter basis, by month:
    (A) Number of months sampled;
    (B) Each type of blendstock used in 1990 gasoline and total number 
of blendstocks. Include all blendstocks produced, purchased or otherwise 
received which were blended to produce gasoline within the facility. 
Identify all blendstocks not produced in the facility but used in the 
facility's 1990 gasoline;
    (C) Total volume of each blendstock used in gasoline in 1990;
    (D) Identification of blendstock streams as batch or continuous;
    (E) Number of blendstock samples from continuous blendstock streams;
    (F) Number of blendstock samples from batch processes, including 
volume of each batch sampled; and
    (G) Baseline fuel parameter value, per Sec. 80.91.
    (5) Method 3, blendstock data. The following information on each 
type of post-1990 gasoline blendstock used in the refinery's gasoline 
are required, by blendstock type shall be provided:
    (i) First and last sampling dates;
    (ii) The following shall be indicated separately on a summer and 
winter basis, by month:
    (A) Number of post-1990 months sampled;
    (B) Each type of blendstock used in 1990 gasoline and total number 
of blendstocks. Include all blendstocks produced, purchased or otherwise 
received which were blended to produce gasoline within the facility. 
Identify all blendstocks not produced in the facility but used in the 
facility's 1990 gasoline;
    (C) Total volume of each blendstock used in gasoline in 1990;
    (D) Identification of post-1990 blendstock streams as batch or 
continuous;
    (E) Number of post-1990 blendstock samples from continuous 
blendstock streams;
    (F) Number of post-1990 blendstock samples from batch processes, 
including volume of each batch sampled; and
    (G) Baseline fuel parameter value, per Sec. 80.91; and
    (iii) Support documentation showing that the criteria of Sec. 80.91 
for using Method 3-type blendstock data are met.
    (6) Method 3, post-1990 gasoline data. The following information on 
post-1990 batches of gasoline, or shipments if not batch blended, are 
required by grade:
    (i) First and last sampling dates;
    (ii) The following shall be indicated separately for summer and 
winter production, by month:

[[Page 600]]

    (A) Number of post-1990 months sampled;
    (B) Number of post-1990 batches, or shipments if not batch blended;
    (C) Total volume of all post-1990 batches or shipments;
    (D) Number of post-1990 batches or shipments sampled;
    (E) Volume of each post-1990 batch or shipment sampled; and
    (F) Baseline fuel parameter value, per Sec. 80.91; and
    (iii) Support documentation showing that the criteria of Sec. 80.91 
for using post-1990 gasoline data are met.
    (7) Work-in-progress (WIP). All of the following must be included in 
support of a WIP adjustment (per Sec. 80.91(e)(5)):
    (i) Petition including identification of the specific baseline 
emission(s) or parameter for which the WIP adjustment is desired;
    (ii) Showing that all WIP criteria, per Sec. 80.91(e)(5), are met;
    (iii) Unadjusted and adjusted baseline fuel parameters, emissions 
and volume for the facility; and
    (iv) Narrative, per Sec. 80.91 (e)(5).
    (8) Extenuating circumstances. All of the following must be included 
in support of an extenuating circumstance adjustment (per Sec. 80.91 
(e)(6) through (e)(7)):
    (i) Petition including identification of the allowable circumstance, 
per Sec. 80.91 (e)(6) through (e)(7);
    (ii) Showing that all applicable criteria, per Sec. 80.91 (e)(6) 
through (e)(7), are met;
    (iii) Unadjusted and adjusted baseline fuel parameters, emissions 
and volume for the facility; and
    (iv) Narrative, per Sec. 80.91.
    (9) Other baseline information. Narrative discussing any aspects of 
the baseline determination not already indicated per the requirements of 
paragraph (c)(8) of this section shall be provided.
    (10) Refinery information. The following information, on a summer or 
winter basis, shall be provided:
    (i) Refinery block flow diagram, showing principal refining units;
    (ii) Principal refining unit charge rates and capacities;
    (iii) Crude types utilized (names, gravities, and sulfur content) 
and crude charge rates; and
    (iv) Information on the following units, if utilized in the 
refinery:
    (A) Catalytic Cracking Unit: conversion, unit yields, gasoline fuel 
parameter values (per Sec. 80.91(a)(2));
    (B) Hydrocracking Unit: unit yields, gasoline fuel parameter values 
(per Sec. 80.91(a)(2));
    (C) Catalytic Reformer: unit yields, severities;
    (D) Bottoms Processing Units (including, but not limited to, coking, 
extraction and hydrogen processing): gasoline stream yields;
    (E) Yield structures for other principal units in the refinery 
(including but not limited to Alkylation, Polymerization, Isomerization, 
Etherification, Steam Cracking).

[59 FR 7860, Feb. 16, 1994, as amended at 59 FR 36968, July 20, 1994; 60 
FR 65575, Dec. 20, 1995]
Secs. 80.94--80.100  [Reserved]



Sec. 80.101  Standards applicable to refiners and importers.

    Any refiner or importer of conventional gasoline shall meet the 
standards specified in this section over the specified averaging period, 
beginning on January 1, 1995.
    (a) Averaging period. The averaging period for the standards 
specified in this section shall be January 1 through December 31.
    (b) Conventional gasoline compliance standards--(1) Simple model 
standards. The simple model standards are the following:
    (i) Annual average exhaust benzene emissions, calculated according 
to paragraph (g)(1)(i) of this section, shall not exceed the refiner's 
or importer's compliance baseline for exhaust benzene emissions;
    (ii) Annual average levels of sulfur shall not exceed 125% of the 
refiner's or importer's compliance baseline for sulfur;
    (iii) Annual average levels of olefins shall not exceed 125% of the 
refiner's or importer's compliance baseline for olefins; and
    (iv) Annual average values of T-90 shall not exceed 125% of the 
refiner's or importer's compliance baseline for T-90.

[[Page 601]]

    (v) The provisions of Sec. 80.101 (b)(1)(ii) are stayed until 
October 19, 1995, for all refiners that meet the following requirements:
    (A)(1) Baseline adjustments may be allowed, upon petition and 
approval (per Sec. 80.93), if a refinery meets all of the following 
requirements:
    (i) The refinery does not produce reformulated gasoline. If the 
refinery produces reformulated gasoline at any time in a calendar year, 
its compliance baseline shall revert to its unadjusted baseline values 
for that year and all subsequent years;
    (ii) Has an unadjusted baseline sulfur value of not more than 50 
ppm;
    (iii) Is not aggregated with one or more other refineries per 
Sec. 80.91(f). If a refinery which received an adjustment per this 
paragraph (b)(1)(v) subsequently is included in an aggregate baseline, 
its compliance baseline shall revert to its unadjusted baseline values 
for that year and all subsequent years;
    (iv) Would require refinery improvements of at least $10 million or 
10 percent of the depreciated value of the refinery to comply with its 
unadjusted baseline;
    (v) Can show that it could not reasonably or economically obtain 
crude oil from an alternative source that would permit it to produce 
conventional gasoline which would comply with its unadjusted baseline;
    (vi) Has experienced at least a 25% increase in the average sulfur 
content of the crude oil used in the production of gasoline in the 
refinery since 1990, calculated as follows:
[GRAPHIC] [TIFF OMITTED] TR04AU95.005

Where:

CSHI=highest annual average crude slate per paragraph 
(b)(1)(v)(A)(2)(ii) of this section
CS90=1990 annual average crude slate sulfur per paragraph 
(b)(1)(v)(A)(2)(i) of this section
CS%CHG=percent change in average sulfur content of crude slate; and

    (vii) Can show that gasoline sulfur changes are directly and solely 
attributable to the crude sulfur change, and not due to alterations in 
refinery operation nor choice of products.
    (2) The adjusted baseline sulfur value shall be calculated as 
follows:
    (i) Determine the average sulfur content (ppm) of the crude slate 
utilized in the production of gasoline in the refinery in 1990;
    (ii) Determine the highest crude sulfur level (ppm) of the crude 
slate utilized in the production of gasoline in the refinery in 1994; 
and
    (iii) Determine the adjusted baseline sulfur value as follows:
    [GRAPHIC] [TIFF OMITTED] TR04AU95.006
    
Where:

ASULF=adjusted baseline sulfur value, ppm
BSULF=actual baseline sulfur value, ppm
CSHI=highest crude sulfur (ppm) per paragraph (b)(1)(v)(A)(2)(ii) of 
this section
CS90=1990 annual average crude slate sulfur per paragraph 
(b)(1)(v)(A)(2)(i) of this section

    (3) In no case can the adjusted baseline sulfur value determined per 
paragraph (b)(1)(v)(A)(2) of this section exceed the sulfur value 
specified in Sec. 80.91(c)(5)(iii).
    (4) All adjustments made pursuant to this paragraph (b)(1)(v) must 
be accompanied by:
    (i) Unadjusted and adjusted fuel parameters and emissions; and
    (ii) A narrative describing the situation, the types of 
calculations, and the reasoning supporting the types of calculations 
done to determine the adjusted values.
    (B) Annual average levels of sulfur shall not exceed 125% of the 
refiner's compliance baseline of sulfur, using the adjusted baseline 
determined under paragraph (b)(1)(v)(A) of this section.
    (2) Optional complex model standards. Annual average levels of 
exhaust benzene emissions, weighted by volume for each batch and 
calculated using the applicable complex model under Sec. 80.45, shall 
not exceed the refiner's or importer's 1990 average exhaust benzene 
emissions.
    (3) Complex model standards. Annual average levels of exhaust toxics 
emissions and NOX emissions, weighted by volume for each batch and 
calculated

[[Page 602]]

using the applicable complex model under Sec. 80.45, shall not exceed 
the refiner's or importer's 1990 average exhaust toxics emissions and 
NOX emissions, respectively.
    (c) Applicability of standards. (1) For each averaging period prior 
to January 1, 1998, a refiner or importer shall be subject to either the 
Simple Model or Optional Complex Model Standards, at their option, 
except that any refiner or importer shall be subject to:
    (i) The Simple Model Standards if the refiner or importer uses the 
Simple Model Standards for reformulated gasoline; or
    (ii) The Optional Complex Model Standards if the refiner or importer 
used the Complex Model Standards for reformulated gasoline.
    (2) Beginning January 1, 1998, each refiner and importer shall be 
subject to the Complex Model Standards for each averaging period.
    (d) Product to which standards apply. Any refiner for each refinery, 
or any importer, shall include in its compliance calculations:
    (1) Any conventional gasoline produced or imported during the 
averaging period;
    (2) Any non-gasoline petroleum products that are produced or 
imported and sold or transferred from the refinery or group of 
refineries or importer during the averaging period, if required pursuant 
to Sec. 80.102(e)(2), unless the refiner or importer is able to 
establish in the form of documentation that the petroleum products were 
used for a purpose other than the production of gasoline within the 
United States;
    (3) Any gasoline blending stock produced or imported during the 
averaging period which becomes conventional gasoline solely upon the 
addition of oxygenate;
    (4)(i) Any oxygenate that is added to conventional gasoline, or 
gasoline blending stock as described in paragraph (d)(3) of this 
section, where such gasoline or gasoline blending stock is produced or 
imported during the averaging period;
    (ii) In the case of oxygenate that is added at a point downstream of 
the refinery or import facility, the oxygenate may be included only if 
the refiner or importer can establish the oxygenate was in fact added to 
the gasoline or gasoline blendstock produced, by showing that the 
oxygenate was added by:
    (A) The refiner or importer; or
    (B) By a person other than the refiner or importer, provided that 
the refiner or importer:
    (1) Has a contract with the oxygenate blender that specifies 
procedures to be followed by the oxygenate blender that are reasonably 
calculated to ensure blending with the amount and type of oxygenate 
claimed by the refiner or importer; and
    (2) Monitors the oxygenate blending operation to ensure the volume 
and type of oxygenate claimed by the refiner or importer is correct, 
through periodic audits of the oxygenate blender designed to assess 
whether the overall volumes and type of oxygenate purchased and used by 
the oxygenate blender are consistent with the oxygenate claimed by the 
refiner or importer and that this oxygenate was blended with the 
refiner's or importer's gasoline or blending stock, periodic sampling 
and testing of the gasoline produced subsequent to oxygenate blending, 
and periodic inspections to ensure the contractual requirements imposed 
by the refiner or importer on the oxygenate blender are being met.
    (e) Product to which standards do not apply. Any refiner for each 
refinery, or any importer, shall exclude from its compliance 
calculations:
    (1) Gasoline that was not produced at the refinery or was not 
imported by the importer;
    (2) Blendstocks that have been included in another refiner's 
compliance calculations, pursuant to Sec. 80.102(e)(2) or otherwise;
    (3) California gasoline as defined in Sec. 80.81(a)(2); and
    (4) Gasoline that is exported.
    (f) Compliance baseline determinations. (1) In the case of any 
refiner or importer for whom an individual baseline has been established 
under Sec. 80.91, the individual baseline for each parameter or 
emissions performance shall be the compliance baseline for that refiner 
or importer.
    (2) In the case of any refiner or importer for whom the anti-dumping 
statutory baseline applies under Sec. 80.91, the anti-dumping statutory 
baseline for

[[Page 603]]

each parameter or emissions performance shall be the compliance baseline 
for that refiner or importer.
    (3) In the case of a party that is both a refiner and an importer, 
and for whom an individual 1990 baseline has not been established for 
the imported product under Sec. 80.91(b)(4), the compliance baseline for 
the imported product shall be the 1990 volume weighted average of all of 
the refiner's individual refinery baselines.
    (4) Any compliance baseline under paragraph (f) (1) or (3) of this 
section shall be adjusted for each averaging period as follows:
    (i) If the total volume of the conventional gasoline, RBOB, 
reformulated gasoline, and California gasoline as defined in 
Sec. 80.81(a)(2), produced or imported by any refiner or importer during 
the averaging period is equal to or less than that refiner's or 
importer's 1990 baseline volume as determined under Sec. 80.91(f)(1), 
the compliance baseline for each parameter or emissions performance 
shall be that refiner's or importer's individual 1990 baseline; or
    (ii) If the total volume of the conventional gasoline, RBOB, 
reformulated gasoline, and California gasoline as defined in 
Sec. 80.81(a)(2), produced or imported by any refiner or importer during 
the averaging period is greater than that refiner's or importer's 1990 
baseline volume as determined under Sec. 80.91(f)(1), the compliance 
baseline for each parameter or emissions performance shall be calculated 
according to the following formula:
[GRAPHIC] [TIFF OMITTED] TR20JY94.003

where

CBi = the compliance baseline value for parameter or emissions 
performance i
Bi = the refiner's or importer's individual baseline value for 
parameter or emissions performance i calculated according to the 
methodology in Sec. 80.91
DBi = the anti-dumping statutory baseline value for parameter or 
emissions performance i, as specified at Sec. 80.91(c)(5)(iii) or 
(c)(5)(iv), respectively
V1990 = the 1990 baseline volume as determined under 
Sec. 80.91(f)(1)
Va = the total volume of reformulated gasoline, conventional 
gasoline, RBOB, and California gasoline as defined in Sec. 80.81(a)(2) 
produced or imported by a refiner or importer during the averaging 
period
    (g) Compliance calculations--(1)(i) Simple model calculations. In 
the case of any refiner or importer subject to an individual refinery 
baseline, the annual average value for each parameter or emissions 
performance during the averaging period, calculated according to the 
following methodologies, shall be less than or equal to the refiner's or 
importer's standard under paragraph (b) of this section for that 
parameter.
    (A) The average value for sulfur, T-90, olefin, benzene, and 
aromatics for an averaging period shall be calculated as follows:
[GRAPHIC] [TIFF OMITTED] TR20JY94.004

where

APARM = the average value for the parameter being evaluated
Vi = the volume of conventional gasoline or other products included 
under paragraph (d) of this section, in batch i
PARMi = the value of the parameter being evaluated for batch i as 
determined in accordance with the test methods specified in Sec. 80.46
n = the number of batches of conventional gasoline and other products 
included under paragraph (d) of this

[[Page 604]]

section produced or imported during the averaging period
SGi = specific gravity of batch i (only applicable for sulfur)
    (B) Exhaust benzene emissions under the Simple Model for an 
averaging period are calculated as follows:
[GRAPHIC] [TIFF OMITTED] TR20JY94.005

where

EXHBEN = the average exhaust benzene emissions for the averaging period
BZ = the average benzene content for the averaging period, calculated 
per paragraph (g)(1)(i)(A) of this section
AR = the average aromatics content for the averaging period, calculated 
per paragraph (g)(1)(i)(A) of this section
    (ii) Complex model calculations. Exhaust benzene, exhaust toxics, 
and exhaust NOX emissions performance for each batch shall be 
calculated in accordance with the applicable model under Sec. 80.45.
    (2) In the case of any refiner or importer subject to the anti-
dumping statutory baseline, the refiner or importer shall determine 
compliance using the following methodology:
    (i) Calculate the compliance total for the averaging period for 
sulfur, T-90, olefins, exhaust benzene emissions, exhaust toxics and 
exhaust NOX emissions, as applicable, based upon the anti-dumping 
statutory baseline value for that parameter using the formula specified 
at Sec. 80.67.
    (ii) Calculate the actual total for the averaging period for sulfur, 
T-90, olefins, exhaust benzene emissions, exhaust toxics and exhaust 
NOX emissions, as applicable, based upon the value of the parameter 
for each batch of conventional gasoline and gasoline blendstocks, if 
applicable, using the formula specified at Sec. 80.67.
    (iii) The actual total for exhaust benzene emissions, exhaust toxics 
and exhaust NOX emissions, shall not exceed the compliance total, 
and the actual totals for sulfur, olefins and T-90 shall not exceed 125% 
of the compliance totals, as required under the applicable model.
    (3) In the case of any batch of gasoline that is produced by 
combining blendstock with gasoline, where the gasoline portion of the 
blend is not included in the compliance calculation, the emissions 
performance for exhaust benzene, exhaust toxics, and exhaust NOX 
emissions for the blendstock shall be:
    (i)(A) The emissions performance of a gasoline that would be 
produced by combining the blendstock used at the volume percentage used, 
with a gasoline that has properties that are equal to the refiner's or 
importer's anti-dumping baseline; minus
    (B) The emissions performance of a gasoline that has properties that 
are equal to the refiner's or importer's anti-dumping baseline.
    (ii) The volume weighted net emissions performance for exhaust 
benzene, exhaust toxics, and exhaust NOX emissions, as applicable, 
for all batches of gasoline that are produced during the averaging 
period by combining blendstock with gasoline, shall be equal to or less 
than zero.
    (iii) The value of those properties measured on a weight percent or 
ppm basis shall be adjusted for the specific gravity of the gasoline and 
blendstocks used for the purposes of calculations under paragraph (g)(3) 
of this section.
    (iv) For blends which contain greater than 1.50 volume percent 
ethanol, the RVP of the final blend shall be 1.0 psi greater than the 
RVP of the base gasoline and blendstocks without the ethanol for the 
purposes of calculations under paragraph (g)(3) of this section.
    (v) For blends containing less than 1.50 volume percent ethanol, the 
RVP of the base gasoline and blendstocks without ethanol shall be used 
for the purposes of calculations under paragraph (g)(3) of this section.

[[Page 605]]

    (4) Compliance calculations under this subpart E shall be based on 
computations to the same degree of accuracy that are specified in 
establishing individual baselines under Sec. 80.91.
    (5) The emissions performance of gasoline that has an RVP that is 
equal to or less than the RVP required under Sec. 80.27 (``summer 
gasoline'') shall be determined using the applicable summer complex 
model under Sec. 80.45.
    (6) The emissions performance of gasoline that has an RVP greater 
than the RVP required under Sec. 80.27 (``winter gasoline'') shall be 
determined using the applicable winter complex model under Sec. 80.45, 
using an RVP of 8.7 psi for compliance calculation purposes under this 
subpart E.
    (7)(i) For the 1998 averaging period any refiner or importer may 
elect to determine compliance with the requirement for exhaust NOX 
emissions performance either with or without the inclusion of oxygenates 
in its compliance calculations, in accordance with Sec. 80.91(e)(4), 
provided that the baseline exhaust NOX emissions performance is 
calculated using the same with- or without-oxygen approach.
    (ii)(A) Any refiner or importer must use the with- or without-oxygen 
approach elected under paragraph (g)(7)(i) of this section for all 
subsequent averaging periods; except that
    (B) In the case of any refiner or importer who elects to determines 
compliance for the calendar year 1998 averaging period without the 
inclusion of oxygenates, such refiner or importer may elect to include 
oxygenates in its compliance calculations for the 1999 averaging period.
    (iii) Any refiner or importer who elects to use the with-oxygen 
approach under paragraph (g)(7)(ii)(B) of this section must use this 
approach for all subsequent averaging periods.
    (h) Refinery grouping for determining compliance. (1) Any refiner 
that operates more than one refinery may:
    (i) Elect to achieve compliance individually for the refineries; or
    (ii) Elect to achieve compliance on an aggregate basis for a group, 
or for groups, of refineries, some of which may be individual 
refineries; provided that
    (iii) Compliance is achieved for each refinery separately or as part 
of a group; and
    (iv) The data for any refinery is included only in one compliance 
calculation.
    (2) Any election by a refiner to group refineries under paragraph 
(h)(1) of this section shall:
    (i) Be made as part of the report for the 1995 averaging period 
required by Sec. 80.105;
    (ii) Apply for the 1995 averaging period and for each subsequent 
averaging period, and may not thereafter be changed; and
    (iii) Apply for purposes of the blendstock tracking and accounting 
provisions under Sec. 80.102.
    (3)(i) Any standards under this section shall apply, and compliance 
calculations shall be made, separately for each refinery or refinery 
group; except that
    (ii) Any refiner that produces conventional gasoline for 
distribution to a specified geographic area which is the subject of a 
petition approved by EPA pursuant to Sec. 80.91(f)(3) shall achieve 
compliance separately for gasoline supplied to such specified geographic 
area.
    (i) Sampling and testing. (1) Any refiner or importer shall for each 
batch of conventional gasoline, and other products if included in 
paragraph (d) of this section:
    (i)(A) Determine the value of each of the properties required for 
determining compliance with the standards that are applicable to the 
refiner or importer, by collecting and analyzing a representative sample 
of gasoline or blendstock taken from the batch, using the methodologies 
specified in Sec. 80.46; except that
    (B) Any refiner that produces gasoline by combining blendstock with 
gasoline that has been included in the compliance calculations of 
another refiner or of an importer may for such gasoline meet this 
sampling and testing requirement by collecting and analyzing a 
representative sample of the blendstock used subsequent to each receipt 
of such blendstock if the compliance calculation method specified in 
paragraph (g)(3) of this section is used.

[[Page 606]]

    (ii) Assign a number to the batch (the ``batch number''), as 
specified in Sec. 80.65(d)(3);
    (2) For the purposes of meeting the sampling and testing 
requirements under paragraph (i)(1) of this section, any refiner or 
importer may, prior to analysis, combine samples of gasoline collected 
from more than one batch of gasoline or blendstock (``composite 
sample''), and treat such composite sample as one batch of gasoline or 
blendstock provided that the refiner or importer:
    (i) Meets each of the requirements specified in 
Sec. 80.91(d)(4)(iii) for the samples contained in the composite sample;
    (ii) Combines samples of gasoline that are produced or imported over 
a period no longer than one month;
    (iii) Uses the total of the volumes of the batches of gasoline that 
comprise the composite sample, and the results of the analyses of the 
composite sample, for purposes of compliance calculations under 
paragraph (g) of this section; and
    (iv) Does not combine summer and winter gasoline, as specified under 
paragraphs (g) (5) and (6) of this section, in a composite sample.

[59 FR 7860, Feb. 16, 1994, as amended at 59 FR 36968, July 20, 1994; 60 
FR 40008, Aug. 4, 1995]



Sec. 80.102  Controls applicable to blendstocks.

    (a) For the purposes of this subpart E:
    (1) All of the following petroleum products that are produced by a 
refiner or imported by an importer shall be considered ``applicable 
blendstocks'':
    (i) Reformate;
    (ii) Light coker naphtha;
    (iii) FCC naphtha;
    (iv) Benzene/toluene/xylene;
    (v) Pyrolysis gas;
    (vi) Aromatics;
    (vii) Polygasoline; and
    (viii) Dimate; and
    (2) Any gasoline blendstock with properties such that, if oxygenate 
only is added to the blendstock the resulting blend meets the definition 
of gasoline under Sec. 80.2(c), shall be considered gasoline.
    (b)(1) Any refiner or importer of conventional gasoline or 
blendstocks shall determine the baseline blendstock-to-gasoline ratio 
for each calendar year 1990 through 1993 according to the following 
formula:
[GRAPHIC] [TIFF OMITTED] TR20JY94.006

Where:

BGby=Blendstock-to-gasoline ratio for base year
Vbs = Volume of applicable blendstock produced or imported and 
transferred to others during the calendar year, and used to produce 
gasoline
Vg=Volume of gasoline produced or imported during the calendar year

    (2)(i) Only those volumes of applicable blendstocks for which the 
refiner is able to demonstrate the blendstock was used in the production 
of gasoline may be included in baseline blendstock-to-gasoline ratios 
under paragraph (b)(1) of this section.
    (ii) The baseline volume data for applicable blendstocks and 
gasoline shall be confirmed through the baseline audit requirements 
specified in Sec. 80.92 and submitted in accordance with the 
requirements of Sec. 80.93.
    (c) Any refiner or importer shall calculate the baseline cumulative 
blendstock-to-gasoline ratio according to the following formula:
[GRAPHIC] [TIFF OMITTED] TR16FE94.025

Where:

BGCbase=Baseline cumulative blendstock-to-gasoline ratio
Vbs, i=Volume of applicable blendstock produced or imported and 
transferred to others during calendar year i
Vg, i=Volume of gasoline produced or imported during calendar year 
i
i=each year, 1990 through 1993, for which a blendstock-to-gasoline ratio 
is calculated under paragraph (b) of this section


[[Page 607]]


    (d)(1) For each averaging period, any refiner or importer shall:
    (i) Determine the averaging period blendstock-to-gasoline ratio 
according to the following formula:
[GRAPHIC] [TIFF OMITTED] TR20JY94.007

Where:

BGa=Blendstock-to-gasoline ratio for the current averaging period
Vbs = Volume of applicable blendstock produced or imported and 
subsequently transferred to others during the averaging period
Vg = Volume of conventional gasoline, reformulated gasoline and 
RBOB produced or imported during the averaging period, excluding 
California gasoline as defined in Sec. 80.81(a)(2)

    (ii) For each averaging period until January 1, 1998, calculate the 
peak year blendstock-to-gasoline ratio percentage change according to 
the following formula:
[GRAPHIC] [TIFF OMITTED] TR16FE94.027

Where:

PCp=Peak year blendstock-to-gasoline ratio percentage change
BGa=Blendstock-to-gasoline ratio for the averaging period 
calculated under paragraph (d)(1)(i) of this section
BGp=Largest one year blendstock-to-gasoline ratio calculated under 
paragraph (b) of this section

    (2) Beginning on January 1, 1998, for each averaging period any 
refiner or importer shall:
    (i) Determine the running cumulative compliance period blendstock-
to-gasoline ratio according to the following formula:
[GRAPHIC] [TIFF OMITTED] TR20JY94.008

Where:

 BGCcomp=Running cumulative compliance period blendstock-to-
gasoline ratio
Vbs, i=Volume of applicable blendstock produced or imported and 
transferred to others during averaging period i
Vg,i = Volume of conventional gasoline, reformulated gasoline and 
RBOB produced or imported during averaging period i, excluding 
California gasoline as defined in Sec. 80.81(a)(2)
i=The current averaging period, and each of the three immediately 
preceding averaging periods

    (ii) Calculate the cumulative blendstock-to-gasoline ratio 
percentage change according to the following formula:
[GRAPHIC] [TIFF OMITTED] TR16FE94.029

Where:

PCc=Cumulative blendstock-to-gasoline ratio percentage change
BGCcomp=Running cumulative compliance period blendstock-to-gasoline 
ratio as determined in paragraph (d)(2)(i) of this section
BGCbase=Baseline cumulative blendstock-to-gasoline ratio calculated 
under paragraph (c) of this section

    (3) For purposes of this paragraph (d), all applicable blendstocks 
produced or imported shall be included, except those for which the 
refiner or importer has sufficient evidence in the form of documentation 
that the blendstocks were:
    (i) Exported;
    (ii) Used for other than gasoline blending purposes;
    (iii) Transferred to a refiner that used the blendstock as a 
``feedstock'' in a refining process during which the blendstock 
underwent a substantial chemical or physical transformation; or
    (iv) Transferred between refineries which have been grouped pursuant 
to Sec. 80.101(h) by a refiner for the purpose of determining compliance 
under this subpart; or
    (v) Used to produce California gasoline as defined in 
Sec. 80.81(a)(2).

[[Page 608]]

    (e)(1) Any refiner or importer shall have exceeded the blendstock-
to-gasoline ratio percentage change threshold if:
    (i) The peak year blendstock-to-gasoline ratio percentage change 
calculated under paragraph (d)(1)(ii) of this section is more than ten; 
or
    (ii) Beginning on January 1, 1998, the cumulative blendstock-to-
gasoline ratio percentage change calculated under paragraph (d)(2)(ii) 
of this section is more than ten.
    (2) Any refiner or importer that exceeds the blendstock-to-gasoline 
ratio percentage change threshold shall, without further notification:
    (i) Include all blendstocks produced or imported and transferred to 
others in its compliance calculations under Sec. 80.101(g) for two 
averaging periods beginning on January 1 of the averaging period 
subsequent to the averaging period when the exceedance occurs;
    (ii) Provide transfer documents to the recipient of such blendstock 
that contain the language specified at Sec. 80. 106(b); and
    (iii) Transfer such blendstock in a manner such that the ultimate 
blender of such blendstocks has a reasonable basis to know that such 
blendstock has been accounted for.
    (3) Any refiner or importer that has previously exceeded the 
blendstock-to-gasoline ratio percentage change threshold, and 
subsequently exceeds the threshold for an averaging period and is not 
granted a waiver pursuant to paragraph (f)(2)(i) of this section, shall, 
without further notification, meet the requirements specified in 
paragraphs (e)(2) (i) through (iii) of this section for four averaging 
periods, beginning on January 1 of the averaging period following the 
averaging period when the subsequent exceedance occurs.
    (f)(1) The refiner or importer blendstock accounting requirements 
specified under paragraph (e) of this section shall not apply in the 
case of any refiner or importer:
    (i) Whose 1990 baseline value for each regulated fuel property and 
emission performance, as determined in accordance with Secs. 80.91 and 
80.92, is less stringent than the anti-dumping statutory baseline value 
for that parameter or emissions performance;
    (ii) Whose averaging period blendstock-to-gasoline ratio, calculated 
according to paragraph (d)(1)(i) of this section, is equal to or less 
than .0300; or
    (iii) Who obtains a waiver from EPA, provided that a petition for 
such a waiver is filed no later than fifteen days following the end of 
the averaging period for which the blendstock-to-gasoline ratio 
percentage change threshold is exceeded.
    (2)(i) EPA may grant the waiver referred to in paragraph (f)(1)(iii) 
of this section if the level of blendstock production was the result of 
extreme or unusual circumstances (e.g., a natural disaster or act of 
God) which clearly are outside the control of the refiner or importer, 
and which could not have been avoided by the exercise of prudence, 
diligence, and due care.
    (ii) Any petition filed under paragraph (f) of this section shall 
include information which describes the extreme or unusual circumstance 
which caused the increased volume of blendstock produced or imported, 
the steps taken to avoid the circumstance, and the steps taken to remedy 
or mitigate the effect of the circumstance.
    (g) Notwithstanding the requirements of paragraphs (a) through (f) 
of this section, any refiner or importer that transfers applicable 
blendstock to another refiner or importer with a less stringent baseline 
requirement, either directly or indirectly, for the purpose of evading a 
more stringent baseline requirement, shall include such blendstock(s) in 
determining compliance with the applicable requirements of this subpart.

[59 FR 7860, Feb. 16, 1994, as amended at 59 FR 36969, July 20, 1994]



Sec. 80.103  Registration of refiners and importers.

    Any refiner or importer of conventional gasoline must register with 
the Administrator in accordance with the provisions specified at 
Sec. 80.76.



Sec. 80.104  Recordkeeping requirements.

    Any refiner or importer shall maintain records containing the 
information as required by this section.
    (a) Beginning in 1995, for each averaging period:

[[Page 609]]

    (1) Documents containing the information specified in paragraph 
(a)(2) of this section shall be obtained for:
    (i) Each batch of conventional gasoline, and blendstock if 
blendstock accounting is required under Sec. 80.102(e)(2); or
    (ii) Each batch of blendstock received in the case of any refiner 
that determines compliance on the basis of blendstocks properties under 
Sec. 80.101(g)(3).
    (2)(i) The results of tests performed in accordance with 
Sec. 80.101(i);
    (ii) The volume of the batch;
    (iii) The batch number;
    (iv) The date of production, importation or receipt;
    (v) The designation regarding whether the batch is summer or winter 
gasoline;
    (vi) The product transfer documents for any conventional gasoline 
produced or imported;
    (vii) The product transfer documents for any conventional gasoline 
received;
    (viii) For any gasoline blendstocks received by or transferred from 
a refiner or importer, documents that reflect:
    (A) The identification of the product;
    (B) The date the product was transferred; and
    (C) The volume of product;
    (ix) In the case of any refinery-produced or imported products 
listed in Sec. 80.102(a) that are excluded under Sec. 80.102(d)(3), 
documents which demonstrate that basis for exclusion; and
    (x) In the case of oxygenate that is added by a person other than 
the refiner or importer under Sec. 80.101(d)(4)(ii)(B), documents that 
support the volume of oxygenate claimed by the refiner or importer, 
including the contract with the oxygenate blender and records relating 
to the audits, sampling and testing, and inspections of the oxygenate 
blender operation.
    (b) Any refiner or importer shall retain the documents required in 
this section for a period of five years from the date the conventional 
gasoline or blendstock is produced or imported, and deliver such 
documents to the Administrator of EPA upon the Administrator's request.

[59 FR 7860, Feb. 16, 1994, as amended at 59 FR 36969, July 20, 1994]



Sec. 80.105  Reporting requirements.

    (a) Beginning with the 1995 averaging period, and for each 
subsequent averaging period, any refiner for each refinery or group of 
refineries at which any conventional gasoline is produced, and any 
importer that imports any conventional gasoline, shall submit to the 
Administrator a report which contains the following information:
    (1) The total gallons of conventional gasoline produced or imported;
    (2)(i) The total gallons of applicable blendstocks produced or 
imported and transferred to others that are not excluded under 
Sec. 80.102(d)(3); and
    (ii) The total gallons of applicable blendstocks produced or 
imported and transferred to others that are excluded under 
Sec. 80.102(d)(3);
    (3) The total gallons of blendstocks included in compliance 
calculations pursuant to Sec. 80.102(e)(2);
    (4)(i) If using the simple model:
    (A) The applicable exhaust benzene emissions standard under 
Sec. 80.101(b)(1)(i);
    (B) The average exhaust benzene emissions under Sec. 80.101(g);
    (C) The applicable sulfur content standard under 
Sec. 80.101(b)(1)(ii) in parts per million;
    (D) The average sulfur content under Sec. 80.101(g) in parts per 
million;
    (E) The difference between the applicable sulfur content standard 
under Sec. 80.101(b)(1)(ii) in parts per million and the average sulfur 
content under paragraph (a)(4)(i)(D) of this section in parts per 
million, indicating whether the average is greater or lesser than the 
applicable standard;
    (F) The applicable olefin content standard under 
Sec. 80.101(b)(1)(iii) in volume percent;
    (G) The average olefin content under Sec. 80.101(g) in volume 
percent;
    (H) The difference between the applicable olefin content standard 
under Sec. 80.101(b)(1)(iii) in volume percent and the average olefin 
content under paragraph (a)(4)(i)(G) of this section in volume percent, 
indicating whether the average is greater or lesser than the applicable 
standard;
    (I) The applicable T90 distillation point standard under 
Sec. 80.101(b)(1)(iv) in degrees Fahrenheit;

[[Page 610]]

    (J) The average T90 distillation point under Sec. 80.101(g) in 
degrees Fahrenheit; and
    (K) The difference between the applicable T90 distillation point 
standard under Sec. 80.101(b)(1)(iv) in degrees Fahrenheit and the 
average T90 distillation point under paragraph (a)(4)(i)(J) of this 
section in degrees Fahrenheit, indicating whether the average is greater 
or lesser than the applicable standard.
    (ii) If using the optional complex model, the applicable exhaust 
benzene emissions standard and the average exhaust benzene emissions, 
under Sec. 80.101(b)(2) and (g).
    (iii) If using the complex model:
    (A) The applicable exhaust toxics emissions standard and the average 
exhaust toxics emissions, under Sec. 80.101(b)(3) and (g); and
    (B) The applicable NOX emissions standard and the average 
NOX emissions, under Sec. 80.101(b)(3) and (g).
    (5) The following information for each batch of conventional 
gasoline or batch of blendstock included under paragraph (a) of this 
section:
    (i) The batch number;
    (ii) The date of production;
    (iii) The volume of the batch;
    (iv) The grade of gasoline produced (i.e., premium, mid-grade, or 
regular); and
    (v) The properties, pursuant to Sec. 80.101(i); and
    (6) Such other information as EPA may require.
    (b) The reporting requirements of paragraph (a) of this section do 
not apply in the case of any conventional gasoline or gasoline 
blendstock that is excluded from a refiner's or importer's compliance 
calculation pursuant to Sec. 80.101(e).
    (c) For each averaging period, each refiner and importer shall cause 
to be submitted to the Administrator of EPA, by May 30 of each year, a 
report in accordance with the requirements for the Attest Engagements of 
Secs. 80.125 through 80.131.
    (d) The report required by paragraph (a) of this section shall be:
    (1) Submitted on forms and following procedures specified by the 
Administrator of EPA;
    (2) Submitted to EPA by the last day of February each year for the 
prior calendar year averaging period; and
    (3) Signed and certified as correct by the owner or a responsible 
corporate officer of the refiner or importer.

[59 FR 7860, Feb. 16, 1994, as amended at 59 FR 36969, July 20, 1994; 60 
FR 65575, Dec. 20, 1995]



Sec. 80.106  Product transfer documents.

    (a)(1) On each occasion when any person transfers custody or title 
to any conventional gasoline, the transferor shall provide to the 
transferee documents which include the following information:
    (i) The name and address of the transferor;
    (ii) The name and address of the transferee;
    (iii) The volume of gasoline being transferred;
    (iv) The location of the gasoline at the time of the transfer;
    (v) The date of the transfer;
    (vi) In the case of transferors or transferees who are refiners or 
importers, the EPA-assigned registration number of those persons; and
    (vii) The following statement: ``This product does not meet the 
requirements for reformulated gasoline, and may not be used in any 
reformulated gasoline covered area.''
    (2) The requirements of paragraph (a)(1) of this section apply to 
product that becomes gasoline upon the addition of oxygenate only.
    (b) On each occasion when any person transfers custody or title to 
any blendstock that has been included in the refiner's or importer's 
compliance calculations under Sec. 80.102(e)(2), the transferor shall 
provide to the transferee documents which include the following 
statement: ``For purposes of the Anti-Dumping requirements under 40 CFR 
part 80, subpart E, this blendstock has been accounted for by the 
refiner that produced it, and must be excluded from any subsequent 
compliance calculations.''

[[Page 611]]



Secs. 80.107-80.124  [Reserved]



                      Subpart F--Attest Engagements

    Source: 59 FR 7875, Feb. 16, 1994, unless otherwise noted.



Sec. 80.125  Attest engagements.

    (a) Any refiner, importer, and oxygenate blender subject to the 
requirements of this subpart F shall engage an independent certified 
public accountant, or firm of such accountants (hereinafter referred to 
in this subpart F as ``CPA''), to perform an agreed-upon procedure 
attestation engagement of the underlying documentation that forms the 
basis of the reports required by Secs. 80.75 and 80.105.
    (b) The CPA shall perform the attestation engagements in accordance 
with the Statements on Standards for Attestation Engagements.
    (c) The CPA may complete the requirements of this subpart F with the 
assistance of internal auditors who are employees or agents of the 
refiner, importer, or oxygenate blender, so long as such assistance is 
in accordance with the Statements on Standards for Attestation 
Engagements.
    (d) Notwithstanding the requirements of paragraph (a) of this 
section, any refiner, importer, or oxygenate blender may satisfy the 
requirements of this subpart F if the requirements of this subpart F are 
completed by an auditor who is an employee of the refiner, importer, or 
oxygenate blender, provided that such employee:
    (1) Is an internal auditor certified by the Institute of Internal 
Auditors, Inc. (hereinafter referred to in this subpart F as ``CIA''); 
and
    (2) Completes the internal audits in accordance with the 
Codification of Standards for the Professional Practice of Internal 
Auditing.
    (e) Use of a CPA or CIA who is debarred, suspended, or proposed for 
debarment pursuant to the Governmentwide Debarment and Suspension 
Regulations, 40 CFR part 32, or the Debarment, Suspension, and 
Ineligibility Provisions of the Federal Acquisition Regulations, 48 CFR 
part 9, subpart 9.4, shall be deemed in noncompliance with the 
requirements of this section.
    (f) The following documents are incorporated by reference: the 
Statements on Standards for Attestation Engagements, Codification of 
Statements on Auditing Standards, written by the American Institute of 
Certified Public Accountants, Inc., 1991, and published by the Commerce 
Clearing House, Inc., Identification Number 059021, and the Codification 
of Standards for the Professional Practice of Internal Auditing, written 
and published by the Institute of Internal Auditors, Inc., 1989, 
Identification Number ISBN 0-89413-207-5. These incorporations by 
reference were approved by the Director of the Federal Register in 
accordance with 5 U.S.C. 552(a) and 1 CFR part 51. Copies of the 
Statements on Standards for Attestation Engagements may be obtained from 
the American Institute of Certified Public Accountants, Inc., 1211 
Avenue of the Americas, New York, New York 10036, and copies of the 
Codification of Standards for the Professional Practice of Internal 
Auditing may be obtained from the Institute of Internal Auditors, Inc., 
249 Maitland Avenue, Altamonte Springs, Florida 32701-4201. Copies may 
be inspected at the U.S. Environmental Protection Agency, Office of the 
Air Docket, 401 M Street, SW., Washington, DC., or at the Office of the 
Federal Register, 800 North Capitol Street, NW., suite 700, Washington 
DC.

[59 FR 7875, Feb. 16, 1994, as amended at 59 FR 36969, July 20, 1994]



Sec. 80.126  Definitions.

    The following definitions shall apply for the purposes of this 
subpart F:
    (a) Averaging compliance records shall include the calculations used 
to determine compliance with relevant standards on average, for each 
averaging period and for each quantity of gasoline for which standards 
must be achieved separately.
    (b) Credit trading records shall include worksheets and EPA reports 
showing actual and complying totals for oxygen and benzene; credit 
calculation worksheets; contracts; letter agreements; and invoices and 
other documentation evidencing the transfer of credits.

[[Page 612]]

    (c) Designation records shall include laboratory analysis reports 
that identify whether gasoline meets the requirements for a given 
designation; operational and accounting reports of product storage; and 
product transfer documents.
    (d) Oxygenate blender records shall include laboratory analysis 
reports; refiner, importer and oxygenate blender contracts; quality 
assurance program records; product transfer documents; oxygenate 
purchasing, inventory, and usage records; and daily tank inventory 
gauging reports, meter tickets, and product transfer documents.
    (e) Product transfer documents shall include documents that reflect 
the transfer of ownership or physical custody of gasoline or blendstock, 
including invoices, receipts, bills of lading, manifests, and pipeline 
tickets.
    (f) A tender means the physical transfer of custody of a volume of 
gasoline or other petroleum product all of which has the same 
identification (reformulated gasoline, conventional gasoline, RBOB, and 
other non-finished gasoline petroleum products), and characteristics 
(time and place of use restrictions for reformulated gasoline).
    (g) Volume records shall include summaries of gasoline produced or 
imported that account for the volume of each type of gasoline produced 
or imported. The volumes shall be based on tank gauges or meter reports 
and temperature adjusted to 60 degrees Fahrenheit.



Sec. 80.127  Sample size guidelines.

    In performing the attest engagement, the auditor shall sample 
relevant populations to which agreed-upon procedures will be applied 
using the methods specified in this section, which shall constitute a 
representative sample.
    (a) Sample items shall be selected in such a way as to comprise a 
simple random sample of each relevant population; and
    (b) Sample size shall be determined using one of the following 
options:
    (1) Option 1. Determine the sample size using the following table:

                 Sample Size, Based Upon Population Size                
------------------------------------------------------------------------
           No. in population (N)                     Sample size        
------------------------------------------------------------------------
66 and larger.............................  29                          
41-65.....................................  25                          
26-40.....................................  20                          
0-25......................................  N or 19, whichever is       
                                             smaller.                   
------------------------------------------------------------------------

    (2) Option 2. Determine the sample size in such a manner that the 
sample size is equal to that which would result by using the following 
parameters and standard statistical methodologies:

Confidence Level--95%
Expected Error Rate--0%
Maximum Tolerable Error Rate--10%

    (3) Option 3. The auditor may use some other form of sample 
selection and/or some other method to determine the sample size, 
provided that the resulting sample affords equal or better strength of 
inference and freedom from bias (as compared with paragraphs (b)(1) and 
(2) of this section), and that the auditor summarizes the substitute 
methods and clearly demonstrates their equivalence in the final report 
on the audit.



Sec. 80.128  Agreed upon procedures for refiners and importers.

    The following are the minimum attest procedures that shall be 
carried out for each refinery and importer. Agreed upon procedures may 
vary from the procedures stated in this section due to the nature of the 
refiner's or importer's business or records, provided that any refiner 
or importer desiring to modify procedures obtains prior approval from 
EPA.
    (a) Read the refiner's or importer's reports filed with EPA for the 
previous year as required by Secs. 80.75, 80.83(g), and 80.105.
    (b) Obtain a gasoline inventory reconciliation analysis for the 
current year from the refiner or importer which includes reformulated 
gasoline, RBOB, conventional gasoline, and non-finished-gasoline 
petroleum products.
    (1) Test the mathematical accuracy of the calculations contained in 
the analysis.
    (2) Agree the beginning and ending inventories to the refiner's or 
importer's perpetual inventory records.

[[Page 613]]

    (c) Obtain separate listings of all tenders during the current year 
of reformulated gasoline, RBOB, conventional gasoline, and non-finished-
gasoline petroleum products.
    (1) Test the mathematical accuracy of the calculations contained in 
the listings.
    (2) Agree the listings of tenders' volumes to the gasoline inventory 
reconciliation in paragraph (b) of this section.
    (3) Agree the listings of tenders' volumes, where applicable, to the 
EPA reports.
    (d) Select a representative sample from the listing of reformulated 
gasoline tenders, and for this sample:
    (1) Agree the volumes to the product transfer documents;
    (2) Compare the product transfer documents designation for 
consistency with the time and place, and compliance model designations 
for the tender (VOC-controlled or non-VOC-controlled, VOC region for 
VOC-controlled, OPRG versus non-OPRG, summer or winter gasoline, and 
simple or complex model certified); and
    (3) Trace back to the batch or batches in which the gasoline was 
produced or imported. Obtain the refiner's or importer's internal 
laboratory analyses for each batch and compare such analyses for 
consistency with the analyses results reported to EPA and to the time 
and place designations for the tender's product transfer documents.
    (e) Select a representative sample from the listing of RBOB tenders, 
and for this sample:
    (1) Agree the volumes to the original product transfer documents;
    (2) Determine that the requisite contract was in place with the 
downstream blender designating the required blending procedures, or that 
the refiner or importer accounted for the RBOB using the assumptions in 
Sec. 80.69(a)(8) in the case of RBOB designated as ``any oxygenate,'' or 
``ether only,'' or using the assumptions in Secs. 80.83(c)(1)(ii) (A) 
and (B) in the case of RBOB designated as ``any renewable oxygenate,'' 
``non VOC controlled renewable ether only,'' or ``renewable ether 
only'';
    (3) Review the product transfer documents for the indication of the 
type and amount of oxygenate required to be added to the RBOB;
    (4) Trace back to the batch or batches in which the RBOB was 
produced or imported. Obtain refiner's or importer's internal lab 
analysis for each batch and agree the consistency of the type and volume 
of oxygenate required to be added to the RBOB with that indicated in 
applicable tender's product transfer documents;
    (5) Agree the sampling and testing frequency of the refiner's or 
importer's downstream oxygenated blender quality assurance program with 
the sampling and testing rates as required in Sec. 80.69(a)(7); and
    (6) In the case of RBOB designated as ``any renewable oxygenate,'' 
``non VOC controlled renewable ether'' or ``renewable ether only'', 
review the documentation from the producer of the oxygenate to determine 
if the oxygenate meets the requirements of Sec. 80.83(a).
    (f) Select a representative sample of reformulated gasoline and RBOB 
batches produced by computerized in-line blending, and for this sample:
    (1) Obtain the composite sample internal laboratory analyses 
results; and
    (2) Agree the results of the internal laboratory analyses to the 
quarterly batch information submitted to the EPA.
    (g) Select a representative sample from the listing of the tenders 
of conventional gasoline and conventional gasoline blendstock that 
becomes gasoline through the addition of oxygenate only, and for this 
sample:
    (1) Agree the volumes to the product transfer documents;
    (2) For a representative sample of tenders, trace back to the batch 
or batches in which the gasoline was produced or imported. Obtain the 
refiner's or importer's internal laboratory analyses for each batch and 
compare such analyses for consistency with the analyses results reported 
to EPA; and
    (3) Where the refiner or importer has included oxygenate that is 
blended downstream of the refinery or import facility in its compliance 
calculations in accordance with Sec. 80.101(d)(4)(ii), obtain a listing 
of each downstream oxygenate blending operation from which

[[Page 614]]

the refiner or importer is claiming oxygenate for use in compliance 
calculations, and for each such operation:
    (i) Determine if the refiner or importer had a contract in place 
with the downstream blender during the period oxygenate was blended;
    (ii) Determine if the refiner or importer has records reflecting 
that it conducted physical inspections of the downstream blending 
operation during the period oxygenate was blended;
    (iii) Obtain a listing from the refiner or importer of the batches 
of conventional gasoline or conventional sub-octane blendstock, and the 
compliance calculations which include oxygenate blended by the 
downstream oxygenate blender, and test the mathematical accuracy of the 
calculations contained in this listing;
    (iv) Obtain a listing from the downstream oxygenate blender of the 
oxygenate blended with conventional gasoline or sub-octane blendstock 
that was produced or imported by the refiner or importer. Test the 
mathematical accuracy of the calculations in this listing. Agree the 
overall oxygenate blending listing obtained from the refiner or importer 
with the listing obtained from the downstream oxygenate blender. Select 
a representative sample of oxygenate blending listing obtained from the 
downstream oxygenate blender, and for this sample:
    (A) Using product transfer documents, determine if the oxygenate was 
blended with conventional gasoline or conventional sub-octane blendstock 
that was produced by the refiner or imported by the importer; and
    (B) Agree the oxygenate volume with the refiner's or importer's 
listing of oxygenate claimed for this gasoline;
    (v) Obtain a listing of the sampling and testing conducted by the 
refiner or importer over the downstream oxygenate blending operation. 
Select a representative sample of the test results from this listing, 
and for this sample agree the tested oxygenate volume with the oxygenate 
use listings from the refiner or importer, and from the oxygenate 
blender; and
    (vi) Obtain a copy of the records reflecting the refiner or importer 
audit over the downstream oxygenate blending operation. Review these 
records for indications that the audit included review of the overall 
volumes and type of oxygenate purchased and used by the oxygenate 
blender to be consistent with the oxygenate claimed by the refiner or 
importer and that this oxygenate was blended with the refiner's or 
importer's gasoline or blending stock.
    (h) In the case of a refiner or importer that is not exempt from 
blendstock tracking under Sec. 80.102(f):
    (1) Obtain listings for those tenders of non-finished-gasoline 
classified by the refiner or importer as:
    (i) Applicable blendstock which is included in the refiner's or 
importer's blendstock tracking calculations pursuant to Sec. 80.102(b) 
through (d);
    (ii) Applicable blendstock which is exempt pursuant to 
Sec. 80.102(d)(3) from inclusion in the refiner's or importer's 
blendstock tracking calculations pursuant to Sec. 80.102 (b) through 
(d); and
    (iii) All other non-finished-gasoline petroleum products.
    (2) Test the mathematical accuracy of the calculations contained in 
the analysis.
    (3) Agree the listings of tenders' volumes to the gasoline inventory 
reconciliation in paragraph (b) of this section.
    (4) Agree the EPA report for the volume classified as applicable 
blendstock pursuant to the requirements of Sec. 80.102.
    (5) Select a representative sample from the listing of applicable 
blendstock which is reported to EPA, and for such sample:
    (i) Agree the volumes to records supporting the transfer of the 
tender to another person; and
    (ii) Trace back to the batch or batches in which the non-finished-
gasoline petroleum product was produced or imported. Obtain the 
refiner's or importer's internal laboratory analysis for each batch and 
compare such analysis for consistency with the product type assigned by 
the refiner or importer (e.g., reformate, light coker naphtha, etc.), 
and that this product type is included in the applicable blendstock list 
at Sec. 80.102(a).
    (6) Select a representative sample from the listing of applicable

[[Page 615]]

blendstock which is exempt from inclusion in the blendstock tracking 
report to EPA, and for such sample:
    (i) Agree the volumes to records supporting the transfer of the 
tender to another person;
    (ii) Trace back to the batch or batches in which the non-finished-
gasoline petroleum product was produced or imported. Obtain the 
refiner's or importer's internal laboratory analysis for each batch and 
compare such analysis for consistency with the product type assigned by 
the refiner or importer (e.g., reformate, light coker naphtha, etc.), 
and that this product type is included in the applicable blendstock list 
at Sec. 80.102(a); and
    (iii) Obtain the documents that demonstrate the purpose for which 
the product was used, and agree that the documented purpose is one of 
those specified at Sec. 80.102(d)(3).
    (7) Select a representative sample from the listing of all other 
non-finished-gasoline petroleum products, and for such sample:
    (i) Agree the volumes to records supporting the transfer of the 
tender to another person;
    (ii) Trace back to the batch or batches in which the non-finished-
gasoline petroleum product was produced or imported. Obtain the 
refiner's or importer's internal laboratory analysis for each batch and 
compare such analysis for consistency with the product-type assigned by 
the refiner or importer (e.g., alkylate, isobutane, etc.), and agree 
that this product type is excluded from the applicable blendstock list 
at Sec. 80.102(a).
    (i) In the case of a refiner or importer required to account for 
blendstocks produced or imported under Sec. 80.102(e)(2):
    (1) Obtain listings for those tenders of non-finished-gasoline 
tenders classified by the refiner or importer as:
    (i) Blendstock which is included in the compliance calculations for 
the refinery or importer; and
    (ii) All other non-finished-gasoline petroleum products;
    (2) Test the mathematical accuracy of the calculations contained in 
the listings under paragraph (i)(1) of this section;
    (3) Agree the listings of tenders' volumes to the gasoline inventory 
reconciliation in paragraph (b) of this section;
    (4) Select a representative sample from the listing of blendstock 
tenders which are included in the compliance calculations for the 
refinery or importer, and for such sample:
    (i) Agree the volumes to records supporting the transfer of the 
tender to another person;
    (ii) Review the product transfer documents for the statement 
indicating the blendstock has been accounted-for, and may not be 
included in another party's compliance calculations; and
    (iii) Trace back to the batch or batches in which the blendstock was 
produced or imported. Obtain the refiner's or importer's internal 
laboratory analyses for each batch and compare such analyses for 
consistency with the analyses results reported to EPA; and
    (5) Select a representative sample from the listing of tenders of 
non-finished-gasoline petroleum products that are excluded from the 
refiner's or importer's compliance calculations, and for such sample 
confirm that documents demonstrate the petroleum products were used for 
a purpose other than the production of gasoline within the United 
States.

[59 FR 7875, Feb. 16, 1994, as amended at 59 FR 36969, July 20, 1994; 59 
FR 39292, Aug. 2, 1994]

    Effective Date Note: At 59 FR 39292, Aug. 2, 1994, Sec. 80.128 was 
amended by revising paragraphs (a) and (e)(2); removing ``and'' at the 
end of paragraph (e)(4); removing the period at the end of paragraph 
(e)(5) and adding ``; and'' in its place; and adding paragraph (e)(6) 
effective September 1, 1994. At 59 FR 60715, Nov. 28, 1994, the 
amendment was stayed effective September 13, 1994.



Sec. 80.129  Agreed upon procedures for downstream oxygenate blenders.

    The following are the procedures to be carried out at each oxygenate 
blending facility that is subject to the requirements of this subpart F:
    (a) Read the oxygenate blender's reports filed with the EPA for the 
previous year as required by Secs. 80.75 and 80.83(g).
    (b) Obtain a material balance analysis summarizing receipts of RBOB 
and

[[Page 616]]

oxygenate to the blender, and the deliveries of reformulated gasoline 
from the blender.
    (1) Test the mathematical accuracy of the calculations contained in 
the analysis.
    (2) Agree the beginning and ending inventory to the blender's 
perpetual inventory records.
    (3) Agree the analysis, where applicable, to the EPA reports.
    (c) Obtain a listing of all RBOB receipts for the previous year.
    (1) Test the mathematical accuracy of the volumetric calculations 
contained in the listing.
    (2) Agree the volumetric calculations of RBOB receipts to the 
calculations contained in the material balance analysis.
    (3) Select a representative sample of RBOB receipts from the 
listing. Review the product transfer documents for the indication of the 
type and volume of oxygenate required to be added to the RBOB.
    (d) Obtain a listing of all reformulated gasoline batches produced 
by the blender during the previous year.
    (1) Test the mathematical accuracy of the volumetric calculations 
contained in the listing.
    (2) Agree the volumetric calculations contained in the listing to 
the calculations contained in the material balance analysis.
    (3) Select a representative sample of the batches from the listing, 
and for these batches:
    (i) Obtain the blender's records that indicate the volume and type 
of oxygenate that was blended, the volume of RBOB that was blended and 
the product transfer documents for the RBOB, and the internal lab 
analysis where applicable;
    (ii) Agree the consistency of the type and volume of oxygenate added 
to the RBOB with that indicated to be added in the RBOB's product 
transfer documents;
    (iii) In the case of RBOB designated as ``any renewable oxygenate,'' 
``non VOC controlled renewable ether only,'' or ``renewable ether 
only,'' review the documentation from the producer of the oxygenate to 
determine if the oxygenate meets the requirements of Sec. 80.83(a);
    (iv) Recalculate the actual oxygen content based on the volumes 
blended and agree to the report to EPA on oxygen; and
    (v) Review the time and place designations in the product transfer 
documents prepared for the batch by the blender, for consistency with 
the time and place designations in the product transfer documents for 
the RBOB (e.g., VOC-controlled or non-VOC-controlled, VOC region for 
VOC-controlled, OPRG versus non-OPRG, and simple or complex model).
    (e) Agree the sampling and testing frequency of the blender's 
quality assurance program with the sampling and testing rates required 
in Sec. 80.69.

[59 FR 7875, Feb. 16, 1994, as amended at 59 FR 36969, July 20, 1994; 59 
FR 39292, Aug. 2, 1994]

    Effective Date Note: At 59 FR 39292, Aug. 2, 1994, Sec. 80.129 was 
amended by revising paragraphs (a), (d)(3)(iii) and (d)(3)(iv), and 
adding paragraph (d)(3)(v) effective September 1, 1994. At 59 FR 60715, 
Nov. 28, 1994, the amendment was stayed effective September 13, 1994.



Sec. 80.130  Agreed upon procedures reports.

    (a) Reports. (1) The CPA or CIA shall issue to the refiner, 
importer, or blender a report summarizing the procedures performed and 
the findings in accordance with the attest engagement or internal audit 
performed in compliance with this subpart.
    (2) The refiner, importer or blender shall provide a copy of the 
auditor's report to the EPA within the time specified in Sec. 80.75(m).
    (b) Record retention. The CPA or CIA shall retain all records 
pertaining to the performance of each agreed upon procedure and 
pertaining to the creation of the agreed upon procedures report for a 
period of five years from the date of creation and shall deliver such 
records to the Administrator upon request.
Secs. 80.131--80.135  [Reserved]



                      Subpart G--Detergent Gasoline

    Source: 59 FR 54706, Nov. 1, 1994, unless otherwise noted.

[[Page 617]]



Sec. 80.140  Definitions.

    The definitions in this section apply only to subpart G of this 
part. Any terms not defined in this subpart shall have the meaning given 
them in 40 CFR part 80, subpart A, or, if not defined in 40 CFR part 80, 
subpart A, shall have the meaning given them in 40 CFR part 79, subpart 
A.
    Additization means the addition of detergent to gasoline or post-
refinery component in order to create detergent-additized gasoline or 
detergent-additized post-refinery component.
    Automated detergent blending facility means any facility (including, 
but not limited to, a truck or individual storage tank) at which 
detergent is blended with gasoline or post-refinery component, by means 
of an injector system calibrated to automatically deliver a prescribed 
amount of detergent.
    Base gasoline means any gasoline that does not contain detergent.
    Carburetor deposits means the deposits formed in the carburetor 
during operation of a carburetted gasoline engine which can disrupt the 
ability of the carburetor to maintain the proper air/fuel ratio.
    Carrier of detergent means any distributor of detergent who 
transports or stores or causes the transportation or storage of 
detergent without taking title to or otherwise having any ownership of 
the detergent, and without altering either the quality or quantity of 
the detergent.
    Deposit control effectiveness means the ability of a detergent 
additive package to prevent the formation of deposits in gasoline 
engines.
    Deposit control efficiency means the degree to which a detergent 
additive package at a given concentration in gasoline is effective in 
limiting the formation of deposits. The addition of inactive ingredients 
to a detergent additive package, to the extent that this addition 
dilutes the concentration of the detergent-active components, reduces 
the deposit control efficiency of the package.
    Detergent additive package means any chemical compound or 
combination of chemical compounds, including carrier oils, that may be 
added to gasoline, or to post-refinery component blended with gasoline, 
in order to control deposit formation. Carrier oil means an oil that may 
be added to the package to mediate or otherwise enhance the detergent 
chemical's ability to control deposits. A detergent additive package may 
contain non-detergent-active components such as corrosion inhibitors, 
antioxidants, metal deactivators, and handling solvents.
    Detergent blender means any person who owns, leases, operates, 
controls or supervises the blending operation of a detergent blending 
facility. Pursuant to the definition in 40 CFR 79.2(d), a detergent 
blender is also considered a fuel manufacturer.
    Detergent blending facility means any facility (including, but not 
limited to, a truck or individual storage tank) at which detergent is 
blended with gasoline or post-refinery component.
    Detergent-active components means the components of a detergent 
additive package which act to prevent the formation of deposits, 
including, but not necessarily limited to, the actual detergent chemical 
and any carrier oil (if present) that acts to enhance the detergent's 
ability to control deposits.
    Detergent-additized gasoline (also called detergent gasoline) means 
any gasoline that contains base gasoline and detergent.
    Detergent-additized post-refinery component means any post-refinery 
component that contains detergent.
    Distributor of detergent means any person who transports or stores 
or causes the transportation or storage of detergent at any point 
between its manufacture and its introduction into gasoline.
    Fuel injector deposits (also known as port fuel injector deposits or 
PFID) means the deposits formed on fuel injector(s) during and after 
operation of a gasoline engine, as evaluated by the reduction in the 
gasoline flow rate through the fuel injector(s).
    Gasoline means any fuel for use in motor vehicles and motor vehicle 
engines, including both highway and off-highway vehicles and engines, 
and commonly or commercially known or sold as gasoline. The term 
``gasoline'' is inclusive of base gasoline, detergent gasoline, and base 
gasoline or detergent gasoline that has been commingled with post-
refinery component.

[[Page 618]]

    Hand blending detergent facility means any facility (including, but 
not limited to, a truck or individual storage tank) at which detergent 
is blended with gasoline or post-refinery component by the manual 
addition of detergent, or at which detergent is blended with these 
substances by any means that is not automated.
    Intake valve deposits (IVD) means the deposits formed on the intake 
valve(s) during operation of a gasoline engine, as evaluated by weight.
    Manufacturer of detergent means any person who owns, leases, 
operates, controls, or supervises a facility that manufactures 
detergent. Pursuant to the definition in 40 CFR 79.2(f), a manufacturer 
of detergent is also considered an additive manufacturer.
    Post-refinery component means any gasoline blending stock or any 
oxygenate which is blended with gasoline subsequent to the gasoline 
refining process.



Sec. 80.141  Interim detergent gasoline program.

    (a) Effective date of requirements; responsible parties. Beginning 
January 1, 1995, all gasoline sold or transferred to the ultimate 
consumer, or to the marketer who sells or transfers gasoline to the 
ultimate consumer, must contain detergent additive(s) meeting the 
requirements of this section. The applicability of these detergency 
requirements to specific types of gasoline is specified in paragraph (b) 
of this section. Pursuant to paragraphs (c) through (f) of this section, 
compliance with the requirements of this section is the responsibility 
of parties who directly or indirectly sell or dispense gasoline to the 
ultimate consumer as well as parties who manufacture, supply, or 
transfer detergent additives or detergent-additized post-refinery 
components.
    (b) Applicability of gasoline detergency requirements. Except as 
specifically exempted in Sec. 80.160, the detergency requirements of 
this subpart apply to all gasoline, including highway-use, off-road, 
reformulated, conventional, and oxygenated gasolines, as well as the 
gasoline component mixtures of petroleum and alcohol fuels, gasoline 
used as marine fuel, gasoline service accumulation fuel (as described in 
Sec. 86.113-94(a)(1) of this chapter), and the gasoline component of 
fuel mixtures of petroleum and methanol used for service accumulation in 
flexible fuel vehicles (as described in Sec. 86.113-94(d) of this 
chapter).
    (c) Detergent registration requirements. To be eligible for use by 
fuel manufacturers in complying with the gasoline detergency 
requirements of this subpart, a detergent additive package must be 
registered by its manufacturer under 40 CFR part 79 according to the 
specifications in paragraphs (c) (1) through (3) of this section. After 
evaluating the adequacy of registration data provided by the detergent 
manufacturer pursuant to these requirements, if EPA finds the data to be 
deficient, EPA may disqualify the detergent package for use in complying 
with the gasoline detergency requirements of this subpart, under the 
provisions of paragraph (g) of this section.
    (1) Compositional data. The compositional data supplied to EPA by 
the additive manufacturer for purpose of registering a detergent 
additive package under Sec. 79.21(a) of this chapter must include:
    (i) A complete listing of the components of the detergent additive 
package, using standard chemical nomenclature when possible or providing 
the chemical structure of any component for which the standard chemical 
name is not precise. Detergent-active components may not be reported as 
the product of other chemical reactants.
    (ii) The exact weight and/or volume percent (as applicable) of each 
component of the package, with variability in these amounts restricted 
according to the provisions of paragraph (c)(2) of this section.
    (iii) For each detergent-active component of the package, 
classification into one of the following designations:
    (A) Polyalkyl amine;
    (B) Polyether amine;
    (C) Polyalkylsuccinimide;
    (D) Polyalkylaminophenol;
    (E) Detergent-active carrier oil; and
    (F) Other detergent-active component.
    (2) Allowable variation in compositional data. A single detergent 
additive registration may contain no variation in

[[Page 619]]

the identity or concentration of any of the detergent-active components 
identified pursuant to paragraph (c)(1)(iii) of this section. The 
identity and/or concentration of other components of the detergent 
additive package may vary under a single registration, provided that the 
range of such variation is specified in the registration and that such 
variability does not change the minimum recommended concentration of the 
additive package reported in accordance with the requirements of 
paragraph (c)(3) of this section. Detergent additive packages which 
constitute a variation from these restrictions must be separately 
registered. EPA may disqualify an additive for use in satisfying the 
requirements of this subpart if EPA determines that the variability 
included within a given detergent additive registration affects the 
concentration of detergent-active components.
    (3) Minimum recommended concentration. (i) The lower boundary of the 
recommended range of concentration for the detergent additive package in 
gasoline, reported by the additive manufacturer pursuant to the 
registration requirements in Sec. 79.21(d) of this chapter, must equal 
or exceed the minimum concentration which the manufacturer has 
determined to be necessary for the control of deposits in the associated 
fuel type. This concentration must be reported in gallons of the 
detergent additive package per gallons of gasoline.
    (A) When registered for use in unleaded gasoline, the minimum 
recommended concentration must not be less than the concentration 
necessary for the control of PFID and IVD.
    (B) When registered for use in leaded gasoline, the minimum 
recommended concentration must not be less than the concentration 
necessary for the control of carburetor deposits.
    (ii) The minimum concentration reported in the detergent 
registration according to the provisions of paragraph (c)(3)(i) of this 
section must also be communicated in writing by the additive 
manufacturer to each fuel manufacturer who purchases the subject 
detergent for purpose of compliance with the gasoline detergency 
requirements of this subpart, and to any additive manufacturer who 
purchases the subject additive with the intent of reselling it to a fuel 
manufacturer for this purpose.
    (iii) Pursuant to the requirements of paragraph (e) of this section, 
EPA may require the additive manufacturer to submit data to support the 
deposit control effectiveness of the detergent package at the specified 
minimum effective concentration. EPA may disqualify an additive for use 
in satisfying the requirements of this subpart upon finding that the 
supporting data is inadequate. Manufacturers may be subject to the 
liabilities and enforcement actions in Secs. 80.156 and 80.159 if such a 
finding is made.
    (d) Detergent gasoline registration requirements. (1) Pursuant to 
the fuel registration requirements of Sec. 79.11 of this chapter, a 
detergent blender/fuel manufacturer must include adequate information in 
the gasoline's registration to identify which registered detergent 
additive(s) will be used in the gasoline. This information must at a 
minimum include the specific commercial identifying name and 
manufacturer of the detergent additive package(s), the range of 
concentration of each such additive package intended to be used in the 
base gasoline, and any additional information needed to clearly identify 
which registered detergent additive(s) are to be used. A fuel 
registration shall be deemed insufficient if the registered additive to 
be used cannot be clearly identified based on the information provided. 
To comply with the detergency requirements of this subpart, the lower 
boundary of the range of concentration of the detergent additive 
package, reported by the fuel manufacturer pursuant to the registration 
requirements of Sec. 79.11(c) of this chapter, must equal or exceed the 
minimum recommended concentration specified in the detergent additive's 
registration, unless otherwise approved by EPA under the provisions of 
paragraph (d)(2) of this section.
    (2) If a detergent blender believes that the minimum treat rate 
recommended by the manufacturer of a detergent additive exceeds the 
amount

[[Page 620]]

of detergent actually required for effective deposit control, then, upon 
informing EPA of these circumstances pursuant to paragraph (d)(2)(i) of 
this section, the detergent blender may use the detergent at a lower 
concentration than recommended by the detergent manufacturer. Under the 
provisions of paragraph (d)(2)(ii) of this section, EPA may subsequently 
require the detergent blender to provide test data substantiating the 
effectiveness of the detergent at the lower concentration. Pursuant to 
paragraph (d)(2)(iii) of this section, if EPA determines that the lower 
concentration does not provide a level of deposit control consistent 
with the requirements of this section, the detergent blender may be 
subject to the penalties described in Secs. 80.156 and 80.159 for any 
gasoline additized at the lower concentration.
    (i) The detergent blender must inform EPA in writing of an intent to 
use a detergent product at a lower concentration than the minimum 
recommended by the detergent manufacturer. This notification must 
clearly specify the name of the detergent product and its manufacturer, 
the concentration recommended by the detergent manufacturer, and the 
concentration which the detergent blender intends to use. The 
notification must also attest that data are available to substantiate 
the deposit control effectiveness of the detergent at the intended lower 
concentration. The notification should be sent by certified mail to the 
address specified in Sec. 80.160(a).
    (ii) At its discretion, EPA may request that the detergent blender 
submit the test data purported to substantiate the claimed effectiveness 
of the lower concentration of the detergent additive. In such instance, 
EPA shall also require the manufacturer of the subject detergent 
additive to submit test data substantiating the minimum recommended 
concentration specified in the detergent additive registration. In each 
case, the supporting data will be due to EPA within 30 days of receipt 
of EPA's request.
    (A) If the detergent blender fails to submit the required supporting 
data to EPA in the allotted time period, EPA will proceed on the 
assumption that data are not available to substantiate the effectiveness 
of the lower detergent concentration, and the detergent blender will be 
subject to any applicable liabilities and penalties in Secs. 80.156 and 
80.159 for any gasoline it has additized at the lower concentration.
    (B) If the detergent manufacturer fails to submit the required test 
data to EPA within the allotted time period, EPA will proceed on the 
assumption that data are not available to substantiate the minimum 
recommended concentration specified in the detergent registration, and 
the subject additive may be disqualified for use in complying with the 
requirements of this subpart, pursuant to the procedures in paragraph 
(g) of this section. The detergent manufacturer may also be subject to 
applicable liabilities and penalties in Secs. 80.156 and 80.159.
    (iii) If both parties submit the requested information, EPA will 
evaluate the quality and results of both sets of test data in relation 
to each other and to industry-consensus test practices and standards, in 
a manner consistent with the guidelines described in paragraph (e) of 
this section. EPA will inform both the detergent blender and the 
detergent manufacturer of the results of its analysis within 60 days of 
receipt of both sets of data. Either party may appeal EPA's decision, 
using procedures analogous to those specified in paragraphs (g)(3) 
through (g)(4) of this section.
    (e) Demonstration of deposit control efficiency. At its discretion, 
EPA may require a detergent additive registrant to provide test data to 
support the deposit control effectiveness of a detergent at the minimum 
concentration recommended, pursuant to paragraph (c)(3) of this section 
and Sec. 79.21(d) of this chapter. The required supporting data must be 
submitted to EPA within 30 days of receipt of EPA's request. EPA will 
notify the submitter, within 60 days after receiving the supporting 
data, whether the data is adequate to support the deposit control 
efficiency claimed. Subject to the procedures specified in paragraph (g) 
of this section, if the supporting data are not submitted or if EPA 
finds the data insufficient, the detergent may be disqualified for use 
by fuel manufacturers in complying with the requirements of

[[Page 621]]

this subpart. EPA will use the following guidelines in determining the 
adequacy of the supporting data:
    (1) CARB-based supporting test data. For detergent additives which 
are certified by the California Air Resources Board (CARB) for use in 
the State of California (pursuant to Title 13, section 2257 of the 
California Code of Regulations), the CARB certification data constitutes 
adequate support of the detergent's effectiveness under this section, 
with the exception that CARB detergent certification data specific to 
California Phase II reformulated gasoline (pursuant to Title 13, Chapter 
5, Article 1, Subarticle 2, California Code of Regulations, Standards 
for Gasoline Sold Beginning March 1, 1996) will not be considered 
adequate support for detergent effectiveness in gasoline sold outside of 
California. For CARB-based supporting data to be used to demonstrate 
detergent performance, the concentration of the detergent-active 
components reported in the subject CARB detergent certification must not 
exceed the minimum recommended concentration reported in the applicable 
detergent additive registration.
    (2) EPA will evaluate the adequacy of other supporting data 
according to the following guidelines:
    (i) Test fuel guidelines.
    (A) The gasoline used in the supporting tests must contain the 
detergent-active components of the subject detergent additive package in 
an amount which corresponds to the minimum recommended concentrations 
recorded in the respective detergent registration, or less than this 
amount.
    (B) The test fuels must not contain any detergent-active components 
other than those recorded in the subject detergent registration.
    (C) The test fuels used must be reasonably typical of in-use fuels 
in their tendency to form deposits. Test fuel taken directly from 
commercial refinery production stock is acceptable. Specially refined 
low-deposit-forming fuels such as indolene are not acceptable. Other 
specially blended test fuels will be evaluated by EPA for acceptability 
based on the extent to which such fuels adequately represent the 
deposit-forming tendency of typical (average) in-use fuels, as reflected 
in the levels of the following fuel parameters: sulfur content, aromatic 
content, olefin content, T-90, and oxygenate content.
    (D) The composition of the blended test fuel(s) used in carburetor 
deposit control testing, conducted to support the claimed effectiveness 
of detergents used in leaded gasoline, should be reasonably typical of 
in-use gasoline in its tendency to form carburetor deposits (or more 
severe than typical in-use fuels) as defined by the olefin and sulfur 
content. Test data using leaded fuels is preferred for this purpose, but 
data collected using unleaded fuels may also be acceptable provided that 
some correlation with additive performance in leaded fuels is available.
    (ii) Test procedure guidelines.
    (A) To be acceptable, test data submitted to support the deposit 
control effectiveness of a detergent additive must derive from testing 
conducted in conformity with good engineering practices.
    (B) For demonstration of fuel injector and intake valve deposit 
control performance, vehicle-based tests using standard industry 
procedures and standards is preferred. Engine-based tests may also be 
acceptable, assuming a reasonable correlation with vehicle-based tests 
and standards can be demonstrated. Bench test data may be acceptable to 
demonstrate fuel injector deposit control performance, assuming the 
results can be correlated with vehicle- or engine-based tests and 
standards. Bench testing will not be considered acceptable for 
demonstration of IVD control performance. Examples of acceptable test 
procedures are contained in the following references:
    (1) Intake Valve Deposit Test Procedures:
    (i) ``Intake Valve Deposits--Fuel Detergency Requirements 
Revisited'', Bill Bitting et al., Society of Automotive Engineers, SAE 
Technical Paper No. 872117, 1987.\1\
---------------------------------------------------------------------------

    \1\ Society of Automotive Engineers (SAE), 400 Commonwealth Drive, 
Warrendale, PA 15096-0001.
---------------------------------------------------------------------------

    (ii) ``BMW--10,000 Miles Intake Valve Test Procedure'', March 1, 
1991, Section

[[Page 622]]

2257, Title 13, California Code of Regulations.
    (iii) ``Standard Test Method for Vehicle Evaluation of Unleaded 
Automotive Spark-Ignition Engine Fuel for Intake Valve Deposit 
Formation'', American Society for Testing and Materials, ASTM Test 
Method D-5500.\2\
---------------------------------------------------------------------------

    \2\ American Society for Testing and Materials (ASTM), 1916 Race 
Street, Philadelphia, PA, 19103-1187.
---------------------------------------------------------------------------

    (iv) ``Effect on Intake Valve Deposits of Ethanol and Additives 
Common to the Available Ethanol Supply'', Clifford Shilbolm et al., SAE 
Technical Paper Series No. 902109, 1990.
    (2) Fuel Injector Deposit Test Procedures:
    (i) ``Test Method for Evaluating Port Fuel Injector (PFI) Deposits 
in Vehicle Engines'', March 1, 1991, Section 2257, Title 13, California 
Code of Regulations.
    (ii) ``A Vehicle Test Technique for Studying Port Fuel Injector 
Deposits--A Coordinating Research Council Program'', Robert Tupa et al., 
SAE Technical paper No. 890213, 1989.
    (iii) ``The Effects of Fuel Composition and Additives on Multiport 
Fuel Injector Deposits'', Jack Benson et al., SAE Technical Paper Series 
No. 861533, 1986.
    (iv) ``Injector Deposits--The Tip of Intake System Deposit 
Problems'', Brian Taneguchi, et al., SAE Technical Paper Series No. 
861534, 1986.
    (C) For demonstration of carburetor deposit control performance, any 
generally accepted vehicle, engine, or bench test procedure for 
carburetor deposit control will be considered adequate. Port and 
throttle body fuel injector deposit control test data will also be 
considered to be adequate demonstration of an additive's ability to 
control carburetor deposits. Examples of acceptable test procedures for 
demonstration of carburetor deposit control, in addition to the fuel 
injector test procedures listed above in paragraph (e)(2)(ii)(B)(2) of 
this section, are contained in the following references:
    (1) ``Fuel Injector, Intake Valve, and Carburetor Detergency 
Performance of Gasoline Additives'', C.H. Jewitt et al., SAE Technical 
Paper No. 872114, 1987.
    (2) ``Carburetor Cleanliness Test Procedure, State-of-the-Art 
Summary, Report: 1973-1981'', Coordinating Research Council, CRC Report 
No. 529.\3\
---------------------------------------------------------------------------

    \3\ Coordinating Research Council Inc. (CRC), 219 perimeter Center 
Parking, Atlanta, Georgia, 30346.
---------------------------------------------------------------------------

    (f) Detergent identification test procedure. (1) At its discretion, 
EPA may require the additive registrant to submit an analytical 
procedure capable of identifying the detergent additive in its pure 
state. The test procedure will be due to EPA within 30 days of the 
registrant's receipt of the request. Subject to the provisions in 
paragraph (g) of this section, if the registrant fails to submit an 
analytical procedure, or if EPA judges a submitted procedure to be 
inadequate, EPA may deny or withdraw the detergent's eligibility to be 
used to satisfy the detergency requirements in this section.
    (2) The analytical procedure submitted by the registrant must be 
able to both qualitatively and quantitatively identify each component of 
the detergent additive package. To be acceptable, the procedure must 
provide results that conform to reasonable and customary standards of 
repeatability and reproducibility, and reasonable and customary limits 
of detection and accuracy, for the type of test in question.
    (3) A fourier transform infrared spectroscopy (FTIR)-based 
procedure, including an actual infrared spectrum of the detergent 
additive package and each component part of the detergent package 
obtained from this test method, is preferred.
    (g) Disqualification of a detergent additive package. (1) When EPA 
makes a preliminary determination that a detergent additive registrant 
has failed to comply with the requirements of paragraph (c), 
(d)(2)(ii)(B), (e), or (f) of this section, either by failing to submit 
required information for a subject detergent additive or by submitting 
information which EPA deems inadequate, EPA shall notify the additive 
registrant by certified mail, return receipt requested, setting forth 
the basis for that determination and informing the registrant that the 
detergent may lose its eligibility to be used to comply with the 
detergency requirements of this section.

[[Page 623]]

    (2) If EPA determines that the detergent registration was created by 
fraud or other misconduct, such as a negligent disregard for the 
truthfulness or accuracy of the required information or of the 
application, the detergent registration will be considered void ab 
initio and the revocation of qualification will be retroactive to 
January 1, 1995 or the date on which the additive product was first 
registered, whichever is later.
    (3) The registrant will be afforded 60 days from the date of receipt 
of the notice of intent of detergent disqualification to submit written 
comments concerning the notice, and to demonstrate or achieve compliance 
with the specific data requirements which provide the basis for the 
proposed disqualification. If the registrant does not respond in writing 
within 60 days from the date of receipt of the notice of intent of 
disqualification, the detergent disqualification shall become final by 
operation of law and the Administrator shall notify the registrant of 
such disqualification. If the registrant responds in writing within 60 
days from the date of receipt of the notice of intent to disqualify, the 
Administrator shall review and consider all comments submitted by the 
registrant before taking final action concerning the proposed 
disqualification. The registrants' communications should be sent to the 
following address: Director, Field Operations and Support Division, Mail 
Code: 6406J, U.S. Environmental Protection Agency, 401 M Street, SW., 
Washington, DC 20460.
    (4) As part of a written response to a notice of intent to 
disqualify, a registrant may request an informal hearing concerning the 
notice. Any such request shall state with specificity the information 
the registrant wishes to present at such a hearing. If an informal 
hearing is requested, EPA shall schedule such a hearing within 90 days 
from the date of receipt of the request. If an informal hearing is held, 
the subject matter of the hearing shall be confined solely to whether or 
not the registrant has complied with the specific data requirements 
which provide the basis for the proposed disqualification. If an 
informal hearing is held, the designated presiding officer may be any 
EPA employee, the hearing procedures shall be informal, and the hearing 
shall not be subject to or governed by 40 CFR part 22 or by 5 U.S.C. 
554, 556, or 557. A verbatim transcript of each informal hearing shall 
be kept and the Administrator shall consider all relevant evidence and 
arguments presented at the hearing in making a final decision concerning 
a proposed cancellation.
    (5) If a registrant who has received a notice of intent to 
disqualify submits a timely written response, and the Administrator 
decides after reviewing the response and the transcript of any informal 
hearing to disqualify the detergent for use in complying with the 
requirements of this subpart, the Administrator shall issue a final 
disqualification order, forward a copy of the disqualification order to 
the registrant by certified mail, and promptly publish the 
disqualification order in the Federal Register. Any disqualification 
order issued after receipt of a timely written response by the 
registrant shall become legally effective five days after it is 
published in the Federal Register.
    (6) Upon making a final decision to disqualify a detergent additive 
package pursuant to this paragraph (g), EPA shall inform all fuel 
manufacturers and secondary additive manufacturers whose product 
registrations report the potential use of the disqualified detergent 
that such detergent is no longer eligible for compliance with the 
requirements of this subpart. Such fuel manufacturers and secondary 
additive manufacturers shall have 45 days in which to stop using the 
ineligible detergent additive package and substitute an eligible 
detergent additive. When applicable, EPA shall also notify such parties 
that the detergent registration had been created by fraud or other 
misconduct, pursuant to paragraph (g)(2) of this section.
Sec. 80.142--80.154  [Reserved]



Sec. 80.155  Controls and prohibitions.

    (a)(1) No person shall sell, offer for sale, dispense, supply, offer 
for supply, transport, or cause the transportation of gasoline to the 
ultimate consumer for use in motor vehicles or in any off-

[[Page 624]]

road engine use (except as provided in Sec. 80.160), or to a gasoline 
retailer or wholesale purchaser-consumer, and no person shall additize 
gasoline, unless such gasoline has been additized in conformity with the 
requirements of Sec. 80.141.
    (2) Gasoline has been additized in conformity with the requirements 
of Sec. 80.141 when the detergent component satisfies the requirements 
of Sec. 80.141 and when:
    (i) The gasoline has been additized in conformity with the detergent 
composition and purpose-in-use specifications of an applicable detergent 
registered under 40 CFR part 79, in accordance with at least the minimum 
concentration specifications of a detergent registered under 40 CFR part 
79 or as otherwise provided under Sec. 80.141(d)(2); or
    (ii) The gasoline is composed of two or more commingled gasolines 
and each component gasoline has been additized in conformity with the 
detergent composition and purpose-in-use specifications of a detergent 
registered under 40 CFR part 79, in accordance with at least the minimum 
concentration specifications of a detergent registered under 40 CFR part 
79 or as otherwise provided under Sec. 80.141(d)(2); or
    (iii) The gasoline is composed of a gasoline commingled with a post-
refinery component, and both of these components have been additized in 
conformity with the detergent composition and use specifications of a 
detergent registered under 40 CFR part 79, in accordance with at least 
the minimum concentration specifications of a detergent registered under 
40 CFR part 79 or as otherwise provided under Sec. 80.141(d)(2).
    (b) No person shall blend detergent into gasoline or post-refinery 
component unless such person complies with the volumetric additive 
reconciliation requirements of Sec. 80.157.
    (c) No person shall sell, offer for sale, dispense, supply, offer 
for supply, store, transport, or cause the transportation of any 
gasoline, detergent, or detergent-additized post-refinery component 
unless the product transfer document for the gasoline, detergent or 
detergent-additized post-refinery component complies with the 
requirements of Sec. 80.158.
    (d) No person shall refine, import, manufacture, sell, offer for 
sale, dispense, supply, offer for supply, store, transport, or cause the 
transportation of any detergent that is to be used as a component of 
detergent-additized gasoline or detergent-additized post-refinery 
component unless the detergent conforms with the composition 
specifications of a detergent registered under 40 CFR part 79, and the 
detergent otherwise complies with the requirements of Sec. 80.141.
    (e)(1) No person shall sell, offer for sale, dispense, supply, offer 
for supply, transport, or cause the transportation of detergent-
additized post-refinery component unless the post-refinery component has 
been additized in conformity with the interim detergent program 
requirements of Sec. 80.141.
    (2) Post-refinery component has been additized in conformity with 
the interim detergent program requirements of Sec. 80.141 when the 
detergent component satisfies the requirements of Sec. 80.141 and:
    (i) The post-refinery component has been additized in accordance 
with the detergent composition and use specifications of a detergent 
registered under 40 CFR part 79, and in accordance with at least the 
minimum concentration specifications of a detergent registered under 40 
CFR part 79 or as otherwise provided under Sec. 80.141(d)(2); or
    (ii) The post-refinery component is composed of two or more 
commingled post-refinery components, and each component has been 
additized in accordance with the detergent composition and use 
specifications of a detergent registered under 49 CFR part 79, and in 
accordance with at least the minimum concentration specifications of a 
detergent registered under 40 CFR part 79 or as otherwise provided under 
Sec. 80.141(d)(2).



Sec. 80.156  Liability for violations of the interim detergent program controls and prohibitions.

    (a) Persons liable--(1) Gasoline non-conformity. Where gasoline 
contained in any storage tank at any facility owned,

[[Page 625]]

leased, operated, controlled or supervised by any gasoline refiner, 
importer, carrier, distributor, reseller, retailer, wholesale purchaser-
consumer, oxygenate blender, or detergent blender, is found in violation 
of any of the prohibitions specified in Sec. 80.155(a), the following 
persons shall be deemed in violation:
    (i) Each gasoline refiner, importer, carrier, distributor, reseller, 
retailer, wholesale purchaser-consumer, oxygenate blender, or detergent 
blender, who owns, leases, operates, controls or supervises the facility 
(including, but not limited to, a truck or individual storage tank) 
where the violation is found;
    (ii) Each gasoline refiner, importer, distributor, reseller, 
retailer, wholesale purchaser-consumer, oxygenate blender, detergent 
manufacturer, distributor, or blender, who refined, imported, 
manufactured, sold, offered for sale, dispensed, supplied, offered for 
supply, stored, transported, or caused the transportation of the 
detergent-additized gasoline, the base gasoline component, the detergent 
component, or the detergent-additized post-refinery component, of the 
gasoline that is in violation; and
    (iii) Each gasoline carrier who dispensed, supplied, stored, or 
transported any gasoline in the storage tank containing gasoline found 
to be in violation, and each detergent carrier who dispensed, supplied, 
stored, or transported the detergent component of any post-refinery 
component or gasoline in the storage tank containing gasoline found to 
be in violation, provided that the EPA demonstrates, by reasonably 
specific showings by direct or circumstantial evidence, that the 
gasoline or detergent carrier caused the violation.
    (2) Post-refinery component non-conformity. Where detergent-
additized post-refinery component contained in any storage tank at any 
facility owned, leased, operated, controlled or supervised by any 
gasoline refiner, importer, carrier, distributor, reseller, retailer, 
wholesale purchaser-consumer, oxygenate blender, detergent manufacturer, 
carrier, distributor, or blender, is found in violation of the 
prohibitions specified in Sec. 80.155(e), the following persons shall be 
violation:
    (i) Each gasoline refiner, importer, carrier, distributor, reseller, 
retailer, wholesale-purchaser consumer, oxygenate blender, detergent 
manufacturer, carrier, distributor, or blender, who owns, leases, 
operates, controls or supervises the facility (including, but not 
limited to, a truck or individual storage tank) where the violation is 
found;
    (ii) Each gasoline refiner, importer, distributor, reseller, 
retailer, wholesale-purchaser consumer, oxygenate blender, detergent 
manufacturer, distributor, or blender, who sold, offered for sale, 
dispensed, supplied, offered for supply, stored, transported, or caused 
the transportation of the detergent-additized post-refinery component, 
or the detergent component of the post-refinery component, in violation; 
and
    (iii) Each carrier who dispensed, supplied, stored, or transported 
any detergent-additized post-refinery component in the storage tank 
containing post-refinery component in violation, and each detergent 
carrier who dispensed, supplied, stored, or transported the detergent 
component of any detergent-additized post-refinery component which is in 
the storage tank containing detergent-additized post-refinery component 
found to be in violation, provided that the EPA demonstrates by 
reasonably specific showings by direct or circumstantial evidence, that 
the gasoline or detergent carrier caused the violation.
    (3) Detergent non-conformity. Where the detergent (prior to 
additization) contained in any storage tank or container found at any 
facility owned, leased, operated, controlled or supervised by any 
gasoline refiner, importer, carrier, distributor, reseller, retailer, 
wholesale-purchaser consumer, oxygenate blender, detergent manufacturer, 
carrier, distributor, or blender, is found in violation of the 
prohibitions specified in Sec. 80.155(d), the following persons shall be 
in violation:
    (i) Each gasoline refiner, importer, carrier, distributor, reseller, 
retailer, wholesale-purchaser consumer, oxygenate blender, detergent 
manufacturer, carrier, distributor, or blender, who owns, leases, 
operates, controls or supervises the facility (including, but not 
limited to, a truck or individual storage tank) where the violation is 
found;

[[Page 626]]

    (ii) Each gasoline refiner, importer, distributor, reseller, 
retailer, wholesale-purchaser consumer, oxygenate blender, detergent 
manufacturer, distributor, or blender, who sold, offered for sale, 
dispensed, supplied, offered for supply, stored, transported, or caused 
the transportation of the detergent that is in violation; and
    (iii) Each gasoline or detergent carrier who dispensed, supplied, 
stored, or transported any detergent which is in the storage tank or 
container containing detergent found to be in violation, providing that 
EPA demonstrates, by reasonably specific showings by direct or 
circumstantial evidence, that the gasoline or detergent carrier caused 
the violation.
    (4) Volumetric additive reconciliation. Where a violation of the 
volumetric additive reconciliation requirements established by 
Sec. 80.155(b) has occurred, each detergent blender who owns, leases, 
operates, controls or supervises the facility (including, but not 
limited to, a truck or individual storage tank) where the violation has 
occurred, shall be in violation.
    (5) Product transfer document. Where a violation of Sec. 80.155(c) 
is found at a facility owned, leased, operated, controlled, or 
supervised by any gasoline refiner, importer, carrier, distributor, 
reseller, retailer, wholesale-purchaser consumer, oxygenate blender, 
detergent manufacturer, carrier, distributor, or blender, the following 
persons shall be in violation: each gasoline refiner, importer, carrier, 
distributor, reseller, retailer, wholesale-purchaser consumer, oxygenate 
blender, detergent manufacturer, carrier, distributor, or blender, who 
owns, leases, operates, control or supervises the facility (including, 
but not limited to, a truck or individual storage tank) where the 
violation is found.
    (b) Branded refiner vicarious liability. Where any violation of the 
prohibitions specified in Sec. 80.155 has occurred, with the exception 
of violations of Sec. 80.155(c), a refiner will also be deemed liable 
for violations occurring at a facility operating under such refiner's 
corporate, trade, or brand name or that of any of its marketing 
subsidiaries. For purposes of this section, the word facility includes, 
but is not limited to, a truck or individual storage tank.
    (c) Defenses. (1) In any case in which a gasoline refiner, importer, 
distributor, carrier, reseller, retailer, wholesale-purchaser consumer, 
oxygenate blender, detergent distributor, carrier, or blender, is in 
violation of any of the prohibitions of Sec. 80.155, the regulated party 
shall be deemed not in violation if it can demonstrate:
    (i) That the violation was not caused by the regulated party or its 
employee or agent;
    (ii) That product transfer documents account for the gasoline, 
detergent, or detergent-additized post-refinery component in violation 
and indicate that the gasoline, detergent, or detergent-additized post-
refinery component satisfied relevant requirements when it left their 
control; and
    (iii) That the party has fulfilled the requirements of paragraphs 
(c) (2) or (3) of this section, as applicable.
    (2) Branded refiner. (i) Where a branded refiner, pursuant to 
paragraph (b) of this section, is in violation of any of the 
prohibitions of Sec. 80.155 as a result of violations occurring at a 
facility (including, but not limited to, a truck or individual storage 
tank) which is operating under the corporate, trade or brand name of a 
refiner or that of any of its marketing subsidiaries, the refiner shall 
be deemed not in violation if it can demonstrate, in addition to the 
defense requirements stated in paragraph (c)(1) of this section, that 
the violation was caused by:
    (A) An act in violation of law (other than these regulations), or an 
act of sabotage or vandalism, whether or not such acts are violations of 
law in the jurisdiction where the violation of the prohibitions of 
Sec. 80.155 occurred; or
    (B) The action of any gasoline refiner, importer, reseller, 
distributor, oxygenate blender, detergent manufacturer, distributor, 
blender, or retailer or wholesale purchaser-consumer supplied by any of 
these persons, in violation of a contractual undertaking imposed by the 
refiner designed to prevent such action, and despite the implementation 
of an oversight program, including, but not limited to, periodic review 
of product transfer documents

[[Page 627]]

by the refiner to ensure compliance with such contractual obligation; or
    (C) The action of any gasoline or detergent carrier, or other 
gasoline or detergent distributor not subject to a contract with the 
refiner but engaged by the refiner for transportation of gasoline, post-
refinery component, or detergent, to a gasoline or detergent 
distributor, oxygenate blender, detergent blender, gasoline retailer or 
wholesale purchaser consumer, despite specification or inspection of 
procedures or equipment by the refiner which are reasonably calculated 
to prevent such action.
    (ii) In this paragraph (c)(2), to show that the violation ``was 
caused'' by any of the specified actions, the party must demonstrate by 
reasonably specific showings, by direct or circumstantial evidence, that 
the violation was caused or must have been caused by another.
    (3) Detergent blender. In any case in which a detergent blender is 
liable for violating any of the prohibitions of Sec. 80.155, the 
detergent blender shall not be deemed in violation if it can 
demonstrate, in addition to the defense requirements stated in paragraph 
(c)(1) of this section, the following:
    (i) That it obtained or supplied, as appropriate, prior to the 
detergent blending, written instructions from the detergent manufacturer 
or other party with knowledge of such instructions, specifying the 
detergent's minimum recommended concentration as found in the 40 CFR 
part 79 registration and, where appropriate, the detergent's use 
limitations in regard to leaded product; and
    (ii) That it has implemented a quality assurance program that 
includes, but is not limited to, a periodic review of supporting product 
transfer and volume measurement documents to confirm the correctness of 
the product transfer and volumetric additive reconciliation documents 
created for the additized product.
    (4) Detergent manufacturer. In any case in which a detergent 
manufacturer would be liable for violating any of the prohibitions of 
Sec. 80.155 pursuant to paragraph (a) of this section, the detergent 
manufacturer shall not be in violation if it can demonstrate the 
following:
    (i) Product transfer documents which account for the detergent 
component of the product in violation and which indicate that such 
detergent satisfied relevant requirements when it left the detergent 
manufacturer's control;
    (ii) Test results performed in accordance with the detergent testing 
analysis submitted, or available for submission, by the manufacturer to 
EPA as part of the interim detergent program requirements. The test 
results must accurately establish that the detergent component of the 
product determined to be in violation was in conformity with the 
composition and concentration specifications of the detergent's 40 CFR 
part 79 registration when the detergent left the manufacturer's control; 
and
    (iii) Written blending instructions that were supplied by the 
detergent manufacturer to its customer who purchased or obtained from 
the manufacturer the detergent component of the product determined to be 
in violation. The written blending instructions, which must have been 
supplied by the manufacturer to the customer prior to the customer's use 
or sale of the detergent, must accurately identify the minimum 
recommended concentration of the detergent necessary to control 
deposits, as specified in the detergent's 40 CFR part 79 registration, 
and must also accurately identify if the detergent, at that 
concentration, is only registered as effective for use in leaded 
gasoline.
    (d) Detergent manufacturer causation liability. In any case in which 
a detergent manufacturer is liable for a violation of Sec. 80.155 
pursuant to paragraph (a) of this section, and the manufacturer 
establishes affirmative defense to such liability pursuant to paragraph 
(c) of this section, the detergent manufacturer will be liable for the 
violation of Sec. 80.155 pursuant to this paragraph (d) of this section, 
provided that EPA can demonstrate, by reasonably specific showings by 
direct or circumstantial evidence, that the detergent manufacturer 
caused the violation.

[[Page 628]]



Sec. 80.157  Volumetric additive reconciliation (``VAR''), equipment calibration, and recordkeeping requirements.

    This section contains requirements for automated detergent blending 
facilities and hand-blending detergent facilities. All gasolines and all 
post-refinery components (PRC) intended for use in gasoline must be 
additized, unless otherwise noted in supporting VAR records, and must be 
accounted for in VAR records. The VAR reconciliation standard is 
attained under this section when the actual concentration of detergent 
used per VAR record equals or exceeds the lowest additive concentration 
(LAC) specified for that detergent in its 40 CFR part 79 registration, 
except as may be modified pursuant to Sec. 80.141(d)(2). Each VAR record 
must identify the brands and grades of gasoline, and the types of PRC, 
being measured on that record. There must be a separate VAR record for 
leaded gasoline being additized with a detergent registered as effective 
for use with leaded gasoline only, or used at a concentration that is 
registered as effective for leaded gasoline only. Detergent being so 
used must be accurately and separately measured, either through the use 
of a separate storage tank for it, or a separate meter, or the use of 
some other measurement system that is able to accurately distinguish its 
use from that of other detergents. Measurements of detergent and 
gasoline must be precise to at least the nearest gallon.
    (a) For an automated detergent blending facility, for each VAR 
period, for each detergent storage tank and each detergent in that 
storage tank, the following must be recorded:
    (1) The manufacturer and commercial identifying name of the 
detergent additive package being reconciled, and the LAC specified for 
that detergent in its 40 CFR part 79 registration for use with the 
applicable type of gasoline (i.e., unleaded or leaded). The LAC must be 
expressed in terms of gallons of detergent per gallons of gasoline. The 
record must indicate if the specified LAC is only effective for use with 
leaded gasoline.
    (2) The total volume of detergent blended into gasoline and PRC, in 
accordance with either paragraph (a)(2)(i) or paragraph (a)(2)(ii) of 
this section, as applicable.
    (i) For a facility which uses in-line meters to measure detergent 
usage, the total volume of detergent measured, together with supporting 
data which includes one of the following: the beginning and ending meter 
readings for each meter being measured, the metered batch volume 
measurements for each meter being measured, or other comparable metered 
measurements. The supporting data may be supplied in the form of 
computer printouts or other comparable documentation.
    (ii)(A) For a facility which uses a gauge to measure the inventory 
of the detergent storage tank, the total volume of detergent shall be 
calculated from the following equation:

Detergent Volume = (A)-(B)+(C)-(D)

where:
A = initial detergent inventory of the tank
B = final detergent inventory of the tank
C = sum of any additions to detergent inventory
D = sum of any withdrawals from detergent inventory for purposes other 
than the additization of gasoline or PRC.

    (B) The value of each of the variables in the equation in paragraph 
(a)(2)(ii)(A) of this section must be separately recorded. In addition, 
a list of each detergent addition included in variable C and a list of 
each detergent withdrawal included in variable D must be provided.
    (3) The total volume of gasoline plus PRC to which detergent has 
been added, together with supporting data which includes one of the 
following: the beginning and ending meter measurements for each meter 
being measured, the metered batch volume measurements for each meter 
being measured, or other comparable metered measurements. The supporting 
data may be supplied in the form of computer printouts or other 
comparable data.
    (4) The actual detergent concentration, calculated as the total 
volume of detergent added (pursuant to paragraph (a)(2) of this 
section), divided by the total volume of gasoline plus PRC

[[Page 629]]

(pursuant to paragraph (a)(3) of this section).
    (5) A list of each concentration rate initially set for the 
detergent that is the subject of the VAR record, together with the date 
and description of each adjustment to any initially set concentration. 
The concentration adjustment information may be supplied in the form of 
computer printouts or other comparable documentation. No concentration 
setting is permitted below the applicable LAC specified in the 
detergent's 40 CFR part 79 registration, except as may be modified 
pursuant to Sec. 80.141(d)(2).
    (6) The dates of the VAR period, which shall be no greater than a 
calendar month, and which shall in no event terminate beyond the end of 
the calendar month in which that VAR period began. Any adjustment to any 
detergent concentration rate more than 10 percent over the concentration 
rate initially set in the VAR period shall terminate that VAR period and 
initiate a new VAR period.
    (b) For a hand-blending detergent facility where any non-automated 
method is used to blend detergent, for each detergent and for each batch 
of gasoline and each batch of PRC to which the detergent is being added, 
the following shall be recorded:
    (1) The manufacturer and commercial identifying name of the 
detergent additive package being reconciled, and the LAC specified for 
that detergent in its 40 CFR part 79 registration for use with the 
applicable type of gasoline (i.e., unleaded or leaded). The LAC must be 
expressed in terms of gallons of detergent per gallons of gasoline. The 
record must indicate if the specified LAC is only effective for use with 
leaded gasoline.
    (2) The date of the additization that is the subject of the VAR 
record.
    (3) The volume of added detergent.
    (4) The volume of the batch of gasoline and/or PRC to which the 
detergent has been added.
    (5) The brand, grade, and leaded/unleaded status of gasoline, and/or 
the type of PRC.
    (6) The actual detergent concentration, calculated as the volume of 
added detergent (pursuant to paragraph (b)(3) of this section), divided 
by the volume of gasoline and/or PRC (pursuant to paragraph (b)(4) of 
this section).
    (c) Every VAR formula record created pursuant to paragraphs (a) and 
(b) of this section shall contain the following:
    (1) The signature of the creator of the VAR record;
    (2) The date of the creation of the VAR record; and
    (3) A certification of correctness by the creator of the VAR record.
    (d) Automated detergent blenders must calibrate their detergent 
equipment each calendar quarter, in January, April, July, and October 
and each time the detergent package is changed.
    (e) The following VAR supporting documentation must also be created 
and maintained; all volume measurements must be to at least the nearest 
gallon in accuracy:
    (1) For all automated detergent blending facilities, documentation 
reflecting performance of the calibrations required by paragraph (d) of 
this section, and any associated adjustments of the automated detergent 
equipment;
    (2) For all automated detergent blending facilities, a record 
specifying, for each VAR period, the volume in gallons of each transfer 
from the facility of unadditized base gasoline, identifying its date of 
transfer and the name of the recipient;
    (3) For all hand blending facilities which are terminals, a monthly 
record specifying the volume in gallons of each transfer from the 
facility of unadditized base gasoline, identifying its date of transfer 
and the name of the recipient; and
    (4) For all detergent blending facilities, product transfer 
documents for all gasoline, detergent and detergent-additized post-
refinery component transferred into or out of the facility; in addition, 
bills of lading, transfer, or sale for all unadditized post-refinery 
component transferred into the facility.
    (f) All detergent blenders shall retain the documents required to be 
created by this section for a period of five years from the date the VAR 
calculation records and VAR supporting documentation are created 
pursuant to this section, and shall deliver them to the

[[Page 630]]

EPA Administrator, or the Administrator's authorized representative, 
upon the Administrator's or the Administrator's authorized 
representative's request.



Sec. 80.158  Product transfer documents.

    (a) Contents. For each occasion when any gasoline refiner, importer, 
reseller, distributor, carrier, retailer, wholesale purchaser-consumer, 
oxygenate blender, detergent manufacturer, distributor, carrier, or 
blender, transfers custody or title to any gasoline, detergent, or 
detergent-additized post-refinery component other than when detergent-
additized gasoline is sold or dispensed at a retail outlet or wholesale 
purchaser-consumer facility to the ultimate consumer for use in motor 
vehicles, the transferor shall provide to the transferee, and the 
transferee shall acquire from the transferor, documents which accurately 
include the following information:
    (1) The name and address of the transferee;
    (2) The name and address of the transferor;
    (3) The date of the transfer;
    (4) The volume of product transferred;
    (5)(i) The identity of the product being transferred (i.e., its 
identity as base gasoline, detergent, detergent-additized gasoline, or a 
specifically named detergent-additized oxygenate or detergent-additized 
gasoline blending stock that comprises a detergent-additized post-
refinery component);
    (ii) If the product being transferred consists of two or more 
different types of product subject to this regulation, i.e., base 
gasoline, detergent-additized gasoline; or specified detergent-additized 
post-refinery component, then the product transfer document for the 
commingled product must identify each such type of component contained 
in the commingled product;
    (6) If the product being transferred is base gasoline, the following 
must be stated on the product transfer document: ``Base gasoline--Not 
for sale to the ultimate consumer'';
    (7) The name of the detergent as specified in its 40 CFR part 79 
registration must be used to identify the detergent on its product 
transfer document;
    (8) If the product being transferred is a leaded gasoline as defined 
in Sec. 80.2(f), then the product transfer document must identify the 
product as leaded base gasoline or leaded detergent-additized gasoline, 
as applicable;
    (9) If the product being transferred is detergent that is only 
authorized for the control of carburetor deposits, then the following 
must be stated on the detergent's transfer document: ``For use with 
leaded gasoline only'';
    (10) If the product being transferred is detergent-additized 
gasoline that has been over-additized in anticipation of the later (or 
earlier) addition of post-refinery component, a statement that the 
product has been over-additized to account for a specified volume in 
gallons of additional, specified post-refinery component.
    (b) Gasoline cannot be additized with a detergent authorized only 
for the control of carburetor deposits and whose product transfer 
document states ``For use with leaded gasoline only'', and gasoline 
cannot be additized at the lower concentration specified for a detergent 
authorized at a lower concentration for the control of carburetor 
deposits only, unless the product transfer document for the gasoline to 
be additized identifies it as leaded gasoline.
    (c) Recordkeeping period. Any person creating, providing or 
acquiring product transfer documentation for gasoline, detergent, or 
detergent-additized post-refinery component shall retain the documents 
required by this section for a period of five years from the date the 
product transfer documentation was created, received or transferred, and 
shall deliver such documents to EPA upon request.



Sec. 80.159  Penalties.

    (a) General. Any person who violates any prohibition or affirmative 
requirement of Sec. 80.155 shall be liable to the United States for a 
civil penalty of not more than the sum of $25,000 for every day of such 
violation and the amount of economic benefit or savings resulting from 
the violation.
    (b) Gasoline non-conformity. Any violation of Sec. 80.155(a) shall 
constitute a separate day of violation for each and

[[Page 631]]

every day the gasoline in violation remains at any place in the gasoline 
distribution system, beginning on the day that the gasoline is in 
violation of the respective prohibition and ending on the last day that 
such gasoline is offered for sale or is dispensed to any ultimate 
consumer.
    (c) Detergent non-conformity. Any violation of Sec. 80.155(d) shall 
constitute a separate day of violation for each and every day the 
detergent in violation remains at any place in the gasoline or detergent 
distribution system, beginning on the day that the detergent is in 
violation of the prohibition and ending on the last day that detergent-
additized gasoline, containing the subject detergent as a component 
thereof, is offered for sale or is dispensed to any ultimate consumer.
    (d) Post-refinery component non-conformity. Any violation of 
Sec. 80.155(e) shall constitute a separate day of violation for each and 
every day the post-refinery component in violation remains at any place 
in the post-refinery component or gasoline distribution system, 
beginning on the day that the post-refinery component is in violation of 
the respective prohibition and ending on the last day that detergent-
additized gasoline containing the post-refinery component is offered for 
sale or is dispensed to any ultimate consumer.
    (e) Product transfer document non-conformity. Any violation of 
Sec. 80.155(c) shall constitute a separate day of violation for every 
day the product transfer document is not fully in compliance. This is to 
begin on the day that the product transfer document is created or should 
have been created and to end at the later of the following dates: Either 
the day that the document is corrected and comes into compliance, or the 
day that gasoline not additized in conformity with interim detergent 
program requirements, as a result of the product transfer document non-
conformity, is offered for sale or is dispensed to the ultimate 
consumer.
    (f) Volumetric additive reconciliation (VAR) record keeping non-
conformity. Any VAR recordkeeping violation of Sec. 80.155(b) shall 
constitute a separate day of violation for every day that VAR 
recordkeeping is not fully in compliance. Each element of the VAR record 
keeping program that is not in compliance shall constitute a separate 
violation for purposes of this section.
    (g) Volumetric additive reconciliation (VAR) compliance standard 
non-conformity. Any violation of the VAR compliance standard established 
in Sec. 80.157 shall constitute a separate day of violation for each and 
every day of the VAR compliance period in which the standard was 
violated.
    (h) Volumetric additive reconciliation (VAR) equipment calibration 
non-conformity. Any VAR equipment calibration violation of 
Sec. 80.155(b) shall constitute a separate day of violation for every 
day a VAR equipment calibration requirement is not met.



Sec. 80.160  Exemptions.

    (a) Research, development, and testing exemptions. Any detergent 
that is either in a research, development, or test status, or is sold to 
petroleum, automobile, engine, or component manufacturers for research, 
development, or test purposes, is exempted from the provisions of the 
interim detergent program, provided that:
    (1) The detergent (or fuel containing the detergent) is kept 
segregated from non-exempt product, and the party possessing the product 
maintains documentation identifying the product as research, 
development, or testing detergent or fuel, as applicable, and stating 
that it is to be used only for research, development, or testing 
purposes; and
    (2) The detergent (or fuel containing the detergent) is not sold, 
offered for sale, transferred, or offered for transfer from a retail 
outlet. It shall also not be transferred or offered for transfer from a 
wholesale purchaser-consumer facility, unless such facility is 
associated with detergent or fuel research, development or testing; and
    (3) The party using the product for research, development, or 
testing purposes notifies the EPA, on at least an annual basis and prior 
to the use of the product, of the purpose(s) of the program(s) in which 
the product will be used and the volume of the product to be used. This 
information must be submitted to the following EPA address: Director 
(6406J), Field Operations and Support Division, U.S. Environmental

[[Page 632]]

Protection Agency, 401 M Street SW., Washington, DC 20460.
    (b) Racing fuel and aviation fuel exemptions. Any fuel that is 
refined, sold, offered for sale, transferred, or offered for transfer as 
automotive racing fuel or as aircraft engine fuel, is exempted from the 
provisions of the interim detergent program, provided that:
    (1) The fuel is kept segregated from non-exempt fuel, and the party 
possessing the fuel for the purposes of refining, selling, offering for 
sale, transferring, or offering for transfer the fuel as automotive 
racing fuel or as aircraft engine fuel, maintains documentation 
identifying the product as racing fuel or aviation fuel, as applicable, 
and stating that is it not for street or highway use in motor vehicles; 
and
    (2) The fuel is not sold, offered for sale, transferred, or offered 
for transfer for highway use in a motor vehicle; and
    (3) In the case of racing fuel, the fuel is sold, offered for sale, 
transferred, or offered for transfer to the ultimate consumer only at a 
racing facility.
Sec. 80.161-80.169  [Reserved]

   Appendix A to Part 80--Test for the Determination of Phosphorus in 
                                Gasoline

1. Scope.

    1.1 This method was developed for the determination of phosphorus 
generally present as pentavalent phosphate esters or salts, or both, in 
gasoline. This method is applicable for the determination of phosphorus 
in the range from 0.0008 to 0.15 g P/U.S. gal, or 0.2 to 49 mg P/liter.

2. Applicable documents.

    2.1 ASTM Standards:
    D 1100 Specification for Filter Paper for Use in Chemical Analysis.

3. Summary of method.

    3.1 Organic matter in the sample is decomposed by ignition in the 
presence of zinc oxide. The residue is dissolved in sulfuric acid and 
reacted with ammonium molybdate and hydrazine sulfate. The absorbance of 
the ``Molybdenum Blue'' complex is proportional to the phosphorus 
concentration in the sample and is read at approximately 820 nm in a 5-
cm cell.

4. Apparatus.

    4.1 Buret, 10-ml capacity, 0.05-ml subdivisions.
    4.2 Constant-Temperature Bath, equipped to hold several 100-ml 
volumetric flasks submerged to the mark. Bath must have a large enough 
reservoir or heat capacity to keep the temperature at 180 to 190 deg. F 
(82.2 to 87.8 deg. C) during the entire period of sample heating.
    Note 1: If the temperature of the hot water bath drops below 
180 deg. F (82.2 deg. C) the color development may not be complete.
    4.3 Cooling Bath, equipped to hold several 100-ml volumetric flasks 
submerged to the mark in ice water.
    4.4 Filter Paper, for quantitative analysis, Class G for fine 
precipitates as defined in Specification D 1100.
    4.5 Ignition Dish--Coors porcelain evaporating dish, glazed inside 
and outside, with pourout (size no. 00A, diameter 75 mm. capacity 70 
ml).
    4.6 Spectrophotometer, equipped with a tungsten lamp, a red-
sensitive phototube capable of operating at 830 nm and with absorption 
cells that have a 5-cm light path.
    4.7 Thermometer, range 50 to 220 deg. F (10 to 105 deg. C).
    4.8 Volumetric Flask, 100-ml with ground-glass stopper.
    4.9 Volumetric Flask, 1000-ml with ground-glass stopper.
    4.10 Syringe, Luer-Lok, 10-ml equipped with 5-cm. 22-gage needle.

5. Reagents.

    5.1 Purity of Reagents--Reagent grade chemicals shall be used in all 
tests. Unless otherwise indicated, it is intended that all reagents 
shall conform to the specifications of the Committee on Analytical 
Reagents of the American Chemical Society, where such specifications are 
available. Other grades may be used, provided it is first ascertained 
that the reagent is of sufficiently high purity to permit its use 
without lessening the accuracy of the determination.
    5.2 Purity of Water--Unless otherwise indicated, references to water 
shall be understood to mean distilled water or water of equal purity.
    5.3 Ammonium Molybdate Solution--Using graduated cylinders for 
measurement add slowly (Note 2), with continuous stirring, 225 ml of 
concentrated sulfuric acid to 500 ml of water contained in a beaker 
placed in a bath of cold water. Cool to room temperature and add 20 g of 
ammonium molybdate tetrahydrate 
((NH4)6Mo7O244H2O). Stir until 
solution is complete and transfer to a 1000-ml flask. Dilute to the mark 
with water.
    Note 2: Wear a face shield, rubber gloves, and a rubber apron when 
adding concentrated sulfuric acid to water.
    5.4 Hydrazine Sulfate Solution--Dissolve 1.5 of hydrazine sulfate 
(H2NNH2H2SO4) in 1 litre of water, 
measured with a graduated cylinder.
    Note 3: This solution is not stable. Keep it tightly stoppered and 
in the dark. Prepare a fresh solution after 3 weeks.

[[Page 633]]

    5.5 Molybdate-Hydrazine Reagent--Pipet 25 ml of ammonium molybdate 
solution into a 100-ml volumetric flask containing approximately 50 ml 
of water, add by pipet 10 ml of 
N2NNH2H2SO4 solution, and dilute to 100 ml 
with water.
    Note 4: This reagent is unstable and should be used within about 4 
h. Prepare it immediately before use. Each determination (including the 
blank) uses 50 ml.
    5.6 Phosphorus, Standard Solution (10.0 g P/ml)--Pipet 10 
ml of stock standard phosphorus solution into a 1000-ml volumetric flask 
and dilute to the mark with water.
    5.7 Phosphorus, Stock Standard Solution (1.00 mg P/ml)--Dry 
approximately 5 g of potasium dihydrogen phosphate (KH2PO4 in 
an oven at 221 to 230 deg. F (105 to 110 deg. C) for 3 h. Dissolve 
4.393plus-minus0.002 g of the reagent in 150 ml, measured with a 
graduated cylinder, of H2SO4(1+10) contained in a 1000-ml 
volumetric flask. Dilute with water to the mark.
    5.8 Sulfuric Acid (1+10)--Using graduated cylinders for measurement 
add slowly (Note 2), with continuous stirring, 100-ml of concentrated 
sulfuric acid (H2SO4, sp gr 1.84) to 1 litre of water 
contained in a beaker placed in a bath of cold water.
    5.9 Zinc Oxide.
    Note 5: High-bulk density zinc oxide may cause spattering. Density 
of approximately 0.5 g/cm3 has been found satisfactory.

6. Calibration.

    6.1 Transfer by buret, or a volumetric transfer pipet, 0.0, 0.5, 
1.0, 1.5, 2.0, 3.0, 3.5, and 4.0 ml of phosphorus standard solution into 
100-ml volumetric flasks.
    6.2 Pipet 10 ml of H2SO4 (1+10) into each flask. Mix 
immediately by swirling.
    6.3 Prepare the molybdate-hydrazine solution. Prepare sufficient 
volume of reagent based on the number of samples being analyzed.
    6.4 Pipet 50 ml of the molybdate-hydrazine solution to each 
volumetric flask. Mix immediately by swirling.
    6.5 Dilute to 100 ml with water.
    6.6 Mix well and place in the constant-temperature bath so that the 
contents of the flask are submerged below the level of the bath. 
Maintain bath temperature at 180 to 190 deg. F (82.2 to 87.8 deg. C) for 
25 min (Note 1).
    6.7 Transfer the flask to the cooling bath and cool the contents 
rapidly to room temperature. Do not allow the samples to cool more than 
5 deg. F (2.8 deg. C) below room temperature.
    Note 6: Place a chemically clean thermometer in one of the flasks to 
check the temperature.
    6.8 After cooling the flasks to room temperature, remove them from 
the cooling water bath and allow them to stand for 10 min. at room 
temperature.
    6.9 Using the 2.0-ml phosphorus standard in a 5-cm cell, determine 
the wavelength near 820 nm that gives maximum absorbance. The wavelength 
giving maximum absorbance should not exceed 830 nm.
    6.9.1 Using a red-sensitive phototube and 5-cm cells, adjust the 
spectrophotometer to zero absorbance at the wavelength of maximum 
absorbance using distilled water in both cells. Use the wavelength of 
maximum absorbance in the determination of calibration readings and 
future sample readings.
    6.9.2 The use of 1-cm cells for the higher concentrations is 
permissible.
    6.10 Measure the absorbance of each calibration sample including the 
blank (0.0 ml phosphorus standard) at the wavelength of maximum 
absorbance with distilled water in the reference cell.
    Note 7: Great care must be taken to avoid possible contamination. If 
the absorbance of the blank exceeds 0.04 (for 5-cm cell), check for 
source of contamination. It is suggested that the results be disregarded 
and the test be rerun with fresh reagents and clean glassware.
    6.11 Correct the absorbance of each standard solution by subtracting 
the absorbance of the blank (0 ml phosphorus standard).
    6.12 Prepare a calibration curve by plotting the corrected 
absorbance of each standard solution against micrograms of phosphorus. 
One millilitre of phosphorus standard solution provides 10 g of 
phosphorus.

7. Sampling.

    7.1 Selection of the size of the sample to be tested depends on the 
expected concentration of phosphorous in the sample. If a concentration 
of phosphorus is suspected to be less than 0.0038 g/gal (1.0 mg/litre), 
it will be necessary to use 10 ml of sample.
    Note 8: Two grams of zinc oxide cannot absorb this volume of 
gasoline. Therefore the 10-ml sample is ignited in aliquots of 2 ml in 
the presence of 2 g of zinc oxide.
    7.2 The following table serves as a guide for selecting sample size:

------------------------------------------------------------------------
                                                                Sample  
  Phosphorus, milligrams per liter     Equivalent, grams per     size,  
                                              gallon          milliliter
------------------------------------------------------------------------
2.5 to 40...........................  0.01 to 0.15..........        1.00
1.3 to 20...........................  0.005 to 0.075........        2.00
0.9 to 13...........................  0.0037 to 0.05........        3.00
1 or less...........................  0.0038 or less........       10.00
------------------------------------------------------------------------

8. Procedure.

    8.1 Transfer 2plus-minus0.2 g of zinc oxide into a conical pile 
in a clean, dry, unetched ignition dish.
    Note 9: In order to obtain satisfactory accuracy with the small 
amounts of phosphorus involved, it is necessary to take extensive 
precautions in handling. The usual precautions of cleanliness, careful 
manipulation, and avoidance of contamination should be scrupulously 
observed; also, all glassware should be cleaned before use, with 
cleaning

[[Page 634]]

acid or by some procedure that does not involve use of commercial 
detergents. These compounds often contain alkali phosphates which are 
strongly adsorbed by glass surfaces and are not removed by ordinary 
rinsing. It is desirable to segregate a special stock of glassware for 
use only in the determination of phosphorus.
    8.2 Make a deep depression in the center of the zinc oxide pile with 
a stirring rod.
    8.3 Pipet the gasoline sample (Note 10) (see 7.2 for suggested 
sample volume) into the depression in the zinc oxide. Record the 
temperature of the fuel if the phosphorus content is required at 60 deg. 
F (15.6 deg. C) and make correction as directed in 9.2.
    Note 10: For the 10-ml sample use multiple additions and a syringe. 
Hold the tip of the needle at approximately \2/3\ of the depth of the 
zinc oxide layer and slowly deliver 2 ml of the sample: fast sample 
delivery may give low results. Give sufficient time for the gasoline to 
be absorbed by the zinc oxide. Follow step 8.6. Cool the dish to room 
temperature. Repeat steps 8.3 and 8.6 until all the sample has been 
burned. Safety--cool the ignition dish before adding the additional 
aliquots of gasoline to avoid a flash fire.
    8.4 Cover the sample with a small amount of fresh zinc oxide from 
reagent bottle (use the tip of a small spatula to deliver approximately 
0.2 g). Tap the sides of the ignition dish to pack the zinc oxide.
    8.5 Prepare the blank, using the same amount of zinc oxide in an 
ignition dish.
    8.6 Ignite the gasoline, using the flame from a bunsen burner. Allow 
the gasoline to burn to extinction (Note 10).
    8.7 Place the ignition dishes containing the sample and blank in a 
hot muffle furnace set at a temperature of 1150 to 1300 deg. F (621 to 
704 deg. C) for 10 min. Remove and cool the ignition dishes. When cool 
gently tap the sides of the dish to loosen the zinc oxide. Again place 
the dishes in the muffle furnace for 5 min. Remove and cool the ignition 
dishes to room temperature. The above treatment is usually sufficient to 
burn the carbon. If the carbon is not completely burned off place the 
dish into the oven for further 5-min. periods.
    Note 11: Step 8.7 may also be accomplished by heating the ignition 
dish with a Meker burner gradually increasing the intensity of heat 
until the carbon from the sides of the dish has been burned, then cool 
to room temperature.
    8.8 Pipet 25 ml of H2SO4 (1+10) to each ignition dish. 
While pipeting, carefully wash all traces of zinc oxide from the sides 
of the ignition dish.
    8.9 Cover the ignition dish with a borosilicate watch glass and warm 
the ignition dish on a hot plate until the zinc oxide is completely 
dissolved.
    8.10 Transfer the solution through filter paper to a 100-ml 
volumetric flask. Rinse the watch glass and the dish several times with 
distilled water (do not exceed 25 ml) and transfer the washings through 
the filter paper to the volumetric flask.
    8.11 Prepare the molybdate-hydrazine solution.
    8.12 Add 50 ml of the molybdate-hydrazine solution by pipet to each 
100-ml volumetric flask. Mix immediately by swirling.
    8.13 Dilute to 100 ml with water and mix well. Remove stoppers from 
flasks after mixing.
    8.14 Place the 100-ml flasks in the constant-temperature bath for 25 
min. so that the contents of the flasks are below the liquid level of 
the bath. The temperature of the bath should be 180 to 190 deg. F (82.2 
to 87.8 deg. C) (Note 1).
    8.15 Transfer the 100-ml flasks to the cooling bath and cool the 
contents rapidly to room temperature (Note 6).
    8.16 Allow the samples to stand at room temperature before measuring 
the absorbance.
    Note 12: The color developed is stable for at least 4 h.
    8.17 Set the spectrophotometer to the wavelength of maximum 
absorbance as determined in 6.9. Adjust the spectrophotometer to zero 
absorbance, using distilled water in both cells.
    8.18 Measure the absorbance of the samples at the wavelength of 
maximum absorbance with distilled water in the reference cell.
    8.19 Subtract the absorbance of the blank from the absorbance of 
each sample (Note 7).
    8.20 Determine the micrograms of phosphorous in the sample, using 
the calibration curve from 6.12 and the corrected absorbance.

9. Calculations.

    9.1 Calculate the milligrams of phosphorus per litre of sample as 
follows:

                             P, mg/litre=P/V

where:
P=micrograms of phosphorus read from calibration curve, and
V=millilitres of gasoline sample.

To convert to grams of phosphorus per U.S. gallon of sample, multiply mg 
P/litre by 0.0038.
    9.2 If the gasoline sample was taken at a temperature other than 
60 deg. F (15.6 deg. C) make the following temperature correction:
mg P/litre at 15.6 deg. C=[mg P/litre at t] [1+0.001 (t-15.6)]
where:
t=observed temperature of the gasoline,  deg. C.

    9.3 Concentrations below 2.5 mg/litre or 0.01 g/gal should be 
reported to the nearest 0.01 mg/litre or 0.0001 g/U.S. gal.

[[Page 635]]

    9.3.1 For higher concentrations, report results to the nearest 1 mg 
P/litre or 0.005 g P/U.S. gal.

10. Precision.

    10.1 The following criteria should be used for judging the 
acceptability of results (95 percent confidence):
    10.2 Repeatability--Duplicate results by the same operator should be 
considered suspect if they differ by more than the following amounts:

------------------------------------------------------------------------
    g P/U.S. gal (mg P/litre)             Repeatability       
------------------------------------------------------------------------
0.0008 to 0.005 (0.2 to 1.3)..............  0.0002 g P/U.S. gal (0.05 mg
                                             P/litre).                  
0.005 to 0.15 (1.3 to 40).................  7% of the mean.             
------------------------------------------------------------------------

    10.3 Reproducibility--The results submitted by each of two 
laboratories should not be considered suspect unless they differ by more 
than the following amounts:

------------------------------------------------------------------------
    g P/U.S. gal (mg P/litre)            Reproducibility      
------------------------------------------------------------------------
0.0008 to 0.005 (0.2 to 1.3)..............  0.0005 g P/U.S. gal (0.13 mg
                                             P/litre).                  
0.005 to 0.15 (1.3 to 40).................  13% of the mean.            
------------------------------------------------------------------------

[39 FR 24891, July 8, 1974; 39 FR 25653, July 12, 1974]

        Appendix B to Part 80--Test Methods for Lead in Gasoline

Method 1--Standard Method Test for Lead in Gasoline by Atomic Absorption 
                              Spectrometry

1. Scope. 

    1.1. This method covers the determination of the total lead content 
of gasoline. The procedure's calibration range is 0.010 to 0.10 gram of 
lead/U.S. gal. Samples above this level should be diluted to fall within 
this range or a higher level calibration standard curve must be 
prepared. The higher level curve must be shown to be linear and 
measurement of lead at these levels must be shown to be accurate by the 
analysis of control samples at a higher level of alkyl lead content. The 
method compensates for variations in gasoline composition and is 
independent of lead alkyl type.

2. Summary of method.

    2.1 The gasoline sample is diluted with methyl isobutyl ketone and 
the alkyl lead compounds are stabilized by reaction with iodine and a 
quarternary ammonium salt. The lead content of the sample is determined 
by atomic absorption flame spectrometry at 2833 A, using standards 
prepared from reagent grade lead chloride. By the use of this treatment, 
all alkyl lead compounds give identical response.

3. Apparatus.

    3.1 Atomic Absorption Spectometer, capable of scale expansion and 
nebulizer adjustment, and equipped with a slot burner and premix chamber 
for use with an air-acetylene flame.
    3.2 Volumetric Flasks, 50-ml, 100-ml, 250-ml, and one litre sizes.
    3.3 Pipets, 2-ml, 5-ml, 10-ml, 20-ml, and 50-ml sizes.
    3.4 Micropipet, 100-l, Eppendorf type or equivalent.

4. Reagents.

    4.1 Purity of Reagents--Reagent grade chemicals shall be used in all 
tests. Unless otherwise indicated, it is intended that all reagents 
shall conform to the specifications of the Committee on Analytical 
Reagents of the American Chemical Society, where such specifications are 
available. Other grades may be used, provided it is first ascertained 
that the reagent is of sufficiently high purity to permit its use 
without lessening the accuracy of the determination.
    4.2 Purity of Water--Unless otherwise indicated, references to water 
shall be understood to mean distilled water or water of equal purity.
    4.3 Aliquat 336 (tricapryl methyl ammonium chloride).
    4.4 Aliquat 336/MIBK Solution (10 percent v/v)--Dissolve and dilute 
100 ml (88.0 g) of Aliquat 336 with MIBK to one liter.
    4.5 Aliquat 336/MIBK Solution (1 percent v/v)--Dissolve and dilute 
10 ml (8.8 g) of Aliquat 336 with MIBK to one liter.
    4.6 Iodine Solution--Dissolve and dilute 3.0 g iodine crystals with 
Toluene to 100 ml.
    4.7 Lead Chloride.
    4.8 Lead-Sterile Gasoline--Gasoline containing less than 0.005 g Pb/
gal.
    4.9 Lead, Standard Solution (5.0 g Pb/gal)--Dissolve 0.4433 g of 
lead chloride (PbCl2) previously dried at 105 deg. C for 3 h in 
about 200 ml of 10 percent Aliquat 336/MIBK solution in a 250-ml 
volumetric flask. Dilute to the mark with the 10 percent Aliquat 
solution, mix, and store in a brown bottle having a polyethylene-lined 
cap. This solution contains 1,321 g Pb/ml, which is equivalent 
to 5.0 g Pb/gal.
    4.10 Lead, Standard Solution (1.0 g Pb/gal)--By means of a pipet, 
accurately transfer 50.0 ml of the 5.0 g Pb/gal solution to a 250-ml 
volumetric flask, dilute to volume with 1 percent Aliquat/MIBK solution. 
Store in a brown bottle having a polyethylene-lined cap.
    4.11 Lead, Standard Solutions (0.02, 0.05, and 0.10 g Pb/gal)--
Transfer accurately by means of pipets 2.0, 5.0, and 10.0 ml of the 1.0-
g Pb/gal solution to 100-ml volumetric flasks; add 5.0 ml of 1 percent 
Aliquat 336 solution to each flask; dilute to the mark with MIBK. Mix 
well and store in bottles having polyethylene-lined caps.

[[Page 636]]

    4.12 Methyl Isobutyl Ketone (MIBK). (4-methyl-2-pentanone).

5. Calibration.

    5.1 Preparation of Working Standards--Prepare three working 
standards and a blank using the 0.02, 0.05, and 0.10-g Pb/gal standard 
lead solutions described in 4.11.
    5.1.1 To each of four 50-ml volumetric flasks containing 30 ml of 
MIBK, add 5.0 ml of low lead standard solution and 5.0 ml of lead-free 
gasoline. In the case of the blank, add only 5.0 ml of lead-free 
gasoline.
    5.1.2 Add immediately 0.1 ml of iodine/toluene solution by means of 
the 100-l Eppendorf pipet. Mix well.1
---------------------------------------------------------------------------

    1 EPA practice will be to mix well by shaking vigorously for 
approximately one minute.
---------------------------------------------------------------------------

    5.1.3 Add 5 ml of 1 percent Aliquat 336 solution and mix.
    5.1.4 Dilute to volume with MIBK and mix well.
    5.2 Preparation of Instrument--Optimize the atomic absorption 
equipment for lead at 2833 A. Using the reagent blank, adjust the gas 
mixture and the sample aspiration rate to obtain an oxidizing flame.
    5.2.1 Aspirate the 0.1-g Pb/gal working standard and adjust the 
burner position to give maximum response. Some instruments require the 
use of scale expansion to produce a reading of 0.150 to 0.170 for this 
standard.
    5.2.2 Aspirate the reagent blank to zero the instrument and check 
the absorbances of the three working standards for linearity.

6. Procedure.

    6.1 To a 50 ml volumetric flask containing 30 ml MIBK, add 5.0 ml of 
gasoline sample and mix.\2\
---------------------------------------------------------------------------

    \2\ The gasoline should be allowed to come to room temperature 
(25 deg. C).
---------------------------------------------------------------------------

    6.1.1 Add 0.10 ml (100 l) of iodine/toluene solution and 
allow the mixture to react about 1 minute.\3\
---------------------------------------------------------------------------

    \3\ See footnote 1 of section 5.1.2.
---------------------------------------------------------------------------

    6.1.2 Add 5.0 ml of 1 percent Aliquot 336/MIBK solution and mix.
    6.1.3 Dilute to volume with MIBK and mix.
    6.2 Aspirate the samples and working standards and record the 
absorbance values with frequent checks of the zero.
    6.3  Any sample resulting in a peak greater than 0.05 g Pb/gal will 
be run in duplicate. Samples registering greater than 0.10 g Pb/gal 
should be diluted with iso-octane or unleaded fuel to fall within the 
calibration range or a higher level calibration standard curve must be 
prepared. The higher level curve must be shown to be linear and 
measurement of lead at these levels must be shown to be accurate by the 
analysis of control samples at a higher level of alkyl lead content.

7. Calculations.

    7.1 Plot the absorbance values versus concentration represented by 
the working standards and read the concentrations of the samples from 
the graph.

8. Precision.

    8.1 The following criteria should be used for judging the 
acceptability of results (95 percent confidence):
    8.1.1 Repeatability--Duplicate results by the same operator should 
be considered suspect if they differ by more than 0.005 g/gal.
    8.1.2 Reproductibility--The results submitted by each of two 
laboratories should not be considered suspect unless the two results 
differ by more than 0.01 g/gal.

     Method 2--Automated Method Test for Lead in Gasoline by Atomic 
                         Absorption Spectrometry

1. Scope and application. 

    1.1  This method covers the determination of the total lead content 
of gasoline. The procedure's calibration range is 0.010 to 0.10 gram of 
lead/U.S. gal. Samples above this level should be diluted to fall within 
this range or a higher level calibration standard curve must be 
prepared. The higher level curve must be shown to be linear and 
measurement of lead at these levels must be shown to be accurate by the 
analysis of control samples at a higher level of alkyl lead content. The 
method compensates for variations in gasoline composition and is 
independent of lead alkyl type.
    1.2  This method may be used as an alternative to the Standard 
Method set forth above.
    1.3  Where trade names or specific products are noted in the method, 
equivalent apparatus and chemical reagents may be used. Mention of trade 
names or specific products is for the assistance of the user and does 
not constitute endorsement by the U.S. Environmental Protection Agency.

2. Summary of method. 

    2.1  The gasoline sample is diluted with methly isobutyl ketone 
(MIBK) and the alkyl lead compounds are stabilized by reacting with 
iodine and a quarternary ammonium salt. An automated system is used to 
perform the diluting and the chemical reactions and feed the products to 
the atomic absorption spectrometer with an air-acetylene flame.
    2.2  The dilution of the gasoline with MIBK compensates for severe 
non-atomic absorption, scatter from unburned carbon containing species 
and matrix effects caused in part by the burning characteristics of 
gasoline.
    2.3  The in-situ reaction of alkyl lead in gasoline with iodine 
eliminates the problem of variations in response due to different alkyl 
types by leveling the response of all alkyl lead compounds.

[[Page 637]]

    2.4  The addition of the quarternary ammonium salt improves response 
and increases the stability of the alkyl iodide complex.

3. Sample handling and preservation. 

    3.1  Samples should be collected and stored in containers which will 
protect them from changes in the lead content of the gasoline such as 
from loss of volatile fractions of the gasoline by evaporation or 
leaching of the lead into the container or cap.
    3.2  If samples have been refrigerated they should be brought to 
room temperature prior to analysis.

4. Apparatus. 

    4.1  AutoAnalyzer system consisting of:
    4.1.1  Sampler 20/hr cam, 30/hr cam.
    4.1.2  Proportioning pump.
    4.1.3  Lead in gas manifold.
    4.1.4  Disposable test tubes.
    4.1.5  Two 2-liter and one 0.5 liter Erlenmeyer solvent displacement 
flasks. Alternatively, high pressure liquid chromatography (HPLC) or 
syringe pumps may be used.
    4.2  Atomic Absorption Spectroscopy (AAS) Detector System consisting 
of:
    4.2.1  Atomic absorption spectrometer.
    4.2.2  10'' strip chart recorder.
    4.2.3  Lead hollow cathode lamp or electrodeless discharge lamp 
(EDL).

5. Reagents. 

    5.1  Aliquat 336/MIBK solution (10% v/v): Dissolve and dilute 100 ml 
(88.0 g) of Aliquat 336 (Aldrich Chemical Co., Milwaukee, Wisconsin) 
with MIBK (Burdick & Jackson Lab., Inc., Muskegon, Michigan) to one 
liter.
    5.2  Aliquat 336/iso-octane solution (1% v/v): Dissolve and dilute 
10 ml (8.8 g) of Alquat 336 (reagent 5.1) with iso-octane to one liter.
    5.3  Iodine solution (3% w/v): Dissolve and dilute 3.0 g iodine 
crystals (American Chemical Society) with toluene (Burdick & Jackson 
Lab., Inc., Muskegon, Michigan) to 100 ml.
    5.4  Iodine working solution (0.24% w/v): Dilute 8 ml of reagent 5.3 
to 100 ml with toluene.
    5.5  Methyl isobutyl ketone (MIBK) (4-methlyl-2-pentanone).
    5.6  Certified unleaded gasoline (Phillips Chemical Co., Borger, 
Texas) or iso-octane (Burdick & Jackson Lab, Inc., Muskegon, Michigan).

6. Calibration standards. 

    6.1  Stock 5.0 g Pb/gal Standard:
    Dissolve 0.4433 gram of lead chloride (PbCl2) previously dried 
at 105 deg. C for 3 hours in 200 ml of 10% v/v Aliquat 336/MIBK solution 
(reagent 5.1) in a 250 ml volumetric flask. Dilute to volume with 
reagent 5.1 and store in an amber bottle.
    6.2  Intermediate 1.0 g Pb/gal Standard:
    Pipet 50 ml of the 5.0 g Pb/gal standard into a 250 ml volumetric 
flask and dilute to volume with a 1% v/v Aliquat 336/iso-octane solution 
(reagent 5.2). Store in an amber bottle.
    6.3  Working 0.02, 0.05, 0.10 g Pb/gal Standards:
    Pipet 2.0, 5.0, and 10.0 ml of the 1.0 g Pb/gal solution to 100 ml 
volumetric flasks. Add 5 ml of a 1% Aliquat 336/iso-octane solution to 
each flask. Dilute to volume with iso-octane. These solutions contain 
0.02, 0.05, and 0.10 g Pb/gal in a 0.05% Aliquat 336/iso-octane 
solution.

7. AAS Instrumental conditions. 

    7.1  Lead hollow cathode lamp.
    7.2  Wavelength: 283.3 nm.
    7.3  Slit: 4 (0.7mm).
    7.4  Range: UV.
    7.5  Fuel: Acetylene (approx. 20 ml/min at 8 psi).
    7.6  Oxidant: Air (approx. 65 ml/min at 31 psi).
    7.7  Nebulizer: 5.2 ml/min.
    7.8  Chart speed: 10 in/hr.

8. Procedures. 

    8.1  AAS start-up.
    8.1.1  Assure that instrumental conditions have been optimized and 
aligned according to Section 7 and the instrument has had substantial 
time for warm-up.
    8.2  Auto Analyzer start-up [see figure 1].
    8.2.1  Check all pump tubing and replace as necessary. Iodine tubing 
should be changed daily. All pump tubing should be replaced after one 
week of use. Place the platen on the pump.
    8.2.2  Withdraw any water from the sample wash cup and fill with 
certified unleaded gasoline (reagent 5.6).
    8.2.3  Fill the 2-liter MIBK dilution displacement Erlenmeyer flask 
(reagent 5.5) and the 0.5 liter Aliquat 336/MIBK 1% v/v (reagent 5.2) 
displacement flask and place the rubber stopper glass tubing assemblies 
in their respective flasks.
    8.2.4  Fill a 2-liter Erlenmeyer flask with distilled water. The 
water will be used to displace the solvents. Therefore, place the 
appropriate lines in this flask. This procedure is not relevant if 
syringe pumps are used.
    8.2.5  Fill the final debubbler reverse displacement 2-liter 
Erlenmeyer flask with distilled water and place the rubber stopper glass 
tubing assembly in the flask.
    8.2.6  Place the appropriate lines for the iodine reagent (reagent 
5.4) and the wash solution (reagent 5.6) in their respective bottles.
    8.2.7  Start the pump and connect the aspiration line from the 
manifold to the AAS.
    8.2.8  Some initial checks to assure that the reagents are being 
added are:
    a. A good uniform bubble pattern.
    b. Yellow color evident due to iodine in the system.
    c. No surging in any tubing.
    8.3  Calibration.

[[Page 638]]

    8.3.1  Turn the chart drive on and obtain a steady baseline.
    8.3.2  Load standards and samples into sample tray.
    8.3.3  Start the sampler and run the standards (Note: first check 
the sample probe positioning with an empty test tube).
    8.3.4  Check the linearity of calibration standards response and 
slope by running a least squares fit. Check these results against 
previously obtained results. They should agree within 10%.
    8.3.5  If the above is in control then start the sample analysis.
    8.4  Sample Analysis.
    8.4.1  To minimize gasoline vapor in the laboratory, load the sample 
tray about 5-10 test tubes ahead of the sampler.
    8.4.2  Record the sample number on the strip chart corresponding to 
the appropriate peak.
    8.4.3  Every ten samples run the high calibration standard and a 
previously analyzed sample (duplicate). Also let the sampler skip to 
check the baseline.
    8.4.4  After an acceptable peak (within the calibration range) is 
obtained, pour the excess sample from the test tube into the waste 
gasoline can.
    8.4.5  Any sample resulting in a peak greater than 0.05 g Pb/gal 
will be run in duplicate. Samples registering greater than 0.10 g Pb/gal 
should be diluted with iso-octane or unleaded fuel to fall within the 
calibration range or a higher level calibration standard curve must be 
prepared. The higher level curve must be shown to be linear and 
measurement of lead at these levels must be shown to be accurate by the 
analysis of control samples at a higher level of alkyl lead content.
    8.5  Shut Down.
    8.5.1  Replace the solvent displacement flask with flasks filled 
with distilled water. Also place all other lines in a beaker of 
distilled water. Rinse the system with distilled water for 15 minutes.
    8.5.2  Withdraw the gasoline from the wash cup and fill with water.
    8.5.3  Dispose of all solvent waste in waste glass bottles.
    8.5.4  Turn the AAS off after extinguishing the flame. Also turn the 
recorder and pump off. Remove the platen and release the pump tubing.
    8.5.5  Shut the acetylene off at the tank and bleed the line.

9. Quality control. 

    9.1  Precision.
    9.1.1  All duplicate results should be considered suspect if they 
differ by more than 0.005 g Pb/gal.
    9.2  Accuracy.
    9.2.1  All quality control standard checks should agree within 10% 
of the nominal value of the standard.
    9.2.2  All spikes should agree within 10% of the known addition.

10. Past quality control data. 

    10.1  Precision.
    10.1.1  Duplicate analysis for 156 samples in a single laboratory 
has resulted in an average difference of 0.00011 g Pb/gal with a 
standard deviation of 0.0023.
    10.1.2  Replicate analysis in a single laboratory (greater than 5 
determinations) of samples at concentrations of 0.010, 0.048, and 0.085 
g Pb/gal resulted in relative standard deviations of 4.2%, 3.5%, and 
3.3% respectively.
    10.2  Accuracy.
    10.2.1  The analysis of National Bureau of Standards (NBS) lead in 
reference fuel of known concentrations in a single laboratory has 
resulted in found values deviating from the true value for 11 
determinations of 0.0322 g Pb/gal by an average of 0.56% with a standard 
deviation of 6.8%, for 15 determinations of 0.0519 g Pb/gal by an 
average of -1.1% with a standard deviation of 5.8%, and for 7 
determinations of 0.0725 g Pb/gal by an average of 3.5% with a standard 
deviation of 4.8%.
    10.2.2  Twenty-three analyses of blind reference samples in a single 
laboratory (U.S. EPA, RTP, N.C.) have resulted in found values differing 
from the true value by an average of -0.0009 g Pb/gal with a standard 
deviation of 0.004.
    10.2.3  In a single laboratory, the average percent recovery of 108 
spikes made to samples was 101% with a standard deviation of 5.6%.

[[Page 639]]

[GRAPHIC] [TIFF OMITTED] TC01SE92.139



[[Page 640]]

        Method 3--Test for Lead in Gasoline by X-Ray Spectrometry

1. Scope and application.

    1.1  This method covers the determination of the total lead content 
of gasoline. The procedure's calibration range is 0.010 to 5.0 grams of 
lead/U.S. gallon. Samples above this level should be diluted to fall 
within the range of 0.05 to 5.0 grams of lead/U.S. gallon. The method 
compensates for variations in gasoline composition and is independent of 
lead alkyl type.
    1.2  This method may be used as an alternative to Method 1--Standard 
Method Test for Lead in Gasoline by Atomic Absorption Spectrometry, or 
to Method 2--Automated Method Test for Lead in Gasoline by Atomic 
Absorption Spectrometry.
    1.3  Where trade names or specific products are noted in the method, 
equivalent apparatus and chemical reagents may be used. Mention of trade 
names or specific products is for the assistance of the user and does 
not constitute endorsement by the U.S. Environmental Protection Agency.

2. Summary of method.

    2.1  A portion of the gasoline sample is placed in an appropriate 
holder and loaded into an X-ray spectrometer. The ratio of the net X-ray 
intensity of the lead L alpha radiation to the net intensity of the 
incoherently scattered tungsten L alpha radiation is measured. The lead 
content is determined by reference to a linear calibration equation 
which relates the lead content to the measured ratio.
    2.2  The incoherently scattered tungsten radiation is used to 
compensate for variations in gasoline samples.

3. Sample handling and preservation.

    3.1  Samples should be collected and stored in containers which will 
protect them from changes in the lead content of the gasoline, such as 
loss of volatile fractions of the gasoline by evaporation or leaching of 
the lead into the container or cap.
    3.2  If samples have been refrigerated they should be brought to 
room temperature prior to analysis.
    3.3  Gasoline is extremely flammable and should be handled 
cautiously and with adequate ventilation. The vapors are harmful if 
inhaled and prolonged breathing of vapors should be avoided. Skin 
contact should be minimized. See precautionary statements in Annex Al.3.

4. Apparatus.

    4.1  X-ray Spectrometer, capable of exciting and measuring the 
fluorescence lines mentioned in 2.1 and of being operated under the 
following instrumental conditions or others giving equivalent results: a 
tungsten target tube operated at 50 kV, a lithium fluoride analyzing 
crystal, an air or helium optical path and a proportional or 
scintillation detector.
    4.2  Some manufacturers of X-ray Spectrometer units no longer allow 
use of air as the beam path medium because the X-ray beam produces 
ozone, which may degrade seals and electronics. In addition, use of the 
equipment with liquid gasoline in close proximity to the hot X-ray tube 
could pose flammability problems with any machine in case of a rupture 
of the sample container. Therefore, use of the helium alternative is 
recommended.

5. Reagents.

    5.1  Isooctane. Isooctane is flammable and the vapors may be 
harmful. See precautions in Annex Al.1.
    5.2  Lead standard solution, in isooctane, toluene or a mixture of 
these two solvents, containing approximately 5 gm Pb/U.S. gallon may be 
prepared from a lead-in-oil concentrate such as those prepared by 
Conostan (Conoco, Inc., Ponca City, Oklahoma). Isooctane and toluene are 
flammable and the vapors may be harmful. See precautionary statements in 
Annex Al.1 and Al.2.

6. Calibration.

    6.1  Make exact dilutions with isooctane of the lead standard 
solution to give solutions with concentrations of 0.01, 0.05, 0.10, 
0.50, 1.0, 3.0 and 5.0 g Pb/U.S. gallon. If a more limited range is 
desired as required for linearity, such range shall be covered by at 
least five standard solutions approximately equally spaced and this 
range shall not be exceeded by any of the samples. Place each of the 
standard solutions in a sample cell using techniques consistent with 
good operating practice for the spectrometer employed. Insert the sample 
in the spectrometer and allow the spectrometer atmosphere to reach 
equilibrium (if appropriate). Measure the intensity of the lead L alpha 
peak at 1.175 angstroms, the Compton scatter peak of the tungsten L 
alpha line at 1.500 angstroms and the background at 1.211 angstroms. 
Each measured intensity should exceed 200,000 counts or the time of 
measurement should be at least 30 seconds. The relative standard 
deviation of each measurement, based on counting statistics, should be 
one percent or less. The Compton scatter peak given above is for 90 deg. 
instrument geometry and should be changed for other geometries. The 
Compton scatter peak (in angstroms) is found at the wavelength of the 
tungsten L alpha line plus 0.024 (1-cos phi), where phi is the angle 
between the incident radiation and the take-off collimator.
    6.2  For Each of the standards, as well as for an isooctane blank, 
determine the net lead intensity by subtracting the corrected background 
from the gross intensity. Determine the corrected background by 
multiplying the intensity of the background at 1.211

[[Page 641]]

angstroms by the following ratio obtained on an isooctane blank:

                                                                        
                      Background at 1.175 angstroms                     
      ------------------------------------------------------------      
                      Background at 1.211 angstroms                     
                                                                        

    6.3  Determine the corrected lead intensity ratio, which is the net 
lead intensity corrected for matrix effects by division by the net 
incoherently scattered tungsten radiation. The net scattered intensity 
is calculated by subtracting the background intensity at 1.211 angstroms 
from the gross intensity of the incoherently scattered tungsten L alpha 
peak. The equation for the corrected lead intensity ratio follows:

                                                                        
                       Lead L alpha--corrected background               
  R=  ------------------------------------------------------------------
                    Incoherent tungsten L alpha--background             
                                                                        

    6.4  Obtain a linear calibration curve by performing a least squares 
fit of the corrected lead intensity ratios to the standard 
concentrations.

7. Procedure.

    7.1  Prepare a calibration curve as described in 6. Since the 
scattered tungsten radiation serves as an internal standard, the 
calibration curve should serve for at least several days. Each day the 
suitability of the calibration curve should be checked by analyzing 
several National Bureau of Standards (NBS) lead-in-reference-fuel 
standards or other suitable standards.
    7.2  Determine the corrected lead intensity ratio for a sample in 
the same manner as was done for the standards. The samples should be 
brought to room temperature before analysis.
    7.3  Determine the lead concentration of the sample from the 
calibration curve. If the sample concentration is greater than 5.0 g Pb/
U.S. gallon or the range calibrated for in 6.1, the sample should be 
diluted so that the result is within the calibration span of the 
instrument.
    7.4  Quality control standards, such as NBS standard reference 
materials, should be analyzed at least once every testing session.
    7.5  For each group of ten samples, a spiked sample should be 
prepared by adding a known amount of lead to a sample. This known 
addition should be at least 0.05 g Pb/U.S. gallon, at least 50% of the 
measured lead content of the unspiked sample, and not more than 200% of 
the measured lead content of the unspiked sample (unless the minimum 
addition of 0.05 g Pb/U.S. gallon exceeds 200%). Both the spiked and 
unspiked samples should be analyzed.

8. Quality control.

    8.1  The difference between duplicates should not exceed 0.005 g Pb/
U.S. gallon or a relative difference of 6%.
    8.2  All quality control standard check samples should agree within 
10% of the nominal value of the standard.
    8.3  All spiked samples should have a percent recovery of 100% 
 10%. The percent recovery, P, is calculated as follows:

P=100 X (A-B)/K

where
A=the analytical result from the spiked sample, B= the analytical result 
          from the unspiked sample, and K= the known addition.

    8.4  The difference between independent analyses of the same sample 
in different laboratories should not exceed 0.01 g Pb/U.S. gallon or a 
relative difference of 12%.

9. Past quality control data.

    9.1  Duplicate analysis for 26 samples in the range of 0.01 to 0.10 
g Pb/U.S. gallon resulted in an average relative difference of 5.2% with 
a standard deviation of 5.4%. Duplicate analysis of 14 samples in the 
range 0.1 to 0.5 g Pb/U.S. gallon resulted in an average relative 
difference of 2.3% with a standard deviation of 2.0. Duplicate analysis 
of 47 samples in the range of 0.5 to 5 g Pb/U.S. gallon resulted in an 
average relative difference of 2.1% with a standard deviation of 1.8%.
    9.2  The average percent recovery for 23 spikes made to samples in 
the 0.0 to 0.1 g Pb/U.S. gallon range was 103% with a standard deviation 
of 3.2%. For 42 spikes made to samples in the 0.1 to 5.0 g Pb/U.S. 
gallon range, the average percent recovery was 102% with a standard 
deviation of 4.2%.
    9.3  The analysis of National Bureau of Standards lead-in-reference-
fuel standards of known concentrations in a single laboratory has 
resulted in found values deviating from the true value for 14 
determinations of 0.0490 g Pb/U.S. gallon by an average of 2.8% with a 
standard deviation of 6.4%, for 11 determinations of 0.065 g Pb/U.S. 
gallon by an average of 4.4% with a standard deviation of 2.9%, and for 
15 determinations of 1.994 g Pb/U.S. gallon by an average of 0.3% with a 
standard deviation of 1.3%.
    9.4  Eighteen analyses of reference samples (U.S. EPA, Research 
Triangle Park, NC) have resulted in found values differing from the true 
value by an average of 0.0004 g Pb/U.S. gallon with a standard deviation 
of 0.004 g Pb/U.S. gallon.

                                  Annex

                      A1.  Precautionary Statements

                             A1.1  Isooctane

Danger--Extremely flammable. Vapors harmful if inhaled.
Vapor may cause flash fire.

[[Page 642]]

Keep away from heat, sparks, and open flame.
Vapors are heavier than air and may gather in low places, resulting in 
explosion hazard.
Keep container closed.
Use adequate ventilation.
Avoid buildup of vapors.
Avoid prolonged breathing of vapor or spray mist.
Avoid prolonged or repeated skin contact.

                              A1.2  Toluene

Warning--Flammable. Vapor harmful.
Keep away from heat, sparks, and open flame.
Keep container closed.
Use with adequate ventilation.
Avoid breathing of vapor or spray mist.
Avoid prolonged or repeated contact with skin.

                             A1.3  Gasoline

Danger--Extremely flammable. Vapors harmful if inhaled.
Vapor may cause flash fire.
Keep away from heat, sparks, and open flame.
Vapors are heavier than air and may gather in low places, resulting in 
explosion hazard.
Keep container closed.
Use adequate ventilation.
Avoid buildup of vapors.
Avoid prolonged breathing of vapor or spray mist.
Avoid prolonged or repeated skin contact.

[39 FR 24891, July 8, 1974; 39 FR 25653, July 12, 1974; 39 FR 26287, 
July 18, 1974, as amended at 47 FR 765, Jan. 7, 1982; 52 FR 259, Jan. 5, 
1987; 56 FR 13768, Apr. 4, 1991]

                    Appendix C to Part 80--[Reserved]

     Appendix D to Part 80--Sampling Procedures for Fuel Volatility

                                1. Scope.

    1.1  This method covers procedures for obtaining representative 
samples of gasoline for the purpose of testing for compliance with the 
Reid vapor pressure (RVP) standards set forth in Sec. 80.27.

                          2. Summary of method.

    2.1  It is necessary that the samples be truly representative of the 
gasoline in question. The precautions required to ensure the 
representative character of the samples are numerous and depend upon the 
tank, carrier, container or line from which the sample is being 
obtained, the type and cleanliness of the sample container, and the 
sampling procedure that is to be used. A summary of the sampling 
procedures and their application is presented in Table 1. Each procedure 
is suitable for sampling a material under definite storage, 
transportation, or container conditions. The basic principle of each 
procedure is to obtain a sample in such manner and from such locations 
in the tank or other container that the sample will be truly 
representative of the gasoline.

                        3. Description of terms.

    3.1  Average sample is one that consists of proportionate parts from 
all sections of the container.
    3.2  All-levels sample is one obtained by submerging a stoppered 
beaker or bottle to a point as near as possible to the draw-off level, 
then opening the sampler and raising it at a rate such that it is 70-85% 
full as it emerges from the liquid. An all-levels sample is not 
necessarily an average sample because the tank volume may not be 
proportional to the depth and because the operator may not be able to 
raise the sampler at the variable rate required for proportionate 
filling. The rate of filling is proportional to the square root of the 
depth of immersion.
    3.3  Running sample is one obtained by lowering an unstoppered 
beaker or bottle from the top of the gasoline to the level of the bottom 
of the outlet connection or swing line, and returning it to the top of 
the gasoline at a uniform rate of speed such that the beaker or bottle 
is 70-85% full when withdrawn from the gasoline.
    3.4  Spot sample is one obtained at some specific location in the 
tank by means of a thief bottle, or beaker.
    3.5  Top sample is a spot sample obtained 6 inches (150 mm) below 
the top surface of the liquid (Figure 1).
    3.6  Upper sample is a spot sample taken at the mid-point of the 
upper third of the tank contents (Figure 1).
    3.7  Middle sample is a spot sample obtained from the middle of the 
tank contents (Figure 1).
    3.8  Lower sample is a spot sample obtained at the level of the 
fixed tank outlet or the swing line outlet (Figure 1).
    3.9  Clearance sample is a spot sample taken 4 inches (100 mm) below 
the level of the tank outlet (Figure 1).
    3.10  Bottom sample is one obtained from the material on the bottom 
surface of the tank, container, or line at its lowest point.
    3.11  Drain sample is one obtained from the draw-off or discharge 
valve. Occasionally, a drain sample may be the same as a bottom sample, 
as in the case of a tank car.
    3.12  Continuous sample is one obtained from a pipeline in such 
manner as to give a representative average of a moving stream.
    3.13  Mixed sample is one obtained after mixing or vigorously 
stirring the contents of the original container, and then pouring out or 
drawing off the quantity desired.

[[Page 643]]

    3.14  Nozzle sample is one obtained from a gasoline pump nozzle 
which dispenses gasoline from a storage tank at a retail outlet or a 
wholesale purchaser-consumer facility.

                          4. Sample containers.

    4.1  Sample containers may be clear or brown glass bottles, or cans. 
The clear glass bottle is advantageous because it may be examined 
visually for cleanliness, and also allows visual inspection of the 
sample for free water or solid impurities. The brown glass bottle 
affords some protection from light. Cans with the seams soldered on the 
exterior surface with a flux of rosin in a suitable solvent are 
preferred because such a flux is easily removed with gasoline, whereas 
many others are very difficult to remove. If such cans are not 
available, other cans made with a welded construction that are not 
affected by, and that do not affect, the gasoline being sampled are 
acceptable.
    4.2  Container closure. Closure devices may be used as long as they 
meet the following test: The quality of closures and containers must be 
determined by the particular laboratory or company doing the testing 
through the analysis of at least six sample pairs of gasoline and 
gasoline-oxygenate blends. The six sample pairs must include at least 
one pair of ethanol at 10 percent and one pair of MTBE at 15 percent. 
The second half of the pair must be analyzed in a period of no less than 
90 days after the first. The data obtained must meet the following 
criteria and should be made available to the EPA upon request;
n=number of pairs
d=duplicate bottle's-initial bottle's vapor pressure
t=student t statistic; the double sided 95% confidence interval for n-1 
          degrees of freedom

 d/n(2)1/2 * t * (( d\2\-( 
          d)\2\/n)/(n-1))1/20.38 psi

    4.2.1  Screw caps must be protected by material that will not affect 
petroleum or petroleum products. A phenolic screw cap with a teflon 
coated liner may be used, since it has met the requirements of the above 
performance test upon EPA analysis.
    4.3 Cleaning procedure. The method of cleaning all sample containers 
must be consistent with the residual materials in the container and must 
produce sample containers that are clean and free of water, dirt, lint, 
washing compounds, naphtha or other solvents, soldering fluxes, and 
acids, corrosion, rust, and oil. New sample containers should be 
inspected and cleaned if necessary. Dry either the container by passing 
a current of clean, warm air through the container or by allowing it to 
air dry in a clean area at room temperature. When dry, stopper or cap 
the container immediately.

                         5. Sampling apparatus.

    5.1  Sampling apparatus is described in detail under each of the 
specific sampling procedures. Clean, dry, and free all sampling 
apparatus from any substance that might contaminate the material, using 
the procedure described in 4.3.

                     6. Time and place of sampling.

    6.1  When loading or discharging gasoline, take samples from both 
shipping and receiving tanks, and from the pipeline if required.
    6.2  Ship or barge tanks. Sample each product after the vessel is 
loaded or just before unloading.
    6.3  Tank cars. Sample the product after the car is loaded or just 
before unloading.
    Note: When taking samples from tanks suspected of containing 
flammable atmospheres, precautions should be taken to guard against 
ignitions due to static electricity. No object or material should be 
lowered into or suspended in a compartment of a tank which is being 
filled. A recommended waiting period of no less than five minutes after 
cessation of pumping will generally permit a substantial relaxation of 
the electrostatic charge for small volume vessels such as tank cars and 
tank trucks; under certain conditions a longer period may be deemed 
advisable. A recommended waiting period of no less than 30 minutes will 
generally permit a substantial relaxation of the electrostatic charge 
for large volume vessels such as storage tanks or ship tanks; under 
certain conditions a longer period may be deemed advisable.

                          7. Obtaining samples.

    7.1  Directions for sampling cannot be made explicit enough to cover 
all cases. Extreme care and good judgment are necessary to ensure 
samples that represent the general character and average condition of 
the material. Clean hands are important. Clean gloves may be worn but 
only when absolutely necessary, such as in cold weather, or when 
handling materials at high temperature, or for reasons of safety. Select 
wiping cloths so that lint is not introduced, contaminating samples.
    7.2  As many petroleum vapors are toxic and flammable, avoid 
breathing them or igniting them from an open flame or a spark produced 
by static. Follow all safety precautions specific to the material being 
sampled.
    7.3  When sampling relatively volatile products (more than 2 pounds 
(0.14 kgf/cm\2\) RVP), the sampling apparatus shall be filled and 
allowed to drain before drawing the sample. If the sample is to be 
transferred to another container, this container shall also be rinsed 
with some of the volatile product and then drained. When the actual 
sample is emptied into this container, the sampling

[[Page 644]]

apparatus should be upended into the opening of the sample container and 
remain in this position until the contents have been transferred so that 
no unsaturated air will be entrained in the transfer of the sample.

                          8. Handling samples.

    8.1  Volatile samples. It is necessary to protect all volatile 
samples of gasoline from evaporation. Transfer the product from the 
sampling apparatus to the sample container immediately. Keep the 
container closed except when the material is being transferred. After 
delivery to the laboratory, volatile samples should be cooled before the 
container is opened.
    8.2  Container outage. Never completely fill a sample container, but 
allow adequate room for expansion, taking into consideration the 
temperature of the liquid at the time of filling and the probable 
maximum temperature to which the filled container may be subjected.

                          9. Shipping samples.

    9.1  To prevent loss of liquid and vapors during shipment, and to 
protect against moisture and dust, cover the stoppers of glass bottles 
with plastic caps that have been swelled in water, wiped dry, placed 
over the tops of the stoppered bottles, and allowed to shrink tightly in 
place. The caps of metal containers must be screwed down tightly and 
checked for leakage. Postal and express office regulations applying to 
the shipment of flammable liquids must be observed.

                     10. Labeling sample containers.

    10.1 Label the container immediately after a sample is obtained. Use 
waterproof and oilproof ink, or a pencil hard enough to dent the tag, 
since soft pencil and ordinary ink markings are subject to obliteration 
from moisture, oil smearing and handling. An indelible identification 
symbol, such as a bar code, may be used in lieu of a manually addressed 
label. The label shall reference the following information:
    10.1.1  Date and time (the period elapsed during continuous 
sampling);
    10.1.2  Name of the sample;
    10.1.3  Name or number and owner of the vessel, car, or container;
    10.1.4--Brand and grade of material; and
    10.1.5--Reference symbol or identification number.

                        11. Sampling procedures.

    11.1  The standard sampling procedures described in this method are 
summarized in Table 1. Alternative sampling procedures may be used if a 
mutually satisfactory agreement has been reached by the party(ies) 
involved and EPA and such agreement has been put in writing and signed 
by authorized officials.
    11.2  Bottle or beaker sampling. The bottle or beaker sampling 
procedure is applicable for sampling liquids of 16 pounds (1.12 kgf/
cm\2\) RVP or less in tank cars, tank trucks, shore tanks, ship tanks, 
and barge tanks.
    11.2.1  Apparatus. A suitable sampling bottle or beaker as shown in 
Figure 2 is required. Recommended diameter of opening in the bottle or 
beaker is \3/4\ inch (19 mm).
    11.2.2  Procedure.
    11.2.2.1  All-levels sample. Lower the weighted, stoppered bottle or 
beaker as near as possible to the draw-off level, pull out the stopper 
with a sharp jerk of the cord or chain and raise the bottle at a uniform 
rate so that it is 70-85% full as it emerges from the liquid.
    11.2.2.2  Running sample. Lower the unstoppered bottle or beaker as 
near as possible to the level of the bottom of the outlet connection or 
swing line and then raise the bottle or beaker to the top of the 
gasoline at a uniform rate of speed such that it is 70-85% full when 
withdrawn from the gasoline.
    11.2.2.3  Upper, middle, and lower samples. Lower the weighted, 
stoppered bottle to the proper depths (Figure 1) as follows:


Upper sample..............................  middle of upper third of the
                                             tank contents              
Middle sample.............................  middle of the tank contents 
Lower sample..............................  level of the fixed tank     
                                             outlet or the swing-line   
                                             outlet                     
                                                                        

    At the selected level pull out the stopper with a sharp jerk of the 
cord or chain and allow the bottle or beaker to fill completely, as 
evidenced by the cessation of air bubbles. When full, raise the bottle 
or beaker, pour off a small amount, and stopper immediately.
    11.2.2.4  Top sample. Obtain this sample (Figure 1) in the same 
manner as specified in 11.2.2.3 but at six inches (150 mm) below the top 
surface of the tank contents.
    11.2.2.5  Handling. Stopper and label bottle samples immediately 
after taking them, and deliver to the laboratory in the original 
sampling bottles.
    11.3  Tap sampling. The tap sampling procedure is applicable for 
sampling liquids of twenty-six pounds (1.83 kgf/cm\2\) RVP or less in 
tanks which are equipped with suitable sampling taps or lines. This 
procedure is recommended for volatile stocks in tanks of the breather 
and balloon roof type, spheroids, etc. (Samples may be taken from the 
drain cocks of gage glasses, if the tank is not equipped with sampling 
taps.) The assembly for tap sampling is shown in Figure 3.
    11.3.1  Apparatus.
    11.3.1.1  Tank taps. The tank should be equipped with at least three 
sampling taps placed equidistant throughout the tank height and 
extending at least three feet (0.9

[[Page 645]]

meter) inside the tank shell. A standard \1/4\ inch pipe with suitable 
valve is satisfactory.
    11.3.1.2  Tube. A delivery tube that will not contaminate the 
product being sampled and long enough to reach to the bottom of the 
sample container is required to allow submerged filling.
    11.3.1.3  Sample containers. Use clean, dry glass bottles of 
convenient size and strength or metal containers to receive the samples.
    11.3.2  Procedure. Before a sample is drawn, flush the tap (or gage 
glass drain cock) and line until they are purged completely. Connect the 
clean delivery tube to the tap. Draw upper, middle, or lower samples 
directly from the respective taps after the flushing operation. Stopper 
and label the sample container immediately after filling, and deliver it 
to the laboratory.
    11.4  Continuous sampling. The continuous sampling procedure is 
applicable for sampling liquids of 16 pounds (1.12 kgf/cm\2\) RVP or 
less and semiliquids in pipelines, filling lines, and transfer lines. 
The continuous sampling may be done manually or by using automatic 
devices.
    11.4.1  Apparatus.
    11.4.1.1  Sampling probe. The function of the sampling probe is to 
withdraw from the flow stream a portion that will be representative of 
the entire stream. The apparatus assembly for continuous sampling is 
shown in Figure 4. Probe designs that are commonly used are as follows:
    11.4.1.1.1  A tube extending to the center of the line and beveled 
at a 45 degree angle facing upstream (Figure 4(a)).
    11.4.1.1.2  A long-radius forged elbow or pipe bend extending to the 
center line of the pipe and facing upstream. The end of the probe should 
be reamed to give a sharp entrance edge (Figure 4(b)).
    11.4.1.1.3  A closed-end tube with a round orifice spaced near the 
closed end which should be positioned in such a way that the orifice is 
in the center of the pipeline and is facing the stream as shown in 
Figure 4(c)).
    11.4.1.2  Probe location. Since the fluid to be sampled may not in 
all cases be homogeneous, the location, the position and the size of the 
sampling probe should be such as to minimize stratification or dropping 
out of heavier particles within the tube or the displacement of the 
product within the tube as a result of variation in gravity of the 
flowing stream. The sampling probe should be located preferably in a 
vertical run of pipe and as near as practicable to the point where the 
product passes to the receiver. The probe should always be in a 
horizontal position.
    11.4.1.2.1  The sampling lines should be as short as practicable and 
should be cleared before any samples are taken.
    11.4.1.2.2  Where adequate flowing velocity is not available, a 
suitable device for mixing the fluid flow to ensure a homogeneous 
mixture at all rates of flow and to eliminate stratification should be 
installed upstream of the sampling tap. Some effective devices for 
obtaining a homogeneous mixture are as follows: Reduction in pipe size; 
a series of baffles; orifice or perforated plate; and a combination of 
any of these methods.
    11.4.1.2.3  The design or sizing of these devices is optional with 
the user, as long as the flow past the sampling point is homogeneous and 
stratification is eliminated.
    11.4.1.3  To control the rate at which the sample is withdrawn, the 
probe or probes should be fitted with valves or plug cocks.
    11.4.1.4  Automatic sampling devices that meet the standards set out 
in 11.4.1.5 may be used in obtaining samples of gasoline. The quality of 
sample collected must be of sufficient size for analysis, and its 
composition should be identical with the composition of the batch 
flowing in the line while the sample is being taken. An automatic 
sampler installation necessarily includes not only the automatic 
sampling device that extracts the samples from the line, but also a 
suitable probe, connecting lines, auxiliary equipment, and a container 
in which the sample is collected. Automatic samplers may be classified 
as follows:
    11.4.1.4.1  Continuous sampler, time cycle (nonproportional) type. A 
sampler designed and operated in such a manner that it transfers equal 
increments of liquid from the pipeline to the sample container at a 
uniform rate of one or more increments per minute is a continuous 
sampler.
    11.4.1.4.2  Continuous sampler, flow-responsive (proportional) type. 
A sampler that is designed and operated in such a manner that it will 
automatically adjust the quantity of sample in proportion to the rate of 
flow is a flow-responsive (proportional) sampler. Adjustment of the 
quantity of sample may be made either by varying the frequency of 
transferring equal increments of sample to the sample container, or by 
varying the volume of the increments while maintaining a constant 
frequency of transferring the increments to the sample container. The 
apparatus assembly for continuous sampling is shown in Figure 4.
    11.4.1.4.3  Intermittent sampler. A sampler that is designed and 
operated in such a manner that it transfers equal increments of liquid 
from a pipeline to the sample container at a uniform rate of less than 
one increment per minute is an intermittent sampler.
    11.4.1.5  Standards of installation. Automatic sampler installations 
should meet all safety requirements in the plant or area where used, and 
should comply with American National Standard Code for Pressure Piping, 
and other applicable codes (ANSI B31.1). The sampler should be so 
installed as to provide ample access space for inspection and 
maintenance.

[[Page 646]]

    11.4.1.5.1  Small lines connecting various elements of the 
installation should be so arranged that complete purging of the 
automatic sampler and of all lines can be accomplished effectively. All 
fluid remaining in the sampler and the lines from the preceding sampling 
cycle should be purged immediately before the start of any given 
sampling operation.
    11.4.1.5.2  In those cases where the sampler design is such that 
complete purging of the sampling lines and the sampler is not possible, 
a small pump should be installed in order to circulate a continuous 
stream from the sampling tube past or through the sampler and back into 
the line. The automatic sampler should then withdraw the sample from the 
sidestream through the shortest possible connection.
    11.4.1.5.3  Under certain conditions, there may be a tendency for 
water and heavy particles to drop out in the discharge line from the 
sampling device and appear in the sample container during some 
subsequent sampling period. To circumvent this possibility, the 
discharge pipe from the sampling device should be free of pockets or 
enlarged pipe areas, and preferably should be pitched downward to the 
sample container.
    11.4.1.5.4  To ensure clean, free-flowing lines, piping should be 
designed for periodic cleaning.
    11.4.1.6  Field calibration. Composite samples obtained from the 
automatic sampler installation should be verified for quantity 
performance in a manner that meets with the approval of all parties 
concerned (including EPA), at least once a month and more often if 
conditions warrant. In the case of time-cycle samplers, deviations in 
quantity of the sample taken should not exceed  five percent 
for any given setting. In the case of flow-responsive samplers, the 
deviation in quantity of sample taken per 1,000 barrels of flowing 
stream should not exceed  five percent. For the purpose of 
field-calibrating an installation, the composite sample obtained from 
the automatic sampler under test should be verified for quality by 
comparing on the basis of physical and chemical properties, with either 
a properly secured continuous nonautomatic sample or tank sample. The 
tank sample should be taken under the following conditions:
    11.4.1.6.1  The batch pumped during the test interval should be 
diverted into a clean tank and a sample taken within one hour after 
cessation of pumping.
    11.4.1.6.2  If the sampling of the delivery tank is to be delayed 
beyond one hour, then the tank selected must be equipped with an 
adequate mixing means. For valid comparison, the sampling of the 
delivery tank must be completed within eight hours after cessation of 
pumping, even though the tank is equipped with a motor-driven mixer.
    11.4.1.6.3  When making a normal full-tank delivery from a tank, a 
properly secured sample may be used to check the results of the sampler 
if the parties (including EPA) mutually agree to this procedure.
    11.4.1.7  Receiver. The receiver must be a clean, dry container of 
convenient size to receive the sample. All connections from the sample 
probe to the sample container must be free of leaks. Two types of 
containers may be used, depending upon service requirements.
    11.4.1.7.1  Atmospheric container. The atmospheric container shall 
be constructed in such a way that it retards evaporation loss and 
protects the sample from extraneous material such as rain, snow, dust, 
and trash. The construction should allow cleaning, interior inspection, 
and complete mixing of the sample prior to removal. The container should 
be provided with a suitable vent.
    11.4.1.7.2  Closed container. The closed container shall be 
constructed in such a manner that it prevents evaporation loss. The 
construction must allow cleaning, interior inspection and complete 
mixing of the sample prior to removal. The container should be equipped 
with a pressure-relief valve.
    11.4.2  Procedure.
    11.4.2.1  Nonautomatic sample. Adjust the valve or plug cock from 
the sampling probe so that a steady stream is drawn from the probe. 
Whenever possible, the rate of sample withdrawal should be such that the 
velocity of liquid flowing through the probe is approximately equal to 
the average linear velocity of the stream flowing through the pipeline. 
Measure and record the rate of sample withdrawal as gallons per hour. 
Divert the sample stream to the sampling container continuously or 
intermittently to provide a quantity of sample that will be of 
sufficient size for analysis.
    11.4.2.2  Automatic sampling. Purge the sampler and the sampling 
lines immediately before the start of a sampling operation. If the 
sample design is such that complete purging is not possible, circulate a 
continuous stream from the probe past or through the sampler and back 
into the line. Withdraw the sample from the side stream through the 
automatic sampler using the shortest possible connections. Adjust the 
sampler to deliver not less than one and not more than 40 gallons (151 
liters) of sample during the desired sampling period. For time-cycle 
samplers, record the rate at which sample increments were taken per 
minute. For flow-responsive samplers, record the proportion of sample to 
total stream. Label the samples and deliver them to the laboratory in 
the containers in which they were collected.
    11.5  Nozzle sampling. The nozzle sampling procedure is applicable 
for sampling gasoline from a retail outlet or wholesale purchaser-
consumer facility storage tank.

[[Page 647]]

    11.5.1  Apparatus. Sample containers conforming with section 4.1 
should be used. A spacer, if appropriate (figure 6), and a nozzle 
extension device similar to that shown in figures 7, 7a, or 7b shall be 
used when nozzle sampling. The nozzle extension device does not need to 
be identical to that shown in figures 7, 7a, or 7b but it should be a 
device that will bottom fill the container with a minimum amount of 
vapor loss.
    11.5.2  Retail sampling procedure
    11.5.2.1  If a nozzle extension as found in figure 7 or 7a is used, 
3 gallons of gasoline should first be dispensed from the pump nozzle to 
purge the pump hose and nozzle. Then a small amount of product should be 
dispensed through the nozzle extension into the sample container to 
rinse the sample container. A pump nozzle spacer (figure 6) may be used 
if the pump is a vapor recovery type. Rinse the sample container and 
discard the waste product into an appropriate container. Insert the 
nozzle extension (figure 7 or 7a) into the sample container and insert 
the pump nozzle into the extension with slot over the air bleed hole 
(when using figure 7). Fill the sample container slowly through the 
nozzle extension to 70-85 percent full (figure 8). Remove the nozzle 
extension. Cap the sample container at once. Check for leaks. Discard 
the sample container and re-sample if leak occurs. If the sample 
container is leak tight, label the container and deliver it to the 
laboratory.
    11.5.2.2  If a nozzle extension as found in figure 7b is used, 3 
gallons of gasoline should first be dispensed from the pump nozzle to 
purge the pump hose and nozzle. Then screw a dry and dirt free 4 oz 
sample bottle container onto the bottle filling fixture. Insert the 
nozzle into the nozzle extension. Insert the discharge end of the 
modified nozzle extension into a gasoline safety can or into the filler 
neck of a vehicle. Obtain the sample by pumping at least 0.2 gallon 
through the sampler. Remove the sample bottle from the fixture. The 
sample must be 70-85 percent full. Cap the sample container at once. 
Check for leaks. Discard the sample container and re-sample if a leak 
occurs. If the sample container is leak tight, label the container and 
deliver it to the laboratory.

                12. Special Precautions and Instructions.

    12.1  Precautions. Vapor pressures are extremely sensitive to 
evaporation losses and to slight changes in composition. When obtaining, 
storing, or handling samples, observe the necessary precautions to 
ensure samples representative of the product and satisfactory for RVP 
tests. Official samples should be taken by, or under the immediate 
supervision of, a person of judgment, skill, and sampling experience. 
Never prepare composite samples for this test. Make certain that 
containers which are to be shipped by common carrier conform to 
applicable Interstate Commerce Commission, state, and local regulations. 
When flushing or purging lines or containers, observe the pertinent 
regulations and precautions against fire, explosion, and other hazards.
    12.2  Sample containers. For nozzle sampling, use containers of not 
less than 4 ounces (118 ml) nor more than two gallons (7.6 liters) 
capacity, of sufficient strength to withstand the pressure to which they 
may be subjected, and of a type that will permit replacement of the cap 
or stopper with suitable connections for the transfer of the sample to 
the gasoline chamber of the vapor pressure testing apparatus. For 
running or all-level sampling procedures, use containers of not less 
than one quart (0.9 liter) nor more than two gallons (7.6 liters) 
capacity. Open-type containers have a single opening which permits 
sampling by immersion. Closed-type containers have two openings, one in 
each end (or the equivalent thereof), fitted with valves suitable for 
sampling by purging.
    12.3  Transfer connections. The transfer connection for the open-
type container consists of an air tube and a liquid delivery tube 
assembled in a cap or stopper. The air tube extends to the bottom of the 
container. One end of the liquid delivery tube is flush with the inside 
face of the cap or stopper and the tube is long enough to reach the 
bottom of the gasoline chamber while the sample is being transferred to 
the chamber. The transfer connection for the closed-type container 
consists of a single tube with a connection suitable for attaching it to 
one of the openings of the sample container. The tube is long enough to 
reach the bottom of the gasoline chamber while the sample is being 
transferred.
    12.4  Sampling open tanks. Use clean containers of the open type 
when sampling open tanks and tank cars. An all-levels or a running 
sample obtained by the bottle procedure described in 11.2 is 
recommended. When the question exists of stratification of the contents 
of the tank, it is recommended that either a running or all-levels 
sample be taken along with upper, middle, and lower spot sampling. 
Before taking the sample, flush the container by immersing it in the 
product to be sampled. Then obtain the sample immediately. The sample 
must be 70-85 percent full. Close the container promptly and confirm it 
is not leaking. Label the container and deliver it to the laboratory.
    12.5.  Sampling closed tanks. Containers of the closed type may be 
used to obtain samples from closed or pressure tanks. Obtain the sample 
using the purging procedure described in 12.6.
    12.6  Purging procedure. Connect the inlet valve of the closed-type 
container to the tank sampling tap or valve. Throttle the outlet valve 
of the container so that the pressure in it will be approximately equal 
to that in the container being sampled. Allow a

[[Page 648]]

volume of product equal to at least twice that of the container to flow 
through the sampling system. Then close all valves, the outlet valve 
first, the inlet valve of the container second, and the tank sampling 
valve last, and disconnect the container immediately. Withdraw enough of 
the contents so that the sample container will be 70-80 percent full. If 
the vapor pressure of the product is not high enough to force liquid 
from the container, open both the upper and lower valves slightly to 
remove the excess. Promptly seal and label the container, and deliver it 
to the laboratory.

    Table 1--Summary of Gasoline Sampling Procedures and Applicability  
------------------------------------------------------------------------
        Type of container              Procedure           Paragraph    
------------------------------------------------------------------------
Storage tanks, ship and barge     Bottle sampling....  11.2             
 tanks, tank cars, tank trucks.                                         
Storage tanks with taps.........  Tap sampling.......  11.3             
Pipes and lines.................  Continuous line      11.4             
                                   sampling.                            
Retail outlet and whole-sale      Nozzle sampling....  11.5             
 purchaser-consumer facility                                            
 storage tanks.                                                         
------------------------------------------------------------------------

      

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[GRAPHIC] [TIFF OMITTED] TC01SE92.147



[54 FR 11886, Mar. 22, 1989; 54 FR 27017, June 27, 1989, as amended at 
55 FR 25835, June 25, 1990; 58 FR 14485, Mar. 17, 1993; 58 FR 19152, 
Apr. 12, 1993]

[[Page 657]]

Appendix E to Part 80--Test for Determining Reid Vapor Pressure (RVP) of 
                 Gasoline and Gasoline-Oxygenate Blends

                   Method 3--Evacuated Chamber Method

                                1. Scope.

    1.1  This method covers the determination of the absolute pressure, 
measured against a vacuum of a gasoline or gasoline-oxygenate blend 
sample saturated with air at 32-40  deg.F (0-4.5  deg.C). The absolute 
(measured) pressure is observed with a system volume ratio of 1 part 
sample and 4 parts evacuated space at 100  deg.F (37.8  deg.C).
    1.2  The values stated in pounds per square inch absolute are 
standard.

                          2. Summary of method.

    2.1  A known volume of air-saturated fuel at 32-40  deg.F is 
introduced into an evacuated, thermostatically controlled test chamber, 
the internal volume of which is or becomes five times that of the total 
test specimen introduced into the test chamber. After the injection the 
test specimen is allowed to reach thermal equilibrium at the test 
temperature, 100  deg.F (37.8  deg.C). The resulting pressure increase 
is measured with an absolute pressure measuring device whose volume is 
included in the total of the test chamber volume. The measured pressure 
is the sum of the partial pressures of the sample and the dissolved air.
    2.2  The total measured pressure is converted to Reid vapor pressure 
by use of a correlation equation (see Section 9).

                              3. Apparatus.

    3.1  The apparatus shall employ a thermostatically controlled test 
chamber which is capable of maintaining a vapor-to-liquid ratio between 
3.95 and 4.05 to 1.00.
    3.2  The pressure measurement device shall have a minimum operation 
range from 0 to 15 psia (0 to 103 kPa) with a minimum resolution of 0.05 
psia (0.34 kPa). The pressure measurement device shall include any 
necessary electronic and readout devices to display the resulting 
reading.
    3.3  The test chamber shall be maintained at 1000.2  
deg.F (37.80.1  deg.C) for the duration of the test except 
for the time period after sample injection when the sample is coming to 
equilibrium with test temperature of 1000.2  deg.F 
(37.80.1  deg.C).
    3.4  A thermometer that meets the specification ASTM 18 F (18 C) or 
a platinum resistance thermometer shall be used for measuring the 
temperature of the test chamber. The minimum resolution for the 
temperature measurement device is 0.2  deg.F (0.1  deg.C) and an 
accuracy of 0.2  deg.F (0.1  deg.C).
    3.5  The vapor pressure apparatus shall have a provision for the 
introduction of the test specimen into the evacuated or to be evacuated 
test chamber and for the cleaning or purging of the chamber following 
the test.
    3.6  If a vacuum pump is used, it must be capable of reducing the 
pressure in the test chamber to less than 0.01 psia (0.07 kPa). If the 
apparatus uses a piston to induce a vacuum in the sample chamber the 
residual pressure shall be no greater than 0.01 psia (0.07 kPa) upon 
full expansion of the test chamber devoid of any material at 
1000.2  deg.F (37.80.1  deg.C).
    3.7  Ice water or air bath for chilling the sample to a temperature 
between 32-40  deg.F (0-4.5  deg.C).
    3.8  Mercury barometer, 0 to 17.4 psia (0 to 120 kPa) range.
    3.9  McLeod vacuum gauge, to cover at least the range of 0 to 5 mm 
Hg (0 to 0.67 kPa). Calibration of the McLeod gauge is checked as in 
accordance with Annex A6 of ASTM test Method D 2892-84, (Standard test 
method for distillation of Crude Petroleum (15-Theoretical Plate 
Column)). ASTM D-2892-84 is incorporated by reference. This 
incorporation by reference was approved by the Director of the Federal 
Register in accordance with 5 U.S.C 552(a) and 1 CFR part 51. Copies may 
be obtained from the American Society for Testing and Materials, 1916 
Race St., Philadelphia, PA 19103. Copies may be inspected at the U.S. 
Environmental Protection Agency, Air Docket Section, room M-1500, 401 M 
Street, SW., Washington, DC 20460 or at the Office of the Federal 
Register, 800 North Capitol Street, NW., Washington, DC.

                       4. Reagents and materials.

    4.1  Quality control standards. Use chemicals of at least 99% purity 
for quality control standards. Unless otherwise indicated, it is 
intended that all reagents conform to the specifications of the 
committee on Analytical Reagents of the American Chemical Society where 
such specifications are available (see section 7.3). Specifications for 
analytical reagents may be obtained from the American Chemical Society, 
1155 16th Street, NW., Washington, DC 20036.
    4.1.1  2,2,4-trimethylpentane
    4.1.2  2,2-dimethylbutane
    4.1.3  3-methylpentane
    4.1.4  n-pentane
    4.1.5  acetone
    4.2  n-pentane  (commercial grade-95% pure)

                         5. Handling of samples.

    5.1  The sensitivity of vapor pressure measurements to losses 
through evaporation and the resulting change in composition is such as 
to require the utmost precaution in the handling of samples. The 
provisions of this section apply to all samples for vapor pressure 
determinations.

[[Page 658]]

    5.2  Sample in accordance with 40 CFR part 80, appendix D.
    5.3  Sample container size. The minimum size of the sample container 
from which the vapor pressure sample is taken is 4 ounces (118 ml). It 
will be 70 to 85% filled with sample.
    5.4  Precautions.
    5.4.1  Determine vapor pressure as the first test on a sample. 
Multiple analyses may be performed, but must be evaluated given the 
stated precision for the size of the sample container, and the order in 
which they were run in relation to the initial analysis.
    5.4.2  Protect samples from excessive heat prior to testing.
    5.4.3  Leaking samples should be replaced if possible. Analysis 
results from leaking sample containers must be marked as such.
    5.4.4  Samples that have separated into two phases should be 
replaced if possible. Analysis results from samples that have phase 
separated must be marked as such.
    5.4.5  Sample handling temperature. In all cases, cool the sample to 
a temperature of 32-40 deg. F (0-4.5 deg. C) before the container is 
opened. To ensure sufficient time to reach this temperature, directly 
measure the temperature of a similar liquid at a similar initial 
temperature in a like container placed in the cooling bath at the same 
time as the sample.

                        6. Preparation for test.

    6.1  Verification of sample container filling. With the sample at a 
temperature of 32-40  deg.F (0-4.5  deg.C), take the container from the 
cooling bath, wipe dry with an absorbent material, unseal it, and 
examine its ullage. The sample content, as determined by use of a 
suitable gauge, should be equal to 70 to 85 volume % of the container 
capacity.
    6.1.1  Analysis results from samples that contain less than 70 
volume % of the container capacity must be marked as such.
    6.1.2  If the container is more than 85 volume % full, pour out 
enough sample to bring the container contents within the 70 to 85 volume 
% range. Under no circumstance may any sample poured out be returned to 
the container.
    6.2  Air saturation of the sample in the sample container. With the 
sample at a temperature of 32-40  deg.F (0-4.5  deg.C), take the 
container from the cooling bath, wipe dry with an absorbent material, 
unseal it momentarily, taking care to prevent water entry, re-seal it, 
and shake it vigorously. Return it to the bath for a minimum of 2 
minutes. Repeat the air introduction procedure twice, for a total of 
three air introductions to completely saturate the sample.
    6.3  Prepare the instrument for operation in accordance with the 
manufacturer's instructions.
    6.3.1  Instruments with vacuum pumps. Clean and dry the test chamber 
as required to obtain a sealed test chamber pressure of less than 0.01 
psi (0.07 kPa) for 1 minute. If the pressure exceeds this value check 
for and resolve in the following order; residual sample or cleaning 
solvent, sample chamber leaks, and transducer calibration.
    6.3.2  Instruments without vacuum pumps. The sample purges the 
sample chamber through a series of rinses before the analysis occurs. 
Errors due to leaks in the plunger, piston seals, or carryover from 
previous samples or standards may give erratic results (see Note of 
section 6.3.2). The operator must run a quality control standard for at 
least one in twenty analyses or once a day to determine if there is 
carryover from previous analyses or if leaks are occurring.

    Note: When using a self cleaning apparatus some residual product may 
be carried over into subsequent analyses. Carryover effect should be 
investigated when conducting sequential analyses of dissimilar 
materials, especially calibration standards. Inaccuracies caused by 
carryover effect should be resolved using testing procedures designed to 
minimize such interferences.

    6.4  If a syringe is used for the physical introduction of the 
sample specimen, it must be either clean and dry before it is used or it 
may be rinsed out at least three times with the sample. When cleaning 
the syringe, the rinse may not be returned to the sample container. The 
syringe must be capable of obtaining, upon filling with the sample 
charge, a quantity of sample that has an entrained gas volume of less 
than 3% of the necessary sample volume.

                             7. Calibration.

    7.1  Pressure measurement device.
    7.1.1  Check the calibration of the pressure measurement device 
daily or until the stability of the device is documented as having less 
than or equal to 0.03 psi (0.2 kPa) drift per unit of the appropriate 
calibration period. When calibration is necessary, follow the procedures 
in sections 7.1.2 through 7.1.4.
    7.1.2  Connect a properly calibrated McLeod gauge to the vacuum 
source line to the test chamber. Apply vacuum to the test chamber. When 
the McLeod gauge registers a pressure less than 0.8 mm Hg (0.1 kPa) 
adjust the pressure measurement device's zero control to match to within 
0.01 psi (0.07 kPa) of the McLeod Gauge.
    7.1.3  Open the test chamber to the atmosphere and observe the 
pressure measurement device's reading. Adjust the pressure measurement 
devices span control to within 0.01 psi (0.07 kPa) of a 
temperature and latitude adjusted mercury barometer.
    7.1.4  Repeat steps 7.1.2 and 7.1.3 until the instrument zero and 
barometer readings read correctly without further adjustments.
    7.2  Thermometer. Check the calibration of the ASTM 18 F (18 C) 
thermometer or the

[[Page 659]]

platinum resistance thermometer used to monitor the test chamber at 
least every six months in accordance ASTM E1-86, (Standard Specification 
for ASTM Thermometers). ASTM E1-86 is incorporated by reference. This 
incorporation by reference was approved by the Director of the Federal 
Register in accordance with 5 U.S.C. 552(a) and 1 CFR part 51. Copies 
may be obtained from the American Society for Testing and Materials, 
1916 Race St., Philadelphia, PA 19103. Copies may be inspected at the 
U.S. Environmental Protection Agency, Air Docket Section, room M-1500, 
401 M Street, SW., Washington, DC 20460 or at the Office of the Federal 
Register, 800 North Capitol Street, NW., Washington, DC. Check the 
reading of the thermometer against a National Institute of Standards and 
Technology traceable thermometer.
    7.3  Quality assurance. The instrument's performance must be checked 
at least once per day using a quality control standard listed in section 
4.1. In the case of the non-vacuum pump instruments the frequency is 
stated in section 6.3.2. The standards must be chilled to the same 
temperature, have the same ullage, and saturated with air in the same 
manner as the samples. Record total measured pressure and compare 
against the following reference values:

----------------------------------------------------------------------------------------------------------------
               Compound                    Lower control limit                   Upper control limit            
----------------------------------------------------------------------------------------------------------------
2,2,4-trimethylpentane...............  2.39 psia (16.5 kpa).......  3.03 psi (20.9 kpa)                         
3-methylpentane......................  6.86 psia (47.3 kpa).......  7.26 psi (50.1 kpa)                         
acetone..............................  7.97 psia (55.0 kpa).......  8.12 psi (56.0 kpa)                         
2,2-dimethylbutane...................  10.64 psia (73.4 kpa)......  10.93 psi (75.4 kpa)                        
n-pentane............................  16.20 psia (111.7 kpa).....  16.40 psi (113.1 kpa)                       
----------------------------------------------------------------------------------------------------------------

  
    If the observed pressure does not fall between the reference values, 
check the instrument for leaks and its calibration (Section 7).
    7.3.1  Other compounds, gasolines, and gasoline blends may be used 
as control standards as long as these materials have been statistically 
evaluated for their mean total measured pressure using an instrument 
that conforms to this procedure.
    7.3.2  The control limits can be calculated with the following 
formula:

                         Mean measured pressure
[GRAPHIC] [TIFF OMITTED] TC01SE92.148

  

                           Standard Deviation
[GRAPHIC] [TIFF OMITTED] TC01SE92.149

  ......................................................................

                        Upper Control Limit (UCL)

  UCL=X+(tn-1,0.975) * (Sx)

                        Lower Control Limit (LCL)

  LCL=X-(tn-1,0.975) * (Sx)

    where: xi is the individual analyses of the control standard, n 
is the number of analyses (for a new instrument or a new control 
standard this should be at least ten analyses); (tn-1,0.975) is the 
two-tailed student t statistic for n-1 degrees of freedom for 95% of the 
expected data from the analysis of the standard.

                              8. Procedure.

    8.1  Remove the sample from the cooling bath or refrigerator, dry 
the exterior of the container with absorbent material, unseal, and 
insert the transfer tube, syringe, or transfer connection (see section 
6). Draw an aliquot (minimize gas bubbles) of sample into a gas tight 
syringe or transfer the sample using tubing or transfer connection and 
deliver this test specimen to the test chamber as rapidly as possible. 
The total time between opening the chilled sample container and 
inserting/securing the syringe or transfer connection into the sealed 
test chamber shall not exceed one minute.
    8.2  Follow the manufacturer's instructions for injection of the 
test specimen into the test chamber, and for the operation of the 
instrument to obtain a total measured vapor pressure result for the test 
specimen.
    8.3  Set the instrument to read the test results in terms of total 
measured pressure. If the instrument is capable of calculating a Reid 
Vapor Pressure equivalent value ensure that only the parameters in 
section 9.2 are used.

[[Page 660]]

                  9. Calculation and record of result.

    9.1  Note the total measured vapor pressure reading for the 
instrument to the nearest 0.01 psi (0.07 kPa). For instruments which do 
not automatically display a stable pressure value, manually note the 
pressure indicator reading every minute to the nearest 0.01 psi (0.07 
kPa). When three successive readings agree to within 0.01 psia (0.07 
kPa) note the final result to the nearest 0.01 psia (0.07 kPa).
    9.2  Using the following correlation equation, calculate the Reid 
Vapor Pressure (RVP) that is equivalent to the total measured vapor 
pressure obtained from the instrument, in order to compare the vapor 
pressure standards set out in 40 CFR 80.27. Ensure that the instrument 
reading in this equation corresponds to the total measured pressure and 
has not been corrected by an automatically programmed correction factor.

RVP psi=(0.956 * X)-0.347
RVP kPa=(0.956 * X)-2.39
where: X=total measured vapor pressure in psi or kPa

    9.3  Record the RVP to the nearest 0.01 psi (0.07 kPa) as the 
official test result.
    9.4  EPA will use the above method as the official vapor pressure 
test method. EPA will recognize correlations from regulated parties if 
the correlations are established directly with EPA's test laboratory. 
Any test method may be used for defense as long as adequate correlation 
is demonstrated to this method (i.e., any vapor pressure defense test 
method could be used if adequate correlation exists directly to this 
method, which can then be converted to Reid Vapor Pressure by use of the 
EPA Grabner correlation equation in section 9.2 of this method).

[58 FR 14488, Mar. 17, 1993]

 Appendix F to Part 80--Test for Determining the Quantity of Alcohol in 
                                Gasoline

                    Method 1--Water Extraction Method

    1. Scope.
    This test method covers the determination of the type and amount of 
alcohols in gasoline.
    2. Summary of method.
    Gasoline samples are extracted with water prior to analysis on a gas 
chromatograph (GC). The extraction eliminates hydrocarbon interference 
during chromatography. A known quantity of isopropanol is added to the 
fuel prior to extraction to act as an internal standard.
    3. Sample description.
    3.1  Sample in accordance with 40 CFR part 80, appendix D.
    3.2  At least 100 ml. of gasoline suspected of containing ethanol 
and/or methanol are required.
    4. Apparatus.
    4.1  Gas chromatograph--A gas chromatograph equipped with a flame 
ionization detector.
    4.2  Column--A gas chromatograph column, glass, 1800 by 6.35 cm. 
outside diameter, packed with chromosorb 102.
    4.3  Recorder--A 1-mv recorder with a 1 second full scale response 
and a chart speed of 10 mm. per minute (0.4 inches per minute).
    4.4  Syringe (100 ul.) for adding the internal standard.
    4.5  Pipet.
    4.6  Injection syringe (10 ul.).
    4.7  Extraction syringe (1-5 ml.) with 3-inch needle.
    4.8  250 ml. (\1/2\ pint) glass sample bottles with screw caps or 
equivalent.
    4.9  Calibration standard solutions extracted from gasoline 
containing known quantities of alcohols.
    4.10  Reference standard solutions extracted from gasoline 
containing known quantities of alcohols.
    4.11  Distilled water.
    4.12  Reagent grade isopropanol.
    4.13  Rubber gloves.
    4.14  I.D. tags.
    5. Precautions.

    Note 1: Gasoline and alcohols are extremely flammable and may be 
toxic over prolonged exposure. Methanol is particularly hazardous. 
Persons performing this procedure must be familiar with the chemicals 
involved and all precautions applicable to each.

    5.1  Extractions and dilutions must be performed in well-ventilated 
areas, preferably under a fume hood, away from open flames and sparks.
    5.2  Rubber gloves must be worn during the handling of gasoline and 
alcohols.
    5.3  Avoid breathing fumes from gasoline and alcohols, particularly 
methanol.
    5.4  Gas cylinders must be properly secured and the hydrogen FID 
fuel must be segregated from the compressed air (oxidizer) tank.
    6. Visual inspection.
    6.1  Ensure that the samples do not certain sediment or separated 
phases prior to extraction.
    6.2  Ensure adequate quantities of GC supply gases to maintain a 
run.
    7. Test article preparation.
    7.1  Gas chromatography--Use carrier gas, flow rates, detector and 
injection temperatures and column as specified in the GC manufacturer's 
specifications.
    7.2  Sample extraction, preparation and analysis.
    7.2.1  Label two 6 ml. vials with the sample identification number 
supplied with the 

[[Page 661]]

original sample. The estimated percent alcohol from any screening tests 
must also be included on the label.
    7.2.2  Pipet 4 ml.0.01 ml. of sample into one of the 
vials. Label as vial 1.
    7.2.3  Measure 100 ul. (0.1 ml.)0.5 ul. of isopropanol 
into vial 1.

    Note: This adds an internal standard to the sample which is required 
for accurate analysis.

    7.2.4  Add 1 ml.0.2 ml. of distilled water to the 
gasoline sample in vial 1 and shake for 10 seconds.
    7.2.5  Allow the mixture to separate into two phases (at least 5 
minutes).
    7.2.6  Carefully draw off the aqueous (lower) phase using a 5 ml. 
syringe and long needle.

    Note: Be careful not to allow any of the gasoline phase to get into 
the needle. Leave a small amount (approximately 0.2 ml.) of the aqueous 
phase in the vial.

    7.2.7  Transfer the aqueous phase into the other 6 ml. vial (vial 
2).
    7.2.8  Repeat steps 7.2.4 to 7.2.6 two more times.
    7.2.9  Fill vial 2 (the aqueous phase) to 4 ml.0.05 ml. 
with distilled water.
    7.2.10  Retain the remaining original gasoline sample (not the 
gasoline phase).
    7.2.11  Discard the extracted gasoline phase in vial 1 in an 
appropriate manner.
    7.2.12  Perform a second extraction on one sample in every 20. This 
sample is to be labeled with the sample number and as a duplicate and 
run as a normal sample.
    7.2.13  Transfer approximately 2 ml. of the aqueous solution to 
vials compatible with the autosampler. Tag the vial with the sample 
number.
    7.2.14  Perform analysis of the sample according to the GC 
manufacturer's specifications.
    7.3  Standards.
    7.3.1  Calibration standard solutions (made in gasoline).
    7.3.1.1  Reagent grade or better alcohols (including undenatured 
ethanol) are to be diluted with regular unleaded gasoline. The 
isopropanol internal standard is to be added during extraction of the 
alcohols. Newly acquired stocks of reagent grade alcohols shall be 
diluted to 10% with hydrocarbon-free water and analyzed for 
contamination by GC before use.
    7.3.1.2  Required calibration standards (% by volume in gasoline):

------------------------------------------------------------------------
                                                      Range     Standard
                      Alcohol                       (percent)    (MIN)  
------------------------------------------------------------------------
Methanol..........................................     0.5-12          5
Ethanol...........................................     0.5-11          5
------------------------------------------------------------------------

    The standards should be as equally spaced within the range as 
possible and may contain more than one alcohol.

    Note: Level 1 must contain all of the alcohols.

    8. Quality control provisions.
    8.1  Alcohol(s) in water solution may be used to characterize the 
GC. The resulting characterization always reflects the absolute 
sensitivity of the instrument to each alcohol.
    8.2  Calibration standards are made by extraction of known 
alcohol(s) in gasoline blends. These standards account for inaccuracies 
caused by incomplete extraction of alcohols.
    8.3  The addition of isopropanol as an internal standard reduces 
errors caused by variations in injection volumes, and further reduces 
inaccuracies caused by incomplete extraction of alcohols.
    8.4  Sufficient sample should be retained to permit reanalysis.
    8.5  Running averages of reference standards data must not exceed 
0.75% of applicable limits or investigation should be started for the 
cause of such variation.
    9. Calculations.
    9.1  Calculate purity of component as follows:

                                                                        
                             Ai                                         
     Pi         =    -----------------  expressed as a decimal fraction,
                         A              that is 0.999          
                                                                        

where:

Pi=purity of component i,
Ai=area of response of component i, and
A=total area response of all components.

    9.2  Calculate response factors as follows:

                                                                        
                                                   Ais x Wi x Pi        
          Fi                    =         ------------------------------
                                                   Ai x Wis x Pis       
                                                                        

where:

Fi=response factor for component of interest i,
Ai=area response for component of interest i,
Ais=area response of internal standard,
Wi=weight of component of interest i (be sure to consider all 
          sources),
Wis=weight of internal standard,
Pi=purity of component of interest i as determined in 9.1 expressed 
          as a decimal, and
Pis=purity of internal standards as determined in 9.1 expressed as 
          a decimal.

    9.3  Calculate the percent alcohols as follows:

[[Page 662]]



                                                                        
              Wis x Ai x Fi                                             
  Ci    =  ------------------    x 100=        weight % component i     
                Wi x Ais                                                
                                                                        

where:

Ai=peak area component i,
Ais=peak area of internal standard,
Wi=weight of sample,
Wis=weight of internal standard, and
Fi=response factor for component i.

    10. Report.
    10.1  Report results to the nearest 0.1%.
    11. Precision and accuracy.
    11.1  Precision--The precision of this test method has not been 
determined.
    11.2  Accuracy--The accuracy of this test method has not been 
determined.

 Method 2--Test Method for Determination of C1 to C4 Alcohols 
               and MTBE in Gasoline by Gas Chromatography

    1. Scope.
    1.1  This test method covers a procedure for determination of 
methanol, ethanol, isopropanol, n-propanol, isobutanol, sec-butanol, 
tert-butanol, n-butanol, and methyl tertiary butyl ether (MTBE) in 
gasoline by gas chromatography.
    1.2  Individual alcohols and MTBE are determined from 0.1 to 10 
volume %. Any sample found to contain greater than 10 volume % of an 
alcohol or MTBE shall be diluted to concentrations within these limits.
    1.3  Sl (metric) units of measurement are preferred and used 
throughout this standard. Alternative units, in common usage, are also 
provided to improve the clarity and aid the user of this test method.
    1.4  This standard may involve hazardous materials, operations, and 
equipment. This standard does not purport to address all of the safety 
problems associated with its use. It is the responsibility of the user 
of this standard to establish appropriate safety and health practices 
and determine the applicability of regulatory limitations prior to use.
    2. Referenced documents.
    2.1  ASTM Standards:

D  4307  Practice for Preparation of Liquid Blends for Use as Analytical 
Standards \1\
---------------------------------------------------------------------------

    \1\ Annual Book of ASTM Standards, Vol. 05.03.
---------------------------------------------------------------------------

D  4626  Practice for Calculation of Gas Chromatographic Response 
Factors \1\
E  260  Practice for Packed Column Gas Chromatographic Procedures \2\
---------------------------------------------------------------------------

    \2\ Annual Book of ASTM Standards, Vol. 14.01.
---------------------------------------------------------------------------

E  355  Practice for Gas Chromatography Terms and Relationships \2\

    2.2  EPA Regulations:

                        40 CFR Part 80 Appendix D

    3. Descriptions of terms specific to this standard.
    3.1  MTBE--methyl tertiary butyl ether.
    3.2  Low volume connector--a special union for connecting two 
lengths of tubing 1.6 mm inside diameter and smaller. Sometimes this is 
referred to as a zero dead volume union.
    3.3  Oxygenates--used to designate fuel blending components 
containing oxygen, either in the form of alcohol or ether.
    3.4  Split ratio--a term used in gas chromatography using capillary 
columns. The split ratio is the ratio of the total flow of the carrier 
gas to the sample inlet versus the flow of carrier gas to the capillary 
column. Typical values range from 10:1 to 500:1 depending upon the 
amount of sample injected and the type of capillary column used.
    3.5  WCOT--abbreviation for a type of capillary column used in gas 
chromatography that is wall-coated open tubular. This type of column is 
prepared by coating the inside of the capillary with a thin film of 
stationary phase.
    3.6  TCEP--1,2,3,-tris-2-cyanoethoxypropane--a gas chromatographic 
liquid phase.
    4. Summary of test method.
    4.1  An internal standard, tertiary amyl alcohol, is added to the 
sample which is then introduced into a gas chromatograph equipped with 
two columns and a column switching valve. The sample first passes onto a 
polar TCEP column which elutes lighter hydrocarbons to vent and retains 
the oxygenated and heavier hydrocarbons. After methylcyclopentane, but 
before MTBE elutes from the polar column, the valve is switched to 
backflush the oxygenates onto a WCOT non-polar column. The alcohols and 
MTBE elute from the non-polar column in boiling point order, before 
elution of any major hydrocarbon constituents. After benzene elutes from 
the non-polar column, the column switching valve is switched back to its 
original position to backflush the heavy hydrocarbons. The eluted 
components are detected by a flame ionization or thermal conductivity 
detector. The detector response, proportional to the component 
concentration, is recorded; the peak areas are measured; and the 
concentration of each component is calculated with reference to the 
internal standard.
    5. Significance and use.
    5.1  Alcohols and other oxygenates may be added to gasoline to 
increase the octane number. Type and concentration of various 

[[Page 663]]

oxygenates are specified and regulated to ensure acceptable commercial 
gasoline quality. Drivability, vapor pressure, phase separation, and 
evaporative emissions are some of the concerns associated with 
oxygenated fuels.
    5.2  This test method is applicable to both quality control in the 
production of gasoline and for the determination of deliberate or 
extraneous oxygenate additions or contamination.
    6. Apparatus.
    6.1  Chromatograph:
    6.1.1  A gas chromatographic instrument which can be operated at the 
conditions given in Table 1, and having a column switching and 
backflushing system equivalent to Fig. 1. Carrier gas flow controllers 
shall be capable of precise control where the required flow rates are 
low (Table 1). Pressure control devices and gages shall be capable of 
precise control for the typical pressures required.

                                   Table 1--Chromatographic Operating Conditions                                
----------------------------------------------------------------------------------------------------------------
                                                                      Other parameters:                         
           Temperatures                      Flows, mL/min           Carrier gas, helium                        
----------------------------------------------------------------------------------------------------------------
Column oven,  deg.C...............   60  To injector.........  75  Sample size, L  3                   
Injector,  deg.C..................  200  Column..............   5  Split ratio............  15 : 1              
Detector--TCD,  deg.C.............  200  Auxiliary...........   3  Backflush, min.........  0.2-0.3             
    FID,  deg.C...................  250  Makeup..............  18  Valve reset time, min..  8-10                
Valve,  deg.C.....................   60                            Total analysis time,     18-20               
                                                                    min.                                        
----------------------------------------------------------------------------------------------------------------

    6.1.2  Detector--A thermal conductivity detector or flame ionization 
detector may be used. The system shall have sufficient sensitivity and 
stability to obtain a recorded deflection of at least 2 mm at a signal-
to-noise ratio of at least 5 to 1 for 0.005 volume % concentration of an 
oxygenate.
    6.1.3  Switching and backflushing valve--A valve, to be located 
within the gas chromatographic column oven, capable of performing the 
functions described in Section 11. and illustrated in Fig. 1. The valve 
shall be of low volume design and not contribute significantly to 
chromatographic deterioration.
    6.1.3.1  Valco Model No. CM-VSV-10-HT, 1.6-mm (\1/16\-in.) fittings. 
This particular valve was used in the majority of the analyses used for 
the development of Section 15.
    6.1.3.2  Valco Model No. C10W, 0.8-mm (\1/32\-in.) fittings. This 
valve is recommended for use with columns of 0.32-mm inside diameter and 
smaller.
    6.1.4  Although not mandatory, an automatic valve switching device 
is strongly recommended to ensure repeatable switching times. Such a 
device should be synchronized with injection and data collection times. 
If no such device is available, a stopwatch, started at the time of 
injection, should be used to indicate the proper valve switching time.
    6.1.5  Injection system--The chromatograph should be equipped with a 
splitting-type inlet device. Split injection is necessary to maintain 
the actual chromatographed sample size within the limits of column and 
detector optimum efficiency and linearity.
    6.1.6  Sample introduction--Any system capable of introducing a 
representative sample into the split inlet device. Microlitre syringes, 
automatic syringe injectors, and liquid sampling valves have been used 
successfully.
    6.2  Data presentation or calculation, or both:
     6.2.1  Recorder--A recording potentiometer or equivalent with a 
full-scale deflection of 5 mV or less. Full-scale response time should 
be l s or less with sufficient sensitivity and stability to meet the 
requirements of 6.1.2.
    6.2.2  Integrator or computer--Devices capable of meeting the 
requirements of 6.1.2, and providing graphic and digital presentation of 
the chromatographic data, are recommended for use. Means shall be 
provided for determining the detector response. Peak heights or areas 
can be measured by computer, electronic integration or manual 
techniques.
    6.3  Columns, two as follows:
    6.3.1  Polar column--This column performs a preseparation of the 
oxygenates from volatile hydrocarbons in the same boiling point range. 
The oxygenates and remaining hydrocarbons are backflushed onto the non-
polar column in section 6.3.2. Any column with equivalent or better 
chromatographic efficiency and selectivity to that described in 6.3.1.1 
can be used. The column shall perform at the same temperature as 
required for the column in 6.3.2.
    6.3.1.1  TCEP micro-packed column, 560 mm (22 in.) by 1.6-mm (\1/
16\-in.) outside diameter by 0.38-mm (0.015-in.) inside diameter 
stainless steel tube packed with 0.14 to 0.15g of 20% (mass/mass) TCEP 
on 80/100 mesh Chromosorb P(AW). This column was used in the (ASTM) 
cooperative study to provide the Precision and Bias data referred to in 
Section 15.
    6.3.2  Non-polar (analytical) column--Any column with equivalent or 
better chromatographic efficiency and selectivity to that described in 
6.3.2.1 and illustrated in Fig. 2 can be used.

[[Page 664]]

    6.3.2.1  WCOT methyl silicone column, 30m (1181 in.) long by 0.53 mm 
(0.021-in.) inside diameter fused silica WCOT column with a 2.6-
m film thickness of cross-linked methyl siloxane. This column 
was used in the (ASTM) cooperative study to provide the Precision and 
Bias data referred to in Section 15.
    7. Reagents and materials.
    7.1  Carrier gas--Carrier gas appropriate to the type of detector 
used. Helium has been used successfully. The minimum purity of the 
carrier gas used must be 99.95 mol %.
    7.2  Standards for calibration and identification--Standards of all 
components to be analyzed and the internal standard are required for 
establishing identification by retention as well as calibration for 
quantitative measurements. These materials shall be of known purity and 
free of the other components to be analyzed.

    Note 1.--Warning--These materials are flammable and may be harmful 
or fatal if ingested or inhaled.

    7.3  Preparation of calibration blends--For best results, these 
components must be added to a stock gasoline or petroleum naphtha, free 
of oxygenates (Warning--See Note 2). Refer to Test Method D 4307 for 
preparation of liquid blends. The preparation of several different 
blends, at different concentration levels covering the scope of the 
method, is recommended. These will be used to establish the linearity of 
the component response.

    Note 2.--Warning--Extremely flammable. Vapors harmful if inhaled.

    7.4  Methylene chloride--Used for column preparation. Reagent grade, 
free of non-volatile residue.

    Note 3.--Warning--Harmful if inhaled. High concentrations may cause 
unconsciousness or death.

    8. Preparation of column packings.
    8.1  TCEP column packing:
    8.1.1  Any satisfactory method, used in the practice of the art that 
will produce a column capable of retaining the C1 to C4 
alcohols and MTBE from components of the same boiling point range in a 
gasoline sample. The following procedure has been used successfully.
    8.1.2  Completely dissolve 10 g of TCEP in 100 mL of methylene 
chloride. Next add 40 g of 80/100 mesh Chromosorb P(AW) to the TCEP 
solution. Quickly transfer this mixture to a drying dish, in a fume 
hood, without scraping any of the residual packing from the sides of the 
container. Constantly, but gently, stir the packing until all of the 
solvent has evaporated. This column packing can be used immediately to 
prepare the TCEP column.
    9. Preparation of micro-packed TCEP column.
    9.1  Wash a straight 560 mm length of 1.6-mm outside diameter (0.38-
mm inside diameter) stainless steel tubing with methanol and dry with 
compressed nitrogen.
    9.2  Insert 6 to 12 strands of silvered wire, a small mesh screen or 
stainless steel frit inside one end of the tube. Slowly add 0.14 to 0.15 
g of packing material to the column and gently vibrate to settle the 
packing inside the column. When strands of wire are used to retain the 
packing material inside the column, leave 6.0 mm (0.25 in.) of space at 
the top of the column.
    9.3  Column conditioning--Both the TCEP and WCOT columns are to be 
briefly conditioned before use. Connect the columns to the valve (see 
11.1) in the chromatographic oven. Adjust the carrier gas flows as in 
11.3 and place the valve in the RESET position. After several minutes, 
increase the column oven temperature to 120  deg.C and maintain these 
conditions for 5 to 10 min. Cool the columns below 60  deg.C before 
shutting off the carrier flow.
    10. Sampling.
    10.1  Gasoline samples to be analyzed by this test method shall be 
sampled in accordance with 40 CFR part 80, appendix D.
    11. Preparation of apparatus and establishment of conditions.
    11.1  Assembly--Connect the WCOT column to the valve system using 
low volume connectors and narrow bore tubing. It is important to 
minimize the volume of the chromatographic system that comes in contact 
with the sample, otherwise peak broadening will occur.
    11.2  Adjust the operating conditions to those listed in Table 1, 
but do not turn on the detector circuits. Check the system for leaks 
before proceeding further.
    11.3  Flow rate adjustment.
    11.3.1  Attach a flow measuring device to the column vent with the 
valve in the RESET position and adjust the pressure to the injection 
port to give 5.0 mL/min flow (14 psig). Soap bubble flow meters are 
suitable.
    11.3.2  Attach a flow measuring device to the split injector vent 
and adjust flow from the split vent using the A flow controller to give 
a flow of 70 mL/min. Recheck the column vent flow set in 11.3.1 and 
adjust if necessary.
    11.3.3  Switch the valve to the BACKFLUSH position and adjust the 
variable restrictor to give the same column vent flow set in 11.3.1. 
This is necessary to minimize flow changes when the valve is switched.
    11.3.4  Switch the valve to the inject position RESET and adjust the 
B flow controller to give a flow of 3.0 to 3.2 mL/min at the detector 
exit. When required for the particular instrumentation used, add makeup 
flow or TCD switching flow to give a total of 21 mL/min at the detector 
exit.
    11.4  When a thermal conductivity detector is used, turn on the 
filament current and allow the detector to equilibrate. When a

[[Page 665]]

flame ionization detector is used, set the hydrogen and air flows and 
ignite the flame.
    11.5  Determine the Time of Backflush--The time to backflush will 
vary slightly for each column system and must be determined 
experimentally as follows. The start time of the integrator and valve 
timer must be synchronized with the injection to accurately reproduce 
the backflush time.
    11.5.1  Initially assume a valve BACKFLUSH time of 0.23 min. With 
the valve RESET, inject 3 L of a blend containing at least 0.5% 
or greater oxygenates (7.3), and simultaneously begin timing the 
analysis. At 0.23 min., rotate the valve to the BACKFLUSH position and 
leave it there until the complete elution of benzene is realized. Note 
this time as the RESET time, which is the time at which the valve is 
returned to the RESET position. When all of the remaining hydrocarbons 
are backflushed the signal will return to a stable baseline and the 
system is ready for another analysis. The chromatogram should appear 
similar to that illustrated in Fig. 2.
    11.5.2  It is necessary to optimize the valve BACKFLUSH time by 
analyzing a standard blend containing oxygenates. The correct BACKFLUSH 
time is determined experimentally by using valve switching times between 
0.2 and 0.3 min. When the valve is switched too soon, C5 and 
lighter hydrocarbons are backflushed and are co-eluted in the C4 
alcohol section of the chromatogram. When the valve BACKFLUSH is 
switched too late, part or all of the MTBE component is vented resulting 
in an incorrect MTBE measurement. Chromatograms resulting from incorrect 
valve times are shown in Figs. 3 and 4.

                  12. Calibration and standardization.

    12.1  Identification--Determine the retention time of each component 
by injecting small amounts either separately or in known mixtures or by 
comparing the relative retention times with those in Table 2.
    12.2  Standardization--The area under each peak in the chromatogram 
is considered a quantitative measure of the corresponding compound. 
Measure the peak area of each oxygenate and of the internal standard by 
either manual methods or electronic integrator. Calculate the relative 
volume response factor of each oxygenate, relative to the internal 
standard, according to Test Method D 4626.

  Table 2--Retention Characteristics for TCEP/WCOT Column Set Conditions
                              as in Table 1                             
------------------------------------------------------------------------
                                                             Relative   
                                              Retention   retention time
                 Component                    time, min       (t-amyl   
                                                           alcohol=1.00)
------------------------------------------------------------------------
Methanol...................................         3.21            0.44
Ethanol....................................         3.58            0.50
Isopropanol................................         3.95            0.56
tert-Butanol...............................         4.31            0.61
n-Propanol.................................         4.75            0.68
MTBE.......................................         5.29            0.76
sec-Butanol................................         5.63            0.82
Isobutanol.................................         6.33            0.93
n-Butanol..................................         7.55            1.10
Benzene....................................         7.88            1.17
------------------------------------------------------------------------

                             13. Procedure.

    13.1  Preparation of sample--Precisely add a quantity of the 
internal standard to an accurately measured quantity of sample. 
Concentrations of 1 to 5 volume percent have been used successfully.
    13.2  Chromatographic analysis--Introduce a representative aliquot 
of the sample, containing internal standard, into the chromatograph 
using the same technique as used for the calibration analyses. An 
injection volume of 3 L with a 15:1 split ratio has been used 
successfully.
    13.3  Interpretation of chromatogram--Compare the results of sample 
analyses to those of calibration analyses to determine identification of 
oxygenates present.

                            14. Calculation.

    14.1  After identifying the various oxygenates, measure the area of 
each oxygenate peak and that of the internal standard. Calculate the 
volume percent of each oxygenate as follows:

                                                                                                                
                                                              VS x PAj x 100                                    
                                                Vj    = -------------------------                               
                                                              PAS x Sj x VG                                     
                                                                                                                

where:
    Vj=volume percent of oxygenate to be determined,
    VS=volume of internal standard (tert-amyl alcohol) added,
    VG=volume of gasoline sample taken,

[[Page 666]]

    PAj=peak area of the oxygenate to be determined,
    PAS=peak area of the internal standard (tert-amyl alcohol), and
    Sj=relative volume response factor of each component (relative 
to the internal standard).
    14.2  Report the volume of each oxygenate. If the volume percent 
exceeds 10%, dilute the sample to a concentration lower than 10% and 
repeat the procedures in sections 13 and 14.

                         15. Precision and bias.

    15.1  Precision--The precision of this test method as determined by 
statistical examination of the interlaboratory test results is as 
follows:
    15.1.1 Repeatability--The difference between successive results 
obtained by the same operator with the same apparatus under constant 
operating conditions on identical test materials would, in the long run, 
in the normal and correct operation of the test method exceed the 
following values only in one case in twenty (see Table 3).
      
      

Methanol 0.086  x  (V+0.070)..............  Isobutanol 0.064  x         
                                             (V+0.086)                  
Ethanol 0.083  x  (V+0.000)...............  sec-Butanol 0.014  x  V     
Isopropanol 0.052  x  (V+0.150)...........  tert-Butanol 0.052  x       
                                             (V+0.388)                  
n-Propanol 0.040  x  (V+0.026)............  n-Butanol 0.043  x          
                                             (V+0.020)                  
                                                                        
                                                                        
                                            MTBE 0.104  x  (V+0.028)    
                                                                        


where V is the mean volume percent.
    15.1.2 Reproducibility--The difference between two single and 
independent results obtained by different operators working in different 
laboratories on identical material would, in the long run, exceed the 
following values only in one case in twenty (see Table 3).

Methanol 0.361  x  (V+0.070)..............  Isobutanol 0.179  x         
                                             (V+0.086)                  
Ethanol 0.373  x  (V+0.000)...............  sec-Butanol 0.277  x  V     
Isopropanol 0.214  x  (V+0.150)...........  tert-Butanol 0.178  x       
                                             (V+0.388)                  
n-Propanol 0.163  x  (V+0.026)............  n-Butanol 0.415  x          
                                             (V+0.020)                  
                                                                        
                                                                        
                                            MTBE 0.244 x (V+0.028)      
                                                                        


where V is the mean volume percent.
    15.2 Bias--Since there is no accepted reference material suitable 
for determining bias for the procedure in the test method, bias cannot 
be determined.

           Table 3--Precision Intervals--Determined from Cooperative Study Data Summarized in Section 15        
----------------------------------------------------------------------------------------------------------------
                                                                  Volume percent                                
           Components            -------------------------------------------------------------------------------
                                    0.20       0.50     1.00      2.00      3.00      4.00      5.00      6.00  
----------------------------------------------------------------------------------------------------------------
                                                                   Repeatability                                
                                                                                                                
                                 -------------------------------------------------------------------------------
Methanol........................      0.02      0.05      0.09      0.18      0.26      0.35      0.44      0.52
Ethanol.........................      0.02      0.04      0.08      0.17      0.25      0.33      0.42      0.50
Isopropanol.....................      0.02      0.03      0.06      0.11      0.16      0.22      0.27      0.32
n-Propanol......................      0.01      0.02      0.04      0.08      0.12      0.16      0.20      0.24
tert-Butanol....................      0.03      0.05      0.07      0.12      0.18      0.23      0.28      0.33
sec-Butanol.....................      0.01      0.01      0.01      0.02      0.02      0.03      0.03      0.03
Isobutanol......................      0.02      0.04      0.07      0.13      0.20      0.26      0.33      0.39
n-Butanol.......................      0.01      0.02      0.04      0.09      0.13      0.17      0.22      0.26
MTBE............................      0.02      0.05      0.11      0.21      0.31      0.42      0.52      0.63
                                                                                                                
                                 -------------------------------------------------------------------------------
                                                                  Reproducibility                               
                                                                                                                
                                 -------------------------------------------------------------------------------
Methanol........................      0.10      0.21      0.39      0.75      1.11      1.47      1.83      2.19
Ethanol.........................      0.07      0.19      0.37      0.75      1.12      1.49      1.87      2.24
Isopropanol.....................      0.07      0.14      0.25      0.46      0.67      0.89      1.10      1.32
n-Propanol......................      0.04      0.09      0.17      0.33      0.49      0.66      0.82      0.98
tert-Butanol....................      0.10      0.16      0.25      0.43      0.60      0.78      0.96      1.14
sec-Butanol.....................      0.12      0.20      0.28      0.39      0.48      0.55      0.62      0.68
Isobutanol......................      0.05      0.10      0.19      0.37      0.55      0.73      0.91      1.09
n-Butanol.......................      0.09      0.22      0.42      0.84      1.25      1.67      2.08      2.50
MTBE............................      0.05      0.12      0.23      0.45      0.68      0.90      1.13      1.35
----------------------------------------------------------------------------------------------------------------

      

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[GRAPHIC] [TIFF OMITTED] TC01SE92.153


[54 FR 11903, Mar. 22, 1989]

[[Page 671]]



       Appendix G to Part 80--Sampling Procedures for Diesel Fuel

                                1. Scope

    1.1  This method covers procedures for obtaining representative 
samples of diesel fuel for the purpose of testing for compliance with 
the cetane index and sulfur percentage standards set forth in 
Sec. 80.29.

                          2. Summary of Method

    2.1  It is necessary that the samples be truly representative of the 
diesel fuel in question. The precautions required to ensure the 
representative character of the samples are numerous and depend upon the 
tank, carrier, container or line from which the sample is being 
obtained, the type and cleanliness of the sample container, and the 
sampling procedures that are to be used. A summary of the sampling 
procedures and their application is presented in Table 1. Each procedure 
is suitable for sampling a material under definite storage, 
transportation, or container conditions. The basic principle of each 
procedure is to obtain a sample in such manner and from such locations 
in the tank or other container that the sample will be truly 
representative of the diesel fuel.

                         3. Description of Terms

    3.1  Average sample is one that consists of proportionate parts from 
all sections of the container.
    3.2  All-levels sample is one obtained by submerging a stoppered 
beaker or bottle to a point as near as possible to the draw-off level, 
then opening the sampler and raising it at a rate such that it is about 
\3/4\ full (maximum 85 percent) as it emerges from the liquid. An all-
levels sample is not necessarily an average sample because the tank 
volume may not be proportional to the depth and because the operator may 
not be able to raise the sampler at the variable rate required for 
proportionate filling. The rate of filling is proportional to the square 
root of the depth of immersion.
    3.3  Running sample is one obtained by lowering an unstoppered 
beaker or bottle from the top of the gasoline to the level of the bottom 
of the outlet connection or swing line, and returning it to the top of 
the top of the diesel fuel at a uniform rate of speed such that the 
beaker or bottle is about \3/4\ full when withdrawn from the diesel 
fuel.
    3.4  Spot sample is one obtained at some specific location in the 
tank by means of a thief bottle, or beaker.
    3.5  Top sample is a spot sample obtained 6 inches (150 mm) below 
the top surface of the liquid (Figure 1 of appendix D).
    3.6  Upper sample is a spot sample taken at the mid-point of the 
upper third of the tank contents (Figure 1 of appendix D).
    3.7  Middle sample is a spot sample obtained from the middle of the 
tank contents (Figure 1 of appendix D).
    3.8  Lower sample is a spot sample obtained at the level of the 
fixed tank outlet or the swing line outlet (Figure 1 of appendix D).
    3.9  Clearance sample is a spot sample taken 4 inches (100 mm) below 
the level of the tank outlet (Figure 1 of appendix D).
    3.10  Bottom sample is a spot sample obtained from the material on 
the bottom surface of the tank, container, or line at its lowest point.
    3.11  Drain sample is a tap sample obtained from the draw-off or 
discharge valve. Occasionally, a drain sample may be the same as a 
bottom sample, as in the case of a tank car.
    3.12  Continuous sample is one obtained from a pipeline in such 
manner as to give a representative average of a moving stream.
    3.13  Nozzle sample is one obtained from a diesel pump nozzle which 
dispenses diesel fuel from a storage tank at a retail outlet or a 
wholesale purchaser-consumer facility.

                          4. Sample Containers

    4.1  Sample containers may be clear or brown glass bottles, or cans. 
The clear glass bottle is advantageous because it may be examined 
visually for cleanliness, and also allows visual inspection of the 
sample for free water or solid impurities. The brown glass bottle 
affords some protection from light. Cans with the seams soldered on the 
exterior surface with a flux of rosin in a suitable solvent are 
preferred because such a flux is easily removed with diesel fuel, 
whereas many others are very difficult to remove. If such cans are not 
available, other cans made with a welded construction that are not 
affected by, and that do not affect, the diesel fuel being sampled are 
acceptable.
    4.2  Container closure. Cork or glass stoppers, or screw caps of 
plastic or metal may be used for glass bottles; screw caps only shall be 
used for cans to provide a vapor-tight closure seal. Corks must be of 
good quality, clean and free from holes and loose bits of cork. Never 
use rubber stoppers. Contact of the sample with the cork may be 
prevented by wrapping tin or aluminum foil around the cork before 
forcing it into the bottle.
    Glass stoppers must be a perfect fit. Screw caps must be protected 
by a cork disk faced with tin or aluminum foil, or other material that 
will not affect petroleum or petroleum products. In addition, a phenolic 
cap with a teflon coated liner may be used.
    4.3  Cleaning procedure. The method of cleaning all sample 
containers must be consistent with the residual materials in the 
container and must produce sample containers that are clean and free of 
water, dirt, lint, washing compounds, naphtha, or other

[[Page 672]]

solvents, soldering fluxes or acids, corrosion, rust, and oil.
    New sample containers should be inspected and cleaned if necessary. 
Dry the container by either passing a current of clean, warm air through 
the container or by allowing it to air dry in a clean area at room 
temperature. When dry, stopper or cap the container immediately.

                          5. Sampling Apparatus

    5.1  Sampling apparatus is described in detail under each of the 
specific sampling procedures. Clean, dry, and free all sampling 
apparatus from any substance that might contaminate the material, using 
the procedure described in 4.3.

                      6. Time and Place of Sampling

    6.1  When loading or discharging diesel fuel, take samples from both 
shipping and receiving tanks, and from the pipeline if required.
    6.2  Ship or barge tanks. Sample each product after the vessel is 
loaded or just before unloading.
    6.3  Tank cars. Sample the product after the car is loaded or just 
before unloading.

    Note: When taking samples from tanks suspected of containing 
flammable atmospheres, precautions should be taken to guard against 
ignitions due to static electricity. Metal or conductive objects, such 
as gage tapes, sample containers, and thermometers, should not be 
lowered into or suspended in a compartment or tank which is being filled 
or immediately after cessation of pumping. A waiting period of 
approximately one minute will generally permit a substantial relaxation 
of the electrostatic charge; under certain conditions a longer period 
may be deemed advisable.

                          7. Obtaining Samples

    7.1  Directions for sampling cannot be made explicit enough to cover 
all cases. Extreme care and good judgment are necessary to ensure 
samples that represent the general character and average condition of 
the material. Clean hands are important. Clean gloves may be worn but 
only when absolutely necessary, such as in cold weather, or when 
handling materials at high temperature, or for reasons of safety. Select 
wiping cloths so that lint is not introduced, contaminating samples.
    7.2  As many petroleum vapors are toxic and flammable, avoid 
breathing them or igniting them from an open flame or a spark produced 
by static. Follow all safety precautions specific to the material being 
sampled.

                           8. Handling Samples

    8.1  Container outage. Never completely fill a sample container, but 
allow adequate room for expansion, taking into consideration the 
temperature of the liquid at the time of filling and the probable 
maximum temperature to which the filled container may be subjected.

                           9. Shipping Samples

    9.1  To prevent loss of liquid during shipment, and to protect 
against moisture and dust, cover with suitable vapor tight caps. The 
caps of all containers must be screwed down tightly and checked for 
leakage. Postal and express office regulations applying to the shipment 
of flammable liquids must be observed.

                     10. Labeling Sample Containers

    10.1  Label the container immediately after a sample is obtained. 
Use waterproof and oilproof ink or a pencil hard enough to dent the tag, 
since soft pencil and ordinary ink markings are subject to obliteration 
from moisture, oil smearing and handling. An indelible identification 
symbol, such as a bar code, may be used in lieu of a manually addressed 
label. The label shall reference the following information:
    10.1.1  Date and time (the period elapsed during continuous 
sampling);
    10.1.2  Name of the sample;
    10.1.3  Name or number and owner of the vessel, car, or container;
    10.1.4  Brand and grade of material; and
    10.1.5  Reference symbol or identification number.

                         11. Sampling procedures

    11.1  The standard sampling procedures described in this method are 
summarized in Table 1. Alternative sampling procedures may be used if a 
mutually satisfactory agreement has been reached by the party(ies) 
involved and EPA and such agreement has been put in writing and signed 
by authorized officials.

   Table 1--Summary of Diesel Fuel Sampling Procedures and Applicability
------------------------------------------------------------------------
         Type of container                  Procedure         Paragraph 
------------------------------------------------------------------------
Storage tanks, ship and barge        Bottle sampling.......         11.2
 tanks, tank cars, tank trucks.                                         
Storage tanks with taps............  Tap sampling..........         11.3
Pipe and lines.....................  Continuous line                11.4
                                      sampling.                         
Retail outlet and whole-sale         Nozzle sampling.......         11.5
 purchaser-consumer facility                                            
 storage tanks.                                                         
------------------------------------------------------------------------

    11.2  Bottle or beaker sampling. The bottle or beaker sampling 
procedure is applicable for sampling liquids of 16 pounds (1.12 kgf/
cm\2\) RVP or less in tank cars, tank trucks, shore tanks, ship tanks, 
and barge tanks.

[[Page 673]]

    11.2.1  Apparatus. A suitable sampling bottle or beaker as shown in 
Figure 2 of appendix D is required.
    11.2.2  Procedure.
    11.2.2.1  All-levels sample. Lower the weighted, stoppered bottle or 
beaker as near as possible to the draw-off level, pull out the stopper 
with a sharp jerk of the cord or chain and raise the bottle at a uniform 
rate so that it is about \3/4\ full as it emerges from the liquid.
    11.2.2.2  Running sample. Lower the unstoppered bottles or beaker as 
near as possible to the level of the bottom of the outlet connection or 
swing line and then raise the bottle or beaker to the top of the 
gasoline at a uniform rate of speed such that it is about \3/4\ full 
when withdrawn from the diesel fuel.
    11.2.2.3  Upper, middle, and lower samples. Lower the weighted, 
stoppered bottle to the proper depths (Figure 1 of appendix D) as 
follows:

Upper sample..............................  middle of upper third of the
                                             tank contents              
Middle sample.............................  middle of the tank contents 
Lower sample..............................  level of the fixed tank     
                                             outlet or the swing-line   
                                             outlet                     
                                                                        

    At the selected level pull out the stopper with a sharp jerk of the 
cord or chain and allow the bottle or beaker to fill completely, as 
evidenced by the cessation of air bubbles. When full, raise the bottle 
or beaker, pour off a small amount, and stopper immediately.
    11.2.2.4  Top sample. Obtain this sample (Figure 1 of appendix D) in 
the same manner as specified in 11.2.2.3 but at six inches (150 mm) 
below the top surface of the tank contents.
    11.2.2.5  Handling. Stopper and label bottle samples immediately 
after taking them, and deliver to the laboratory in the original 
sampling bottles.
    11.3  Tap sampling. The tap sampling procedure is applicable for 
sampling liquids of twenty-six pounds (1.83 kgf/cm\2\) RVP or less in 
tanks which are equipped with suitable sampling taps or lines. The 
assembly for tap sampling is shown in Figure 3 of appendix D.
    11.3.1  Apparatus
    11.3.1.1  Tank taps. The tank should be equipped with at least three 
sampling taps placed equidistant throughout the tank height and 
extending at least three feet (0.9 meter) inside the tank shell. A 
standard \1/4\ inch pipe with suitable valve is satisfactory.
    11.3.1.2  Tube. A delivery tube that will not contaminate the 
product being sampled and long enough to reach to the bottom of the 
sample container is required to allow submerged filling.
    11.3.1.3  Sample containers. Use clean, dry glass bottles of 
convenient size and strength or metal containers to receive the samples.
    11.3.2  Procedure
    11.3.2.1  Before a sample is drawn, flush the tap (or gage glass 
drain cock) and line until they are purged completely. Connect the clean 
delivery tube to the tap. Draw upper, middle, or lower samples directly 
from the respective taps after the flushing operation. Stopper and label 
the sample container immediately after filling, and deliver it to the 
laboratory.
    11.4  Continuous sampling. The continuous sampling procedure is 
applicable for sampling liquids of 16 pounds (1.12 kgf/cm\2\) RVP or 
less and semiliquids in pipelines, filling lines, and transfer lines. 
The continuous sampling may be done manually or by using automatic 
devices.
    11.4.1  Apparatus
    11.4.1.1  Sampling probe. The function of the sampling probe is to 
withdraw from the flow stream a portion that will be representative of 
the entire stream. The apparatus assembly for continuous sampling is 
shown in Figure 4 of Appendix D. Probe designs that are commonly used 
are as follows:
    11.4.1.1.1  A tube extending to the center of the line and beveled 
at a 45 degree angle facing upstream (Figure 4(a) of appendix D).
    11.4.1.1.2  A long-radius forged elbow or pipe bend extending to the 
center line of the pipe and facing upstream. The end of the probe should 
be reamed to give a sharp entrance edge (Figure 4(b) of appendix D).
    11.4.1.1.3  A closed-end tube with a round orifice spaced near the 
closed end which should be positioned in such a way that the orifice is 
in the center of the pipeline and is facing the stream as shown in 
Figure 4(c) of appendix D.
    11.4.1.2  Probe location. Since the fluid to be sampled may not in 
all cases be homogeneous, the location, the position and the size of the 
sampling probe shoud be such as to minimize stratification or dropping 
out of heavier particles within the tube or the displacement of the 
product within the tube as a result of variation in gravity of the 
flowing stream. The sampling probe should be located preferably in a 
vertical run of pipe and as near as practicable to the point where the 
product passes to the receiver. The probe should always be in a 
horizontal position.
    11.4.1.2.1  The sampling lines should be as short as practicable and 
should be cleared before any samples are taken.
    11.4.1.2.2  Where adequate flowing velocity is not available, a 
suitable device for mixing the fluid flow to ensure a homogeneous 
mixture at all rates of flow and to eliminate stratification should be 
installed upstream of the sampling tap. Some effective devices for 
obtaining a homogeneous mixture are as follows: Reduction in pipe size; 
a series of baffles; orifice or perforated plate; and a combination of 
any of these methods.
    11.4.1.2.3  The design or sizing of these devices is optional with 
the user, as long as the

[[Page 674]]

flow past the sampling point is homogeneous and stratification is 
eliminated.
    11.4.1.3  To control the rate at which the sample is withdrawn, the 
probe or probes should be fitted with valves or plug cocks.
    11.4.1.4  Automatic sampling devices that meet the standards set out 
in 11.4.1.5 may be used in obtaining samples of diesel fuel. The quality 
of sample collected must be of sufficient size for analysis, and its 
composition should be identical with the composition of the batch 
flowing in the line while the sample is being taken. An automatic 
sampler installation necessarily includes not only the automatic 
sampling device that extracts the samples from the line, but also a 
suitable probe, connecting lines, auxiliary equipment, and a container 
in which the sample is collected. Automatic samplers may be classified 
as follows:
    11.4.1.4.1  Continuous sampler, time cycle (nonproportional) type. A 
sampler designed and operated in such a manner that it transfers equal 
increments of liquid from the pipeline to the sample container at a 
uniform rate of one or more increments per minute is a continuous 
sampler.
    11.4.1.4.2  Continuous sampler, flow-responsive (proportional) type. 
A sampler that is designed and operated in such a manner that it will 
automatically adjust the quantity of sample in proportion to the rate of 
flow is a flow-responsive (proportional) sampler. Adjustment of the 
quantity of sample may be made either by varying the frequency of 
transferring equal increments of sample to the sample container, or by 
varying the volume of the increments while maintaining a constant 
frequency of transferring the increments to the sample container. The 
apparatus assembly for continuous sampling is shown in Figure 4 of 
appendix D.
    11.4.1.4.3  Intermittent sampler. A sampler that is designed and 
operated in such a manner that it transfers equal increments of liquid 
from a pipeline to the sample container at a uniform rate of less than 
one increment per minute is an intermittent sampler.
    11.4.1.5  Standards of installation. Automatic sampler installations 
should meet all safety requirements in the plant or area where used, and 
should comply with American National Standard Code for Pressure Piping, 
and other applicable codes (ANSI B31.1). The sampler should be so 
installed as to provide ample access space for inspection and 
maintenance.
    11.4.1.5.1  Small lines connecting various elements of the 
installation should be so arranged that complete purging of the 
automatic sampler and of all lines can be accomplished effectively. All 
fluid remaining in the sampler and the lines from the preceding sampling 
cycle should be purged immediately before the start of any given 
sampling operation.
    11.4.1.5.2  In those cases where the sampler design is such that 
complete purging of the sampling lines and the sampler is not possible, 
a small pump should be installed in order to circulate a continuous 
stream from the sampling tube past or through the sampler and back into 
the line. The automatic sampler should then withdraw the sample from the 
sidestream through the shortest possible connection.
    11.4.1.5.3  Under certain conditions, there may be a tendency for 
water and heavy particles to drop out in the discharge line from the 
sampling device and appear in the sample container during some 
subsequent sampling period. To circumvent this possibility, the 
discharge pipe from the sampling device should be free of pockets or 
enlarged pipe areas, and preferably should be pitched downward to the 
sample container.
    11.4.1.5  To ensure clean, free-flowing lines, piping should be 
designed for periodic cleaning.
    11.4.1.6  Field calibration. Composite samples obtained from the 
automatic sampler installation should be verified for quantity 
performance in a manner that meets with the approval of all parties 
concerned (including EPA), at least once a month and more often if 
conditions warrant. In the case of time-cycle samplers, deviations in 
quantity of the sample taken should not exceed  five percent 
for any given setting. In the case of flow-responsive samplers, the 
deviation in quantity of sample taken per 1,000 barrels of flowing 
stream should not exceed  5 percent. For the purpose of 
field-calibrating an installation, the composite sample obtained from 
the automatic sampler under test should be verified for quality by 
comparing on the basis of physical and chemical properties, with either 
a properly secured continuous nonautomatic sample or tank sample. The 
tank sample should be taken under the following conditions:
    11.4.1.6.1  The batch pumped during the test interval should be 
diverted into a clean tank and a sample taken within one hour after 
cessation of pumping.
    11.4.1.6.2  If the sampling of the delivery tank is to be delayed 
beyond one hour, then the tank selected must be equipped with an 
adequate mixing means. For valid comparison, the sampling of the 
delivery tank must be completed within eight hours after cessation of 
pumping, even though the tank is equipped with a motor-driven mixer.
    11.4.1.6.3  When making a normal full-tank delivery from a tank, a 
properly secured sample may be used to check the results of the sampler 
if the parties (including EPA) mutually agree to this procedure.
    11.4.1.7  Receiver. The receiver must be a clean, dry container of 
convenient size to receive the sample. All connections from the sample 
probe to the sample container must be free of leaks. Two types of 
container may

[[Page 675]]

be used, depending upon service requirements.
    11.4.1.7.1  Atmospheric container. The atmospheric container shall 
be constructed in such a way that it retards evaporation loss and 
protects the sample from extraneous material such as rain, snow, dust, 
and trash. The construction should allow cleaning, interior inspection, 
and complete mixing of the sample prior to removal. The container should 
be provided with a suitable vent.
    11.4.1.7.2  Closed container. The closed container shall be 
constructed in such a manner that it prevents evaporation loss. The 
construction must allow cleaning, interior inspection and complete 
mixing of the sample prior to removal. The container should be equipped 
with a pressure-relief valve.
    11.4.2  Procedure.
    11.4.2.1  Nonautomatic sample. Adjust the valve or plug cock from 
the sampling probe so that a steady stream is drawn from the probe. 
Whenever possible, the rate of sample withdrawal should be such that the 
velocity of liquid flowing through the probe is approximately equal to 
the average linear velocity of the stream flowing through the pipeline. 
Measure and record the rate of sample withdrawal as gallons per hour. 
Divert the sample stream to the sampling container continuously or 
intermittently to provide a quantity of sample that will be of 
sufficient size for analysis.
    11.4.2.2  Automatic sampling. Purge the sampler and the sampling 
lines immediately before the start of a sampling operation. If the 
sample design is such that complete purging is not possible, circulate a 
continuous stream from the probe past or through the sampler and back 
into the line. Withdraw the sample from the side stream through the 
automatic sampler using the shortest possible connections. Adjust the 
sampler to deliver not less than one and not more than 40 gallons (151 
liters) of sample during the desired sampling period. For time-cycle 
samplers, record the rate at which sample increments were taken per 
minute. For flow-responsive samplers, record the proportion of sample to 
total stream. Label the samples and deliver them to the laboratory in 
the containers in which they were collected.
    11.5  Nozzle sampling. The nozzle sampling procedure is applicable 
for sampling diesel fuel from a retail outlet or wholesale purchaser-
consumer facility storage tank.
    11.5.1  Apparatus. Sample containers conforming with 4.1 should be 
used. A spacer, if appropriate (Figure 6 of appendix D), and a nozzle 
extension device similar to that shown in Figures 7 or 7a of appendix D 
shall be used when nozzle sampling. The nozzle extension device does not 
need to be identical to that shown in Figure 7 or 7a of appendix D but 
it should be a device that will bottom fill the container.
    11.5.2  Procedure. Immediately after diesel fuel has been delivered 
from the pump and the pump has been reset, deliver a small amount of 
product into the sample container. Rinse sample container and dump 
product into waste container. Insert nozzle extension (Figure 7 or 7a of 
appendix D) into sample container and insert pump nozzle into extension 
with slot over air bleed hole. Fill slowly through nozzle extension to 
70-80 percent full (Figure 8 of appendix D). Remove nozzle extension. 
Cap sample container at once. Check for leaks.

                12. Special Precautions and Instructions.

    12.1  Precautions. Official samples should be taken by, or under the 
immediate supervision of, a person of judgment, skill, and sampling 
experience. Never prepare composite samples for this test. Make certain 
that containers which are to be shipped by common carrier conform to 
applicable Interstate Commerce Commission, state, and local regulations. 
When flushing or purging lines or containers, observe the pertinent 
regulations and precautions against fire, explosion, and other hazards.
    12.2  Sample containers. Use containers of not less than one quart 
(0.9 liter) nor more than two gallons (7.6 liters) capacity, of 
sufficient strength to withstand the pressure to which they may be 
subjected. Open-type containers have a single opening which permits 
sampling by immersion. Closed-type containers have two openings, one in 
each end (or the equivalent thereof), fitted with valves suitable for 
sampling by water displacement or by purging.
    12.3  Transfer connections. The transfer connection for the open-
type container consists of an air tube and a liquid delivery tube 
assembled in a cap or stopper. The air tube extends to the bottom of the 
container. One end of the liquid delivery tube is long enough to reach 
the bottom of the diesel fuel chamber while the sample is being 
transferred to the chamber. The transfer connection for the closed-type 
container consists of a single tube with a connection suitable for 
attaching it to one of the openings of the sample container. The tube is 
long enough to reach the bottom of the diesel chamber while the sample 
is being transferred.
    12.4  Sampling open tanks. Use clean containers of the open type 
when sampling open tanks and tank cars. An all-level sample obtained by 
the bottle procedure described in 11.2 is recommended. Before taking the 
sample, flush the container by immersing it in the product to be 
sampled. Then obtain the sample immediately. Pour off enough so that the 
container will be 70-80 percent full and close it promptly. Label the 
container and deliver it to the laboratory.
    12.5  Sampling closed tanks. Containers of either the open or closed 
type may be used to obtain samples from closed or pressure

[[Page 676]]

tanks. If the closed type is used, obtain the sample using the water 
displacement procedure described in 12.8 or the purging procedure 
described in 12.9. The water displacement procedure is preferable 
because the flow of product involved in the purging procedure may be 
hazardous.
    12.6  Water displacement procedure. Completely fill the closed-type 
container with water and close the valves. While permitting a small 
amount of product to flow through the fittings, connect the top or inlet 
valve of the container to the tank sampling tap or valve. Then open all 
valves on the inlet side of the container. Open the bottom or outlet 
valve slightly to allow the water to be displaced slowly by the sample 
entering the container. Regulate the flow so that there is no 
appreciable change in pressure within the container. Close the outlet 
valve as soon as diesel fuel discharges from the outlet; then in 
succession close the inlet valve and the sampling valve on the tank. 
Disconnect the container and withdraw enough of the contents so that it 
will be 70-80 percent full. If the vapor pressure of the product is not 
high enough to force liquid from the container, open both the upper and 
lower valves slightly to remove the excess. Promptly seal and label the 
container, and deliver it to the laboratory.
    12.7  Purging procedure. Connect the inlet valve of the closed-type 
container to the tank sampling tap or valve. Throttle the outlet valve 
of the container so that the pressure in it will be approximately equal 
to that in the container being sampled. Allow a volume of product equal 
to at least twice that of the container to flow through the sampling 
system. Then close all valves, the outlet valve first, the inlet valve 
of the container second, and the tank sampling valve last, and 
disconnect the container immediately. Withdraw enough of the contents so 
that the sample container will be 70-80 percent full. If the vapor 
pressure of the product is not high enough to force liquid from the 
container, open both the upper and lower valves slightly to remove the 
excess. Promptly seal and label the container, and deliver it to the 
laboratory.

[[Page 677]]

[GRAPHIC] [TIFF OMITTED] TC01SE92.154


[55 FR 34140, Aug. 21, 1990]
[[Page 679]]



                              FINDING AIDS




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

  A list of CFR titles, subtitles, chapters, subchapters and parts and 
an alphabetical list of agencies publishing in the CFR are included in 
the CFR Index and Finding Aids volume to the Code of Federal Regulations 
which is published separately and revised annually.

  Material Approved for Incorporation by Reference
  Table of CFR Titles and Chapters
  Alphabetical List of Agencies Appearing in the CFR
  Table of OMB Control Numbers
  List of CFR Sections Affected

[[Page 681]]

            Material Approved for Incorporation by Reference

                      (Revised as of July 1, 1996)

  The Director of the Federal Register has approved under 5 U.S.C. 
552(a) and 1 CFR Part 51 the incorporation by reference of the following 
publications. This list contains only those incorporations by reference 
effective as of the revision date of this volume. Incorporations by 
reference found within a regulation are effective upon the effective 
date of that regulation. For more information on incorporation by 
reference, see the preliminary pages of this volume.


40 CFR, CHAPTER I (PARTS 72 TO 80): SUBCHAPTER C--AIR PROGRAMS

ENVIRONMENTAL PROTECTION AGENCY


American Gas Association

  1515 Wilson Blvd., Arlington, VA 22209
AGA 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)...........................  75.20; Appendices D 
                                                        and E of Part 75


American Institute of Certified Public Accountants, Inc.

  1211 Avenue of the Americas, New York, NY 10036
Codification of Statements on Auditing Standards, 
  ``Statements on Standards for Attestation 
  Engagements, 1991, Identification Number 059021.                80.125


American Society of Mechanical Engineers (ASME)

  345 East 47th St., New York, NY 10017
ASME MFC-3M-1989 with September 1990 Errata 
  Measurement of Fluid Flow in Pipes Using 
  Orifice, Nozzle, and Venturi.................... 75.20 and Appendix D 
                                                              of Part 75
ASME MFC-4M-1986 (Reaffirmed 1990) Measurement of 
  Gas Flow by Turbine Meters...................... 75.20 and Appendix D 
                                                              of Part 75
ASME MFC-5M-1985 Measurement of Liquid Flow in 
  Closed Conduits Using Transit-Time Ultrasonic 
  Flowmeters...................................... 75.20 and Appendix D 
                                                              of Part 75
ASME MFC-6M-1987 with June 1987 Errata Measurement 
  of Fluid Flow in Pipes Using Vortex Flow Meters. 75.20 and Appendix D 
                                                              of Part 75
ASME MFC-7M-1987 (Reaffirmed 1992) Measurement of 
  Gas Flow by Means of Critical Flow Venturi 
  Nozzles......................................... 75.20 and Appendix D 
                                                              of Part 75
ASME MFC-9M-1988 with December 1989 Errata 
  Measurement of Liquid Flow in Closed Conduits by 
  Weighing Method................................. 75.20 and Appendix D 
                                                              of Part 75
ASME Performance Test Code 4.2 (1991), Test Code 
  for Coal Pulverizers............................           76.4; 76.15


American Society for Testing and Materials

  1916 Race Street, Philadelphia, Pennsylvania 19103
ASTM D 86-90, Standard Test Method for 
  Distillation of Petroleum Products..............                 80.46
ASTM D129-91 Standard Test Method for Sulfur in 
  Petroleum Products (General Bomb Method)........ Appendices A and D of 
                                                        Part 75 and 72.7
ASTM D240-87 (Reapproved 1991) Standard Test 
  Method for Heat of Combustion of Liquid 
  Hydrocarbon Fuels by Bomb Calorimeter........... Appendices A, D, and 
                                                            F of Part 75

[[Page 682]]

ASTM D287-82 (Reapproved 1987) Standard Test 
  Method for API Gravity of Crude Petroleum and 
  Petroleum Products (Hydrometer Method).......... Appendix D of Part 75
ASTM D388-92 Standard Classification of Coals by 
  Rank............................................  72.2 and Appendix F 
                                                              of Part 75
ASTM D396-90a Standard Specification for Fuel Oils                  72.2
ASTM D439-81, Standard Specifications for 
  Automotive Gasoline.............................     80.2(d); 80.22(b)
ASTM D941-88 Standard Test Method for Density and 
  Relative Density (Specific Gravity) of Liquids 
  by Lipkin Bicapillary Pycnometer................ Appendix D of Part 75
ASTM D975-91 Standard Specification for Diesel 
  Fuel Oils.......................................                  72.2
ASTM D 975-93, Standard Specification for Diesel 
  Fuel Oils.......................................      79.56(d)(5) and 
                                                                  (e)(3)
ASTM D 976-80 Standard Methods for Calculated 
  Cetane Index of Distillate Fuels................               80.2(w)
ASTM D1072-90 Standard Test Method for Total 
  Sulfur in Fuel Gases............................ Appendix D of Part 75 
                                                                and 72.7
ASTM D1217-91 Standard Test Method for Density and 
  Relative Density (Specific Gravity) of Liquids 
  by Bingham Pycnometer........................... Appendix D of Part 75
ASTM D1250-80 (Reapproved 1990) Standard Guide for 
  Petroleum Measurement Tables.................... Appendix D of Part 75
ASTM D1265-92 Standard Practice for Sampling 
  Liquified Petroleum (LP) Gases (Manual Method)..                  72.7
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......... Appendix D of Part 75
ASTM D 1319-88 Standard Test Method for 
  Hydrocarbon Types in Liquid Petroleum Products 
  by Fluorescent Indicator Adsorption.............               80.2(z)
ASTM D 1319-93, Standard Test Method for 
  Hydrocarbon Types in Liquid Petroleum Products 
  by Fluorescent Indicator Adsorption.............                 80.46
ASTM D1480-91 Standard Test Method for Density and 
  Relative Density (Specific Gravity) of Viscous 
  Materials by Bingham Pycnometer................. Appendix D of Part 75
ASTM D1481-91 Standard Test Method for Density and 
  Relative Density (Specific Gravity) of Viscous 
  Materials by Lipkin Bicapillary Pycnometer...... Appendix D of Part 75
ASTM D1552-90 Standard Test Method for Sulfur in 
  Petroleum Products (High Temperature Method).... Appendices A and D of 
                                                                 Part 75
ASTM D1826-88 Standard Test Method for Calorific 
  (Heating) Value of Gases in Natural Gas Range by 
  Continuous Recording Calorimeter................ Appendix F of Part 75
ASTM D1945-91 Standard Test Method for Analysis of 
  Natural Gas by Gas Chromatography............... Appendices F and G of 
                                                                 Part 75
ASTM D1946-90 Standard Practice for Analysis of 
  Reformed Gas by Gas Chromatography.............. Appendices F and G of 
                                                                 Part 75
ASTM D 1989-92 Standard Test Method for Gross 
  Caloric Value of Coal and Coke by Microprocessor 
  Controlled Isoperibol Calorimeters.............. Appendix F of Part 75
ASTM D 2013-86 Standard Method of Preparing Coal 
  Samples for Analysis............................   Appendix F of Part 
                                                               75; 75.15
ASTM D2015-91 Standard Test Method for Gross 
  Calorific Value of Coal and Coke by the 
  Adiabatic Bomb Calorimeter...................... Appendices A, D, and 
                                                     F of Part 75; 75.15

[[Page 683]]

ASTM D2234-89 Standard Test Methods for Collection 
  of a Gross Sample of Coal.......................   Appendix F of Part 
                                                               75; 75.15
ASTM D2382-88 Standard Test Method for Heat of 
  Combustion of Hydrocarbon Fuels by Bomb 
  Calorimeter (High-Precision Method).............  Appendices D, and F 
                                                              of Part 75
ASTM D2502-87 Standard Test Method for Estimation 
  of Molecular Weight (Relative Molecular Mass) of 
  Petroleum Oils from Viscosity Measurements...... Appendix G of Part 75
ASTM D2503-82 (Reapproved 1987) Standard Test 
  Method for Molecular Weight (Relative Molecular 
  Mass) of Hydrocarbons by Thermoelectric 
  Measurement of Vapor Pressure................... Appendix G of Part 75
ASTM D 2622-87 Standard Test Method for Sulfur in 
  Petroleum Products by X-Ray Spectrometry........               80.2(y)
ASTM D2622-92 Standard Test Method for Sulfur in 
  Petroleum Products by X-Ray Spectrometry........   72.7; Appendices A 
                                                      and D of Part 75; 
                                                                   80.46
ASTM D2699-80, Standard Test Method for Knock 
  Characteristics of Motor Fuels by the Research 
  Method..........................................               80.2(d)
ASTM D2700-81, Standard Test Method for Knock 
  Characteristics of Motor and Aviation Fuels by 
  the Motor Method................................               80.2(d)
ASTM D 2880-90a, Standard Specification for Gas 
  Turine Fuel Oils................................                  72.2
ASTM D2892-84, Standard Test Method for 
  Distillation of Crude Petroleum (15-Theoretical 
  Plate Column)................................... Appendix E to Part 80
ASTM D 3172-89, Standard Practice for Proximate 
  Analysis of Coal and Coke.......................           76.4; 76.15
ASTM D3174-89 Standard Test Method for Ash in the 
  Analysis Sample of Coal and Coke from Coal...... Appendix G of Part 75
ASTM D3176-89 Standard Practice for Ultimate 
  Analysis of Coal and Coke....................... Appendices A and F of 
                                                    Part 75; 76.4; 76.15
ASTM D3177-89 Standard Test Methods for Total 
  Sulfur in the Analysis Sample of Coal and Coke..   Appendix A of Part 
                                                               75; 75.15
ASTM D3178-89 Standard Test Methods for Carbon and 
  Hydrogen in the Analysis Sample of Coal and Coke Appendix G of Part 75
ASTM D3238-90 Standard Test Method for Calculation 
  of Carbon Distribution and Structural Group 
  Analysis of Petroleum Oils by the n-d-M Method.. Appendix G of Part 75
ASTM D 3286-91a Standard Test Method for Gross 
  Calorific Value of Coal and Coke by the 
  Isoperibol Bomb Calorimeter..................... Appendix F of Part 75
ASTM D 3588-91 Standard Practice for Calculating 
  Heat Value, Compressibility Factor, and Relative 
  Density (Specific Gravity) of Gaseous Fuels..... Appendix F of Part 75
ASTM D 3606-92, Standard Test Method for 
  Determination of Benzene and Toluene in Finished 
  Motor and Aviation Gasoline by Gas 
  Chromatography..................................                 80.46
ASTM D4052-91 Standard Test Method for Density and 
  Relative Density of Liquids by Digital Density 
  Meter........................................... Appendix D of Part 75
ASTM D4057-88 Standard Practice for Manual 
  Sampling of Petroleum and Petroleum Products.... Appendix D of Part 75 
                                                                and 72.7
ASTM D4177-82 (Reapproved 1990) Standard Practice 
  for Automatic Sampling of Petroleum and 
  Petroleum Products.............................. Appendix D of Part 75

[[Page 684]]

ASTM D4239-85 Standard Test Methods for Sulfur in 
  the Analysis Sample of Coal and Coke Using High 
  Temperature Tube Furnace Combustion Methods.....   Appendix A of Part 
                                                               75; 75.15
ASTM D 4294-83 Standard Test Method for Sulfur in 
  Petroleum Products by Non-dispersive X-ray 
  Fluorescence Spectrometry.......................       80.30(g)(2)(ii)
ASTM D4294-90 Standard Test Method for Sulfur in 
  Petroleum Products by Energy-Dispersive X-Ray 
  Fluorescence Spectroscopy....................... 72.7 and Appendices A 
                                                        and D of Part 75
ASTM D 4468-85 (Reapproved 1989) Standard Test 
  Method for Total Sulfur in Gaseous Fuels by 
  Hydrogenolysis and Rateometric Calorimetry...... Appendix D of Part 75
ASTM D 4814-93a, Standard Specification for 
  Automotive Spark-Ignition Engine Fuel...........      79.56(d)(5) and 
                                                                  (e)(3)
ASTM D 4815-93, Standard Test Method for 
  Determination of MTBE, ETBE, TAME, DIPE, 
  tertiary-Amyl Alcohol and C1 to C 4 
  Alcohols in Gasoline by Gas Chromatography......                 80.46
ASTM D 4891-89 Standard Test Method for Heating 
  Value of Gases in Natural Gas Range by 
  Stolchiometric Combustion....................... Appendix F of Part 75
ASTM D 5291-92 Standard Test Methods for 
  Instrumental Determination of Carbon, Hydrogen, 
  and Nitrogen in Petroleum Products and 
  Lubricants...................................... Appendix G of Part 75
ASTM D 5504-94 Standard Test Method for 
  Determination of Sulfur Compounds in Natural Gas 
  and Gaseous Fuels by Gas Chromatography and 
  Chemiluminescence............................... Appendix D of Part 75
ASTM E1-86, Standard Specification for ASTM 
  Thermometers.................................... Appendix E of Part 80


Gas Processors Association

  6526 East 60th Street, Tulsa, OK 74145
GPA Standard 2172-86, Calculation of Gross Heating 
  Value, Relative Density and Compressibility 
  Factor for Natural Gas Mixtures from 
  Compositional Analysis.......................... Appendices D, E, and 
                                                            F of Part 75
GPA Standard 2261-90, Analysis for Natural Gas and 
  Similar Gaseous Mixtures by Gas Chromatography.. Appendices D, F, and 
                                                            G of Part 75


Institute of Internal Auditors, Inc.

  249 Maitland Avenue, Altamonte Springs, FL 32701-4201
Codification of Standards for the Professional 
  Practice of Internal Auditing, 1989, 
  Identification Number ISBN 0-89413-207-5........                80.125


International Organization for Standardization

  Case Postale 56, CH-1211 Geneve 20, Switzerland
ISO 8316: 1987(E), Measurement of Liquid Flow in 
  Closed Conduits--Method of Collection of the 
  Liquid in a Volumetric Tank.....................  75.20; Appendices D 
                                                        and E of Part 75
ISO 9931 (December 1991), Coal--Sampling of 
  Pulverized Coal Conveyed by Gases in Direct 
  Fired Coal Systems..............................           76.4; 76.15


U.S. Government Printing Office

  Washington, DC 20402-9371; Telephone: 202-512-1800; Telefacsimile: 
  202-275-0019
U.S. Department of Health and Human Services, 
  Guide for the Care and Use of Laboratory 
  Animals, 1985................................... 79.61(c)(3), (d)(2), 
                                                              and (d)(4)



[[Page 685]]



                    Table of CFR Titles and Chapters




                      (Revised as of June 30, 1996)

                      Title 1--General Provisions

         I  Administrative Committee of the Federal Register 
                (Parts 1--49)
        II  Office of the Federal Register (Parts 50--299)
        IV  Miscellaneous Agencies (Parts 400--500)

                          Title 2--[Reserved]

                        Title 3--The President

         I  Executive Office of the President (Parts 100--199)

                           Title 4--Accounts

         I  General Accounting Office (Parts 1--99)
        II  Federal Claims Collection Standards (General 
                Accounting Office--Department of Justice) (Parts 
                100--299)

                   Title 5--Administrative Personnel

         I  Office of Personnel Management (Parts 1--1199)
        II  Merit Systems Protection Board (Parts 1200--1299)
       III  Office of Management and Budget (Parts 1300--1399)
        IV  Advisory Committee on Federal Pay (Parts 1400--1499)
         V  The International Organizations Employees Loyalty 
                Board (Parts 1500--1599)
        VI  Federal Retirement Thrift Investment Board (Parts 
                1600--1699)
       VII  Advisory Commission on Intergovernmental Relations 
                (Parts 1700--1799)
      VIII  Office of Special Counsel (Parts 1800--1899)
        IX  Appalachian Regional Commission (Parts 1900--1999)
        XI  Armed Forces Retirement Home (Part 2100)
       XIV  Federal Labor Relations Authority, General Counsel of 
                the Federal Labor Relations Authority and Federal 
                Service Impasses Panel (Parts 2400--2499)
        XV  Office of Administration, Executive Office of the 
                President (Parts 2500--2599)
       XVI  Office of Government Ethics (Parts 2600--2699)
       XXI  Department of the Treasury (Parts 3100--3199)
      XXII  Federal Deposit Insurance Corporation (Part 3202)
      XXVI  Department of Defense (Part 3601)

[[Page 686]]

       XXX  Farm Credit System Insurance Corporation (Parts 4000--
                4099)
      XXXI  Farm Credit Administration (Parts 4100--4199)
    XXXIII  Overseas Private Investment Corporation (Part 4301)
        XL  Interstate Commerce Commission (Part 5001)
       XLI  Commodity Futures Trading Commission (Part 5101)
      XLVI  Postal Rate Commission (Part 5601)
     XLVII  Federal Trade Commission (Part 5701)
    XLVIII  Nuclear Regulatory Commission (Part 5801)
       LII  Export-Import Bank of the United States (Part 6201)
      LIII  Department of Education (Parts 6300--6399)
       LIX  National Aeronautics and Space Administration (Part 
                6901)
        LX  United States Postal Service (Part 7001)
      LXII  Equal Employment Opportunity Commission (Part 7201)
     LXIII  Inter-American Foundation (Part 7301)
      LXIX  Tennessee Valley Authority (Part 7901)
     LXXVI  Federal Retirement Thrift Investment Board (Part 8601)
    LXXVII  Office of Management and Budget (Part 8701)

                          Title 6--[Reserved]

                         Title 7--Agriculture

            Subtitle A--Office of the Secretary of Agriculture 
                (Parts 0--26)
            Subtitle B--Regulations of the Department of 
                Agriculture
         I  Agricultural Marketing Service (Standards, 
                Inspections, Marketing Practices), Department of 
                Agriculture (Parts 27--209)
        II  Food and Consumer Service, Department of Agriculture 
                (Parts 210--299)
       III  Animal and Plant Health Inspection Service, Department 
                of Agriculture (Parts 300--399)
        IV  Federal Crop Insurance Corporation, Department of 
                Agriculture (Parts 400--499)
         V  Agricultural Research Service, Department of 
                Agriculture (Parts 500--599)
        VI  Natural Resources Conservation Service, Department of 
                Agriculture (Parts 600--699)
       VII  Farm Service Agency, Department of Agriculture (Parts 
                700--799)
      VIII  Grain Inspection, Packers and Stockyards 
                Administration (Federal Grain Inspection Service), 
                Department of Agriculture (Parts 800--899)
        IX  Agricultural Marketing Service (Marketing Agreements 
                and Orders; Fruits, Vegetables, Nuts), Department 
                of Agriculture (Parts 900--999)
         X  Agricultural Marketing Service (Marketing Agreements 
                and Orders; Milk), Department of Agriculture 
                (Parts 1000--1199)
        XI  Agricultural Marketing Service (Marketing Agreements 
                and Orders; Miscellaneous Commodities), Department 
                of Agriculture (Parts 1200--1299)

[[Page 687]]

       XIV  Commodity Credit Corporation, Department of 
                Agriculture (Parts 1400--1499)
        XV  Foreign Agricultural Service, Department of 
                Agriculture (Parts 1500--1599)
       XVI  Rural Telephone Bank, Department of Agriculture (Parts 
                1600--1699)
      XVII  Rural Utilities Service, Department of Agriculture 
                (Parts 1700--1799)
     XVIII  Rural Housing Service, Rural Business-Cooperative 
                Service, Rural Utilities Service, and Farm Service 
                Agency, Department of Agriculture (Parts 1800--
                2099)
      XXVI  Office of Inspector General, Department of Agriculture 
                (Parts 2600--2699)
     XXVII  Office of Information Resources Management, Department 
                of Agriculture (Parts 2700--2799)
    XXVIII  Office of Operations, Department of Agriculture (Parts 
                2800--2899)
      XXIX  Office of Energy, Department of Agriculture (Parts 
                2900--2999)
       XXX  Office of Finance and Management, Department of 
                Agriculture (Parts 3000--3099)
      XXXI  Office of Environmental Quality, Department of 
                Agriculture (Parts 3100--3199)
     XXXII  [Reserved]
    XXXIII  Office of Transportation, Department of Agriculture 
                (Parts 3300--3399)
     XXXIV  Cooperative State Research, Education, and Extension 
                Service, Department of Agriculture (Parts 3400--
                3499)
     XXXVI  National Agricultural Statistics Service, Department 
                of Agriculture (Parts 3600--3699)
    XXXVII  Economic Research Service, Department of Agriculture 
                (Parts 3700--3799)
   XXXVIII  World Agricultural Outlook Board, Department of 
                Agriculture (Parts 3800--3899)
     XXXIX  Economic Analysis Staff, Department of Agriculture 
                (Parts 3900--3999)
        XL  Economics Management Staff, Department of Agriculture 
                (Parts 4000--4099)
       XLI  [Reserved]
      XLII  Rural Business-Cooperative Service and Rural Utilities 
                Service, Department of Agriculture (Parts 4200--
                4299)

                    Title 8--Aliens and Nationality

         I  Immigration and Naturalization Service, Department of 
                Justice (Parts 1--499)

                 Title 9--Animals and Animal Products

         I  Animal and Plant Health Inspection Service, Department 
                of Agriculture (Parts 1--199)

[[Page 688]]

        II  Grain Inspection, Packers and Stockyards 
                Administration (Packers and Stockyards Programs), 
                Department of Agriculture (Parts 200--299)
       III  Food Safety and Inspection Service, Meat and Poultry 
                Inspection, Department of Agriculture (Parts 300--
                399)

                           Title 10--Energy

         I  Nuclear Regulatory Commission (Parts 0--199)
        II  Department of Energy (Parts 200--699)
       III  Department of Energy (Parts 700--999)
         X  Department of Energy (General Provisions) (Parts 
                1000--1099)
        XI  United States Enrichment Corporation (Parts 1100--
                1199)
        XV  Office of the Federal Inspector for the Alaska Natural 
                Gas Transportation System (Parts 1500--1599)
      XVII  Defense Nuclear Facilities Safety Board (Parts 1700--
                1799)

                      Title 11--Federal Elections

         I  Federal Election Commission (Parts 1--9099)

                      Title 12--Banks and Banking

         I  Comptroller of the Currency, Department of the 
                Treasury (Parts 1--199)
        II  Federal Reserve System (Parts 200--299)
       III  Federal Deposit Insurance Corporation (Parts 300--399)
        IV  Export-Import Bank of the United States (Parts 400--
                499)
         V  Office of Thrift Supervision, Department of the 
                Treasury (Parts 500--599)
        VI  Farm Credit Administration (Parts 600--699)
       VII  National Credit Union Administration (Parts 700--799)
      VIII  Federal Financing Bank (Parts 800--899)
        IX  Federal Housing Finance Board (Parts 900--999)
        XI  Federal Financial Institutions Examination Council 
                (Parts 1100--1199)
       XIV  Farm Credit System Insurance Corporation (Parts 1400--
                1499)
        XV  Thrift Depositor Protection Oversight Board (Parts 
                1500--1599)
      XVII  Office of Federal Housing Enterprise Oversight, 
                Department of Housing and Urban Development (Parts 
                1700-1799)
     XVIII  Community Development Financial Institutions Fund, 
                Department of the Treasury (Parts 1800--1899)

               Title 13--Business Credit and Assistance

         I  Small Business Administration (Parts 1--199)
       III  Economic Development Administration, Department of 
                Commerce (Parts 300--399)

[[Page 689]]

                    Title 14--Aeronautics and Space

         I  Federal Aviation Administration, Department of 
                Transportation (Parts 1--199)
        II  Office of the Secretary, Department of Transportation 
                (Aviation Proceedings) (Parts 200--399)
       III  Office of Commercial Space Transportation, Department 
                of Transportation (Parts 400--499)
         V  National Aeronautics and Space Administration (Parts 
                1200--1299)

                 Title 15--Commerce and Foreign Trade

            Subtitle A--Office of the Secretary of Commerce (Parts 
                0--29)
            Subtitle B--Regulations Relating to Commerce and 
                Foreign Trade
         I  Bureau of the Census, Department of Commerce (Parts 
                30--199)
        II  National Institute of Standards and Technology, 
                Department of Commerce (Parts 200--299)
       III  International Trade Administration, Department of 
                Commerce (Parts 300--399)
        IV  Foreign-Trade Zones Board, Department of Commerce 
                (Parts 400--499)
       VII  Bureau of Export Administration, Department of 
                Commerce (Parts 700--799)
      VIII  Bureau of Economic Analysis, Department of Commerce 
                (Parts 800--899)
        IX  National Oceanic and Atmospheric Administration, 
                Department of Commerce (Parts 900--999)
        XI  Technology Administration, Department of Commerce 
                (Parts 1100--1199)
      XIII  East-West Foreign Trade Board (Parts 1300--1399)
       XIV  Minority Business Development Agency (Parts 1400--
                1499)
            Subtitle C--Regulations Relating to Foreign Trade 
                Agreements
        XX  Office of the United States Trade Representative 
                (Parts 2000--2099)
            Subtitle D--Regulations Relating to Telecommunications 
                and Information
     XXIII  National Telecommunications and Information 
                Administration, Department of Commerce (Parts 
                2300--2399)

                    Title 16--Commercial Practices

         I  Federal Trade Commission (Parts 0--999)
        II  Consumer Product Safety Commission (Parts 1000--1799)

             Title 17--Commodity and Securities Exchanges

         I  Commodity Futures Trading Commission (Parts 1--199)
        II  Securities and Exchange Commission (Parts 200--399)
        IV  Department of the Treasury (Parts 400--499)

[[Page 690]]

          Title 18--Conservation of Power and Water Resources

         I  Federal Energy Regulatory Commission, Department of 
                Energy (Parts 1--399)
       III  Delaware River Basin Commission (Parts 400--499)
        VI  Water Resources Council (Parts 700--799)
      VIII  Susquehanna River Basin Commission (Parts 800--899)
      XIII  Tennessee Valley Authority (Parts 1300--1399)

                       Title 19--Customs Duties

         I  United States Customs Service, Department of the 
                Treasury (Parts 1--199)
        II  United States International Trade Commission (Parts 
                200--299)
       III  International Trade Administration, Department of 
                Commerce (Parts 300--399)

                     Title 20--Employees' Benefits

         I  Office of Workers' Compensation Programs, Department 
                of Labor (Parts 1--199)
        II  Railroad Retirement Board (Parts 200--399)
       III  Social Security Administration (Parts 400--499)
        IV  Employees' Compensation Appeals Board, Department of 
                Labor (Parts 500--599)
         V  Employment and Training Administration, Department of 
                Labor (Parts 600--699)
        VI  Employment Standards Administration, Department of 
                Labor (Parts 700--799)
       VII  Benefits Review Board, Department of Labor (Parts 
                800--899)
      VIII  Joint Board for the Enrollment of Actuaries (Parts 
                900--999)
        IX  Office of the Assistant Secretary for Veterans' 
                Employment and Training, Department of Labor 
                (Parts 1000--1099)

                       Title 21--Food and Drugs

         I  Food and Drug Administration, Department of Health and 
                Human Services (Parts 1--1299)
        II  Drug Enforcement Administration, Department of Justice 
                (Parts 1300--1399)
       III  Office of National Drug Control Policy (Parts 1400--
                1499)

                      Title 22--Foreign Relations

         I  Department of State (Parts 1--199)
        II  Agency for International Development, International 
                Development Cooperation Agency (Parts 200--299)
       III  Peace Corps (Parts 300--399)
        IV  International Joint Commission, United States and 
                Canada (Parts 400--499)
         V  United States Information Agency (Parts 500--599)

[[Page 691]]

        VI  United States Arms Control and Disarmament Agency 
                (Parts 600--699)
       VII  Overseas Private Investment Corporation, International 
                Development Cooperation Agency (Parts 700--799)
        IX  Foreign Service Grievance Board Regulations (Parts 
                900--999)
         X  Inter-American Foundation (Parts 1000--1099)
        XI  International Boundary and Water Commission, United 
                States and Mexico, United States Section (Parts 
                1100--1199)
       XII  United States International Development Cooperation 
                Agency (Parts 1200--1299)
      XIII  Board for International Broadcasting (Parts 1300--
                1399)
       XIV  Foreign Service Labor Relations Board; Federal Labor 
                Relations Authority; General Counsel of the 
                Federal Labor Relations Authority; and the Foreign 
                Service Impasse Disputes Panel (Parts 1400--1499)
        XV  African Development Foundation (Parts 1500--1599)
       XVI  Japan-United States Friendship Commission (Parts 
                1600--1699)
      XVII  United States Institute of Peace (Parts 1700--1799)

                          Title 23--Highways

         I  Federal Highway Administration, Department of 
                Transportation (Parts 1--999)
        II  National Highway Traffic Safety Administration and 
                Federal Highway Administration, Department of 
                Transportation (Parts 1200--1299)
       III  National Highway Traffic Safety Administration, 
                Department of Transportation (Parts 1300--1399)

                Title 24--Housing and Urban Development

            Subtitle A--Office of the Secretary, Department of 
                Housing and Urban Development (Parts 0--99)
            Subtitle B--Regulations Relating to Housing and Urban 
                Development
         I  Office of Assistant Secretary for Equal Opportunity, 
                Department of Housing and Urban Development (Parts 
                100--199)
        II  Office of Assistant Secretary for Housing-Federal 
                Housing Commissioner, Department of Housing and 
                Urban Development (Parts 200--299)
       III  Government National Mortgage Association, Department 
                of Housing and Urban Development (Parts 300--399)
         V  Office of Assistant Secretary for Community Planning 
                and Development, Department of Housing and Urban 
                Development (Parts 500--599)
        VI  Office of Assistant Secretary for Community Planning 
                and Development, Department of Housing and Urban 
                Development (Parts 600--699) [Reserved]
       VII  Office of the Secretary, Department of Housing and 
                Urban Development (Housing Assistance Programs and 
                Public and Indian Housing Programs) (Parts 700--
                799)

[[Page 692]]

      VIII  Office of the Assistant Secretary for Housing--Federal 
                Housing Commissioner, Department of Housing and 
                Urban Development (Section 8 Housing Assistance 
                Programs and Section 202 Direct Loan Program) 
                (Parts 800--899)
        IX  Office of Assistant Secretary for Public and Indian 
                Housing, Department of Housing and Urban 
                Development (Parts 900--999)
         X  Office of Assistant Secretary for Housing--Federal 
                Housing Commissioner, Department of Housing and 
                Urban Development (Interstate Land Sales 
                Registration Program) (Parts 1700--1799)
       XII  Office of Inspector General, Department of Housing and 
                Urban Development (Parts 2000--2099)
        XX  Office of Assistant Secretary for Housing--Federal 
                Housing Commissioner, Department of Housing and 
                Urban Development (Parts 3200--3699)
       XXV  Neighborhood Reinvestment Corporation (Parts 4100--
                4199)

                           Title 25--Indians

         I  Bureau of Indian Affairs, Department of the Interior 
                (Parts 1--299)
        II  Indian Arts and Crafts Board, Department of the 
                Interior (Parts 300--399)
       III  National Indian Gaming Commission, Department of the 
                Interior (Parts 500--599)
        IV  Office of Navajo and Hopi Indian Relocation (Parts 
                700--799)
         V  Bureau of Indian Affairs, Department of the Interior, 
                and Indian Health Service, Department of Health 
                and Human Services (Part 900)
        VI  Office of the Assistant Secretary-Indian Affairs, 
                Department of the Interior (Part 1001)

                      Title 26--Internal Revenue

         I  Internal Revenue Service, Department of the Treasury 
                (Parts 1--799)

           Title 27--Alcohol, Tobacco Products and Firearms

         I  Bureau of Alcohol, Tobacco and Firearms, Department of 
                the Treasury (Parts 1--299)

                   Title 28--Judicial Administration

         I  Department of Justice (Parts 0--199)
       III  Federal Prison Industries, Inc., Department of Justice 
                (Parts 300--399)
         V  Bureau of Prisons, Department of Justice (Parts 500--
                599)
        VI  Offices of Independent Counsel, Department of Justice 
                (Parts 600--699)
       VII  Office of Independent Counsel (Parts 700--799)

[[Page 693]]

                            Title 29--Labor

            Subtitle A--Office of the Secretary of Labor (Parts 
                0--99)
            Subtitle B--Regulations Relating to Labor
         I  National Labor Relations Board (Parts 100--199)
        II  Office of Labor-Management Programs, Department of 
                Labor (Parts 200--299)
       III  National Railroad Adjustment Board (Parts 300--399)
        IV  Office of Labor-Management Standards, Department of 
                Labor (Parts 400--499)
         V  Wage and Hour Division, Department of Labor (Parts 
                500--899)
        IX  Construction Industry Collective Bargaining Commission 
                (Parts 900--999)
         X  National Mediation Board (Parts 1200--1299)
       XII  Federal Mediation and Conciliation Service (Parts 
                1400--1499)
       XIV  Equal Employment Opportunity Commission (Parts 1600--
                1699)
      XVII  Occupational Safety and Health Administration, 
                Department of Labor (Parts 1900--1999)
        XX  Occupational Safety and Health Review Commission 
                (Parts 2200--2499)
       XXV  Pension and Welfare Benefits Administration, 
                Department of Labor (Parts 2500--2599)
      XXVI  Pension Benefit Guaranty Corporation (Parts 2600--
                2699)
     XXVII  Federal Mine Safety and Health Review Commission 
                (Parts 2700--2799)

                      Title 30--Mineral Resources

         I  Mine Safety and Health Administration, Department of 
                Labor (Parts 1--199)
        II  Minerals Management Service, Department of the 
                Interior (Parts 200--299)
       III  Board of Surface Mining and Reclamation Appeals, 
                Department of the Interior (Parts 300--399)
        IV  Geological Survey, Department of the Interior (Parts 
                400--499)
        VI  Bureau of Mines, Department of the Interior (Parts 
                600--699)
       VII  Office of Surface Mining Reclamation and Enforcement, 
                Department of the Interior (Parts 700--999)

                 Title 31--Money and Finance: Treasury

            Subtitle A--Office of the Secretary of the Treasury 
                (Parts 0--50)
            Subtitle B--Regulations Relating to Money and Finance
         I  Monetary Offices, Department of the Treasury (Parts 
                51--199)
        II  Fiscal Service, Department of the Treasury (Parts 
                200--399)
        IV  Secret Service, Department of the Treasury (Parts 
                400--499)
         V  Office of Foreign Assets Control, Department of the 
                Treasury (Parts 500--599)
        VI  Bureau of Engraving and Printing, Department of the 
                Treasury (Parts 600--699)

[[Page 694]]

       VII  Federal Law Enforcement Training Center, Department of 
                the Treasury (Parts 700--799)
      VIII  Office of International Investment, Department of the 
                Treasury (Parts 800--899)

                      Title 32--National Defense

            Subtitle A--Department of Defense
         I  Office of the Secretary of Defense (Parts 1--399)
         V  Department of the Army (Parts 400--699)
        VI  Department of the Navy (Parts 700--799)
       VII  Department of the Air Force (Parts 800--1099)
            Subtitle B--Other Regulations Relating to National 
                Defense
       XII  Defense Logistics Agency (Parts 1200--1299)
       XVI  Selective Service System (Parts 1600--1699)
       XIX  Central Intelligence Agency (Parts 1900--1999)
        XX  Information Security Oversight Office, National 
                Archives and Records Administration (Parts 2000--
                2099)
       XXI  National Security Council (Parts 2100--2199)
      XXIV  Office of Science and Technology Policy (Parts 2400--
                2499)
     XXVII  Office for Micronesian Status Negotiations (Parts 
                2700--2799)
    XXVIII  Office of the Vice President of the United States 
                (Parts 2800--2899)
      XXIX  Presidential Commission on the Assignment of Women in 
                the Armed Forces (Part 2900)

               Title 33--Navigation and Navigable Waters

         I  Coast Guard, Department of Transportation (Parts 1--
                199)
        II  Corps of Engineers, Department of the Army (Parts 
                200--399)
        IV  Saint Lawrence Seaway Development Corporation, 
                Department of Transportation (Parts 400--499)

                          Title 34--Education

            Subtitle A--Office of the Secretary, Department of 
                Education (Parts 1--99)
            Subtitle B--Regulations of the Offices of the 
                Department of Education
         I  Office for Civil Rights, Department of Education 
                (Parts 100--199)
        II  Office of Elementary and Secondary Education, 
                Department of Education (Parts 200--299)
       III  Office of Special Education and Rehabilitative 
                Services, Department of Education (Parts 300--399)
        IV  Office of Vocational and Adult Education, Department 
                of Education (Parts 400--499)
         V  Office of Bilingual Education and Minority Languages 
                Affairs, Department of Education (Parts 500--599)
        VI  Office of Postsecondary Education, Department of 
                Education (Parts 600--699)

[[Page 695]]

       VII  Office of Educational Research and Improvement, 
                Department of Education (Parts 700--799)
        XI  National Institute for Literacy (Parts 1100-1199)
            Subtitle C--Regulations Relating to Education
       XII  National Council on Disability (Parts 1200--1299)

                        Title 35--Panama Canal

         I  Panama Canal Regulations (Parts 1--299)

             Title 36--Parks, Forests, and Public Property

         I  National Park Service, Department of the Interior 
                (Parts 1--199)
        II  Forest Service, Department of Agriculture (Parts 200--
                299)
       III  Corps of Engineers, Department of the Army (Parts 
                300--399)
        IV  American Battle Monuments Commission (Parts 400--499)
         V  Smithsonian Institution (Parts 500--599)
       VII  Library of Congress (Parts 700--799)
      VIII  Advisory Council on Historic Preservation (Parts 800--
                899)
        IX  Pennsylvania Avenue Development Corporation (Parts 
                900--999)
        XI  Architectural and Transportation Barriers Compliance 
                Board (Parts 1100--1199)
       XII  National Archives and Records Administration (Parts 
                1200--1299)
       XIV  Assassination Records Review Board (Parts 1400-1499)

             Title 37--Patents, Trademarks, and Copyrights

         I  Patent and Trademark Office, Department of Commerce 
                (Parts 1--199)
        II  Copyright Office, Library of Congress (Parts 200--299)
        IV  Assistant Secretary for Technology Policy, Department 
                of Commerce (Parts 400--499)
         V  Under Secretary for Technology, Department of Commerce 
                (Parts 500--599)

           Title 38--Pensions, Bonuses, and Veterans' Relief

         I  Department of Veterans Affairs (Parts 0--99)

                       Title 39--Postal Service

         I  United States Postal Service (Parts 1--999)
       III  Postal Rate Commission (Parts 3000--3099)

                  Title 40--Protection of Environment

         I  Environmental Protection Agency (Parts 1--799)
         V  Council on Environmental Quality (Parts 1500--1599)

[[Page 696]]

          Title 41--Public Contracts and Property Management

            Subtitle B--Other Provisions Relating to Public 
                Contracts
        50  Public Contracts, Department of Labor (Parts 50-1--50-
                999)
        51  Committee for Purchase From People Who Are Blind or 
                Severely Disabled (Parts 51-1--51-99)
        60  Office of Federal Contract Compliance Programs, Equal 
                Employment Opportunity, Department of Labor (Parts 
                60-1--60-999)
        61  Office of the Assistant Secretary for Veterans 
                Employment and Training, Department of Labor 
                (Parts 61-1--61-999)
            Subtitle C--Federal Property Management Regulations 
                System
       101  Federal Property Management Regulations (Parts 101-1--
                101-99)
       105  General Services Administration (Parts 105-1--105-999)
       109  Department of Energy Property Management Regulations 
                (Parts 109-1--109-99)
       114  Department of the Interior (Parts 114-1--114-99)
       115  Environmental Protection Agency (Parts 115-1--115-99)
       128  Department of Justice (Parts 128-1--128-99)
            Subtitle D--Other Provisions Relating to Property 
                Management [Reserved]
            Subtitle E--Federal Information Resources Management 
                Regulations System
       201  Federal Information Resources Management Regulation 
                (Parts 201-1--201-99)
            Subtitle F--Federal Travel Regulation System
       301  Travel Allowances (Parts 301-1--301-99)
       302  Relocation Allowances (Parts 302-1--302-99)
       303  Payment of Expenses Connected with the Death of 
                Certain Employees (Parts 303-1--303-2)
       304  Payment from a Non-Federal Source for Travel Expenses 
                (Parts 304-1--304-99)

                        Title 42--Public Health

         I  Public Health Service, Department of Health and Human 
                Services (Parts 1--199)
        IV  Health Care Financing Administration, Department of 
                Health and Human Services (Parts 400--499)
         V  Office of Inspector General-Health Care, Department of 
                Health and Human Services (Parts 1000--1999)

                   Title 43--Public Lands: Interior

            Subtitle A--Office of the Secretary of the Interior 
                (Parts 1--199)
            Subtitle B--Regulations Relating to Public Lands
         I  Bureau of Reclamation, Department of the Interior 
                (Parts 200--499)
        II  Bureau of Land Management, Department of the Interior 
                (Parts 1000--9999)
       III  Utah Reclamation Mitigation and Conservation 
                Commission (Parts 10000--10005)

[[Page 697]]

             Title 44--Emergency Management and Assistance

         I  Federal Emergency Management Agency (Parts 0--399)
        IV  Department of Commerce and Department of 
                Transportation (Parts 400--499)

                       Title 45--Public Welfare

            Subtitle A--Department of Health and Human Services, 
                General Administration (Parts 1--199)
            Subtitle B--Regulations Relating to Public Welfare
        II  Office of Family Assistance (Assistance Programs), 
                Administration for Children and Families, 
                Department of Health and Human Services (Parts 
                200--299)
       III  Office of Child Support Enforcement (Child Support 
                Enforcement Program), Administration for Children 
                and Families, Department of Health and Human 
                Services (Parts 300--399)
        IV  Office of Refugee Resettlement, Administration for 
                Children and Families Department of Health and 
                Human Services (Parts 400--499)
         V  Foreign Claims Settlement Commission of the United 
                States, Department of Justice (Parts 500--599)
        VI  National Science Foundation (Parts 600--699)
       VII  Commission on Civil Rights (Parts 700--799)
      VIII  Office of Personnel Management (Parts 800--899)
         X  Office of Community Services, Administration for 
                Children and Families, Department of Health and 
                Human Services (Parts 1000--1099)
        XI  National Foundation on the Arts and the Humanities 
                (Parts 1100--1199)
       XII  ACTION (Parts 1200--1299)
      XIII  Office of Human Development Services, Department of 
                Health and Human Services (Parts 1300--1399)
       XVI  Legal Services Corporation (Parts 1600--1699)
      XVII  National Commission on Libraries and Information 
                Science (Parts 1700--1799)
     XVIII  Harry S. Truman Scholarship Foundation (Parts 1800--
                1899)
       XXI  Commission on Fine Arts (Parts 2100--2199)
      XXII  Christopher Columbus Quincentenary Jubilee Commission 
                (Parts 2200--2299)
     XXIII  Arctic Research Commission (Part 2301)
      XXIV  James Madison Memorial Fellowship Foundation (Parts 
                2400--2499)
       XXV  Corporation for National and Community Service (Parts 
                2500--2599)

                          Title 46--Shipping

         I  Coast Guard, Department of Transportation (Parts 1--
                199)
        II  Maritime Administration, Department of Transportation 
                (Parts 200--399)
        IV  Federal Maritime Commission (Parts 500--599)

[[Page 698]]

                      Title 47--Telecommunication

         I  Federal Communications Commission (Parts 0--199)
        II  Office of Science and Technology Policy and National 
                Security Council (Parts 200--299)
       III  National Telecommunications and Information 
                Administration, Department of Commerce (Parts 
                300--399)

           Title 48--Federal Acquisition Regulations System

         1  Federal Acquisition Regulation (Parts 1--99)
         2  Department of Defense (Parts 200--299)
         3  Department of Health and Human Services (Parts 300--
                399)
         4  Department of Agriculture (Parts 400--499)
         5  General Services Administration (Parts 500--599)
         6  Department of State (Parts 600--699)
         7  Agency for International Development (Parts 700--799)
         8  Department of Veterans Affairs (Parts 800--899)
         9  Department of Energy (Parts 900--999)
        10  Department of the Treasury (Parts 1000--1099)
        12  Department of Transportation (Parts 1200--1299)
        13  Department of Commerce (Parts 1300--1399)
        14  Department of the Interior (Parts 1400--1499)
        15  Environmental Protection Agency (Parts 1500--1599)
        16  Office of Personnel Management Federal Employees 
                Health Benefits Acquisition Regulation (Parts 
                1600--1699)
        17  Office of Personnel Management (Parts 1700--1799)
        18  National Aeronautics and Space Administration (Parts 
                1800--1899)
        19  United States Information Agency (Parts 1900--1999)
        20  Nuclear Regulatory Commission (Parts 2000--2099)
        21  Office of Personnel Management, Federal Employees 
                Group Life Insurance Federal Acquisition 
                Regulation (Parts 2100--2199)
        22  Small Business Administration (Parts 2200--2299)
        24  Department of Housing and Urban Development (Parts 
                2400--2499)
        25  National Science Foundation (Parts 2500--2599)
        28  Department of Justice (Parts 2800--2899)
        29  Department of Labor (Parts 2900--2999)
        34  Department of Education Acquisition Regulation (Parts 
                3400--3499)
        35  Panama Canal Commission (Parts 3500--3599)
        44  Federal Emergency Management Agency (Parts 4400--4499)
        51  Department of the Army Acquisition Regulations (Parts 
                5100--5199)
        52  Department of the Navy Acquisition Regulations (Parts 
                5200--5299)
        53  Department of the Air Force Federal Acquisition 
                Regulation Supplement (Parts 5300--5399)
        54  Defense Logistics Agency, Department of Defense (Part 
                5452)

[[Page 699]]

        57  African Development Foundation (Parts 5700--5799)
        61  General Services Administration Board of Contract 
                Appeals (Parts 6100--6199)
        63  Department of Transportation Board of Contract Appeals 
                (Parts 6300--6399)
        99  Cost Accounting Standards Board, Office of Federal 
                Procurement Policy, Office of Management and 
                Budget (Parts 9900--9999)

                       Title 49--Transportation

            Subtitle A--Office of the Secretary of Transportation 
                (Parts 1--99)
            Subtitle B--Other Regulations Relating to 
                Transportation
         I  Research and Special Programs Administration, 
                Department of Transportation (Parts 100--199)
        II  Federal Railroad Administration, Department of 
                Transportation (Parts 200--299)
       III  Federal Highway Administration, Department of 
                Transportation (Parts 300--399)
        IV  Coast Guard, Department of Transportation (Parts 400--
                499)
         V  National Highway Traffic Safety Administration, 
                Department of Transportation (Parts 500--599)
        VI  Federal Transit Administration, Department of 
                Transportation (Parts 600--699)
       VII  National Railroad Passenger Corporation (AMTRAK) 
                (Parts 700--799)
      VIII  National Transportation Safety Board (Parts 800--999)
         X  Surface Transportation Board, Department of 
                Transportation (Parts 1000--1399)

                   Title 50--Wildlife and Fisheries

         I  United States Fish and Wildlife Service, Department of 
                the Interior (Parts 1--199)
        II  National Marine Fisheries Service, National Oceanic 
                and Atmospheric Administration, Department of 
                Commerce (Parts 200--299)
       III  International Regulatory Agencies (Fishing and 
                Whaling) (Parts 300--399)
        IV  Joint Regulations (United States Fish and Wildlife 
                Service, Department of the Interior and National 
                Marine Fisheries Service, National Oceanic and 
                Atmospheric Administration, Department of 
                Commerce); Endangered Species Committee 
                Regulations (Parts 400--499)
         V  Marine Mammal Commission (Parts 500--599)
        VI  Fishery Conservation and Management, National Oceanic 
                and Atmospheric Administration, Department of 
                Commerce (Parts 600--699)

[[Page 700]]

                      CFR Index and Finding Aids

            Subject/Agency Index
            List of Agency Prepared Indexes
            Parallel Tables of Statutory Authorities and Rules
            Acts Requiring Publication in the Federal Register
            List of CFR Titles, Chapters, Subchapters, and Parts
            Alphabetical List of Agencies Appearing in the CFR



[[Page 701]]





           Alphabetical List of Agencies Appearing in the CFR




                      (Revised as of June 30, 1996)

                                                  CFR Title, Subtitle or
                     Agency                               Chapter

ACTION                                            45, XII
Administrative Committee of the Federal Register  1, I
Advanced Research Projects Agency                 32, I
Advisory Commission on Intergovernmental          5, VII
     Relations
Advisory Committee on Federal Pay                 5, IV
Advisory Council on Historic Preservation         36, VIII
African Development Foundation                    22, XV
  Federal Acquisition Regulation                  48, 57
Agency for International Development              22, II
  Federal Acquisition Regulation                  48, 7
Agricultural Marketing Service                    7, I, IX, X, XI
Agricultural Research Service                     7, V
Agriculture Department
  Agricultural Marketing Service                  7, I, IX, X, XI
  Agricultural Research Service                   7, V
  Animal and Plant Health Inspection Service      7, III; 9, I
  Commodity Credit Corporation                    7, XIV
  Cooperative State Research, Education, and      7, XXXIV
       Extension Service
  Economic Analysis Staff                         7, XXXIX
  Economic Research Service                       7, XXXVII
  Economics Management Staff                      7, XL
  Energy, Office of                               7, XXIX
  Environmental Quality, Office of                7, XXXI
  Farm Service Agency                             7, VII, XVIII
  Federal Acquisition Regulation                  48, 4
  Federal Crop Insurance Corporation              7, IV
  Finance and Management, Office of               7, XXX
  Food and Consumer Service                       7, II
  Food Safety and Inspection Service              9, III
  Foreign Agricultural Service                    7, XV
  Forest Service                                  36, II
  Grain Inspection, Packers and Stockyards        7, VIII; 9, II
       Administration
  Information Resources Management, Office of     7, XXVII
  Inspector General, Office of                    7, XXVI
  National Agricultural Library                   7, XLI
  National Agricultural Statistics Service        7, XXXVI
  Natural Resources Conservation Service          7, VI
  Operations, Office of                           7, XXVIII
  Rural Business-Cooperative Service              7, XVIII, XLII
  Rural Development Administration                7, XLII
  Rural Housing Service                           7, XVIII
  Rural Telephone Bank                            7, XVI
  Rural Utilities Service                         7, XVII, XVIII, XLII
  Secretary of Agriculture, Office of             7, Subtitle A
  Transportation, Office of                       7, XXXIII
  World Agricultural Outlook Board                7, XXXVIII
Air Force Department                              32, VII
  Federal Acquisition Regulation Supplement       48, 53
Alaska Natural Gas Transportation System, Office  10, XV
     of the Federal Inspector
Alcohol, Tobacco and Firearms, Bureau of          27, I
AMTRAK                                            49, VII

[[Page 702]]

American Battle Monuments Commission              36, IV
Animal and Plant Health Inspection Service        7, III; 9, I
Appalachian Regional Commission                   5, IX
Architectural and Transportation Barriers         36, XI
     Compliance Board
Arctic Research Commission                        45, XXIII
Arms Control and Disarmament Agency, United       22, VI
     States
Army Department                                   32, V
  Engineers, Corps of                             33, II; 36, III
  Federal Acquisition Regulation                  48, 51
Assassination Records Review Board                36, XIV
Benefits Review Board                             20, VII
Bilingual Education and Minority Languages        34, V
     Affairs, Office of
Blind or Severely Disabled, Committee for         41, 51
     Purchase From People Who Are
Board for International Broadcasting              22, XIII
Census Bureau                                     15, I
Central Intelligence Agency                       32, XIX
Child Support Enforcement, Office of              45, III
Children and Families, Administration for         45, II, III, IV, X
Christopher Columbus Quincentenary Jubilee        45, XXII
     Commission
Civil Rights, Commission on                       45, VII
Civil Rights, Office for                          34, I
Coast Guard                                       33, I; 46, I; 49, IV
Commerce Department                               44, IV
  Census Bureau                                   15, I`
  Economic Affairs, Under Secretary               37, V
  Economic Analysis, Bureau of                    15, VIII
  Economic Development Administration             13, III
  Emergency Management and Assistance             44, IV
  Export Administration, Bureau of                15, VII
  Federal Acquisition Regulation                  48, 13
  Fishery Conservation and Management             50, VI
  Foreign-Trade Zones Board                       15, IV
  International Trade Administration              15, III; 19, III
  National Institute of Standards and Technology  15, II
  National Marine Fisheries Service               50, II, IV
  National Oceanic and Atmospheric                15, IX; 50, II, III, IV, 
       Administration                             VI
  National Telecommunications and Information     15, XXIII; 47, III
       Administration
  National Weather Service                        15, IX
  Patent and Trademark Office                     37, I
  Productivity, Technology and Innovation,        37, IV
       Assistant Secretary for
  Secretary of Commerce, Office of                15, Subtitle A
  Technology, Under Secretary for                 37, V
  Technology Administration                       15, XI
  Technology Policy, Assistant Secretary for      37, IV
Commercial Space Transportation, Office of        14, III
Commodity Credit Corporation                      7, XIV
Commodity Futures Trading Commission              5, XLI; 17, I
Community Planning and Development, Office of     24, V, VI
     Assistant Secretary for
Community Services, Office of                     45, X
Comptroller of the Currency                       12, I
Construction Industry Collective Bargaining       29, IX
     Commission
Consumer Product Safety Commission                16, II
Cooperative State Research, Education, and        7, XXXIV
     Extension Service
Copyright Office                                  37, II
Cost Accounting Standards Board                   48, 99
Council on Environmental Quality                  40, V
Customs Service, United States                    19, I
Defense Contract Audit Agency                     32, I
Defense Department                                5, XXVI; 32, Subtitle A
  Advanced Research Projects Agency               32, I
  Air Force Department                            32, VII
  Army Department                                 32, V; 33, II; 36, III, 
                                                  48, 51

[[Page 703]]

  Defense Intelligence Agency                     32, I
  Defense Logistics Agency                        32, I, XII; 48, 54
  Defense Mapping Agency                          32, I
  Engineers, Corps of                             33, II; 36, III
  Federal Acquisition Regulation                  48, 2
  Navy Department                                 32, VI; 48, 52
  Secretary of Defense, Office of                 32, I
Defense Contract Audit Agency                     32, I
Defense Intelligence Agency                       32, I
Defense Logistics Agency                          32, XII; 48, 54
Defense Mapping Agency                            32, I
Defense Nuclear Facilities Safety Board           10, XVII
Delaware River Basin Commission                   18, III
Drug Enforcement Administration                   21, II
East-West Foreign Trade Board                     15, XIII
Economic Affairs, Under Secretary                 37, V
Economic Analysis, Bureau of                      15, VIII
Economic Analysis Staff                           7, XXXIX
Economic Development Administration               13, III
Economics Management Staff                        7, XL
Economic Research Service                         7, XXXVII
Education, Department of                          5, LIII
  Bilingual Education and Minority Languages      34, V
       Affairs, Office of
  Civil Rights, Office for                        34, I
  Educational Research and Improvement, Office    34, VII
       of
  Elementary and Secondary Education, Office of   34, II
  Federal Acquisition Regulation                  48, 34
  Postsecondary Education, Office of              34, VI
  Secretary of Education, Office of               34, Subtitle A
  Special Education and Rehabilitative Services,  34, III
       Office of
  Vocational and Adult Education, Office of       34, IV
Educational Research and Improvement, Office of   34, VII
Elementary and Secondary Education, Office of     34, II
Employees' Compensation Appeals Board             20, IV
Employees Loyalty Board                           5, V
Employment and Training Administration            20, V
Employment Standards Administration               20, VI
Endangered Species Committee                      50, IV
Energy, Department of                             10, II, III, X
  Federal Acquisition Regulation                  48, 9
  Federal Energy Regulatory Commission            18, I
  Property Management Regulations                 41, 109
Energy, Office of                                 7, XXIX
Engineers, Corps of                               33, II; 36, III
Engraving and Printing, Bureau of                 31, VI
Enrichment Corporation, United States             10, XI
Environmental Protection Agency                   40, I
  Federal Acquisition Regulation                  48, 15
  Property Management Regulations                 41, 115
Environmental Quality, Office of                  7, XXXI
Equal Employment Opportunity Commission           5, LXII; 29, XIV
Equal Opportunity, Office of Assistant Secretary  24, I
     for
Executive Office of the President                 3, I
  Administration, Office of                       5, XV
  Environmental Quality, Council on               40, V
  Management and Budget, Office of                25, III, LXXVII; 48, 99
  National Drug Control Policy, Office of         21, III
  National Security Council                       32, XXI; 47, 2
  Presidential Documents                          3
  Science and Technology Policy, Office of        32, XXIV; 47, II
  Trade Representative, Office of the United      15, XX
       States
Export Administration, Bureau of                  15, VII
Export-Import Bank of the United States           5, LII; 12, IV
Family Assistance, Office of                      45, II
Farm Credit Administration                        5, XXXI; 12, VI
Farm Credit System Insurance Corporation          5, XXX; 12, XIV

[[Page 704]]

Farm Service Agency                               7, VII, XVIII
Farmers Home Administration                       7, XVIII
Federal Acquisition Regulation                    48, 1
Federal Aviation Administration                   14, I
Federal Claims Collection Standards               4, II
Federal Communications Commission                 47, I
Federal Contract Compliance Programs, Office of   41, 60
Federal Crop Insurance Corporation                7, IV
Federal Deposit Insurance Corporation             5, XXII; 12, III
Federal Election Commission                       11, I
Federal Emergency Management Agency               44, I
  Federal Acquisition Regulation                  48, 44
Federal Employees Group Life Insurance Federal    48, 21
     Acquisition Regulation
Federal Employees Health Benefits Acquisition     48, 16
     Regulation
Federal Energy Regulatory Commission              18, I
Federal Financial Institutions Examination        12, XI
     Council
Federal Financing Bank                            12, VIII
Federal Highway Administration                    23, I, II; 49, III
Federal Home Loan Mortgage Corporation            1, IV
Federal Housing Enterprise Oversight Office       12, XVII
Federal Housing Finance Board                     12, IX
Federal Information Resources Management          41, Subtitle E, Ch. 201
     Regulations
Federal Inspector for the Alaska Natural Gas      10, XV
     Transportation System, Office of
Federal Labor Relations Authority, and General    5, XIV; 22, XIV
     Counsel of the Federal Labor Relations 
     Authority
Federal Law Enforcement Training Center           31, VII
Federal Maritime Commission                       46, IV
Federal Mediation and Conciliation Service        29, XII
Federal Mine Safety and Health Review Commission  29, XXVII
Federal Pay, Advisory Committee on                5, IV
Federal Prison Industries, Inc.                   28, III
Federal Procurement Policy Office                 48, 99
Federal Property Management Regulations           41, 101
Federal Property Management Regulations System    41, Subtitle C
Federal Railroad Administration                   49, II
Federal Register, Administrative Committee of     1, I
Federal Register, Office of                       1, II
Federal Reserve System                            12, II
Federal Retirement Thrift Investment Board        5, VI, LXXVI
Federal Service Impasses Panel                    5, XIV
Federal Trade Commission                          5, XLVII; 16, I
Federal Transit Administration                    49, VI
Federal Travel Regulation System                  41, Subtitle F
Finance and Management, Office of                 7, XXX
Fine Arts, Commission on                          45, XXI
Fiscal Service                                    31, II
Fish and Wildlife Service, United States          50, I, IV
Fishery Conservation and Management               50, VI
Fishing and Whaling, International Regulatory     50, III
     Agencies
Food and Drug Administration                      21, I
Food and Consumer Service                         7, II
Food Safety and Inspection Service                9, III
Foreign Agricultural Service                      7, XV
Foreign Assets Control, Office of                 31, V
Foreign Claims Settlement Commission of the       45, V
     United States
Foreign Service Grievance Board                   22, IX
Foreign Service Impasse Disputes Panel            22, XIV
Foreign Service Labor Relations Board             22, XIV
Foreign-Trade Zones Board                         15, IV
Forest Service                                    36, II
General Accounting Office                         4, I, II
General Services Administration
  Contract Appeals, Board of                      48, 61
  Federal Acquisition Regulation                  48, 5
  Federal Information Resources Management        41, Subtitle E, Ch. 201
     Regulations
[[Page 705]]

  Federal Property Management Regulations System  41, 101, 105
  Federal Travel Regulation System                41, Subtitle F
  Payment From a Non-Federal Source for Travel    41, 304
       Expenses
  Payment of Expenses Connected With the Death    41, 303
       of Certain Employees
  Relocation Allowances                           41, 302
  Travel Allowances                               41, 301
Geological Survey                                 30, IV
Government Ethics, Office of                      5, XVI
Government National Mortgage Association          24, III
Grain Inspection, Packers and Stockyards          7, VIII; 9, II
     Administration
Great Lakes Pilotage                              46, III
Harry S. Truman Scholarship Foundation            45, XVIII
Health and Human Services, Department of          45, Subtitle A
  Child Support Enforcement, Office of            45, III
  Children and Families, Administration for       45, II, III, IV, X
  Community Services, Office of                   45, X
  Family Assistance, Office of                    45, II
  Federal Acquisition Regulation                  48, 3
  Food and Drug Administration                    21, I
  Health Care Financing Administration            42, IV
  Human Development Services, Office of           45, XIII
  Indian Health Service                           25, V
  Inspector General (Health Care), Office of      42, V
  Public Health Service                           42, I
  Refugee Resettlement, Office of                 45, IV
Health Care Financing Administration              42, IV
Housing and Urban Development, Department of      24, Subtitle B
  Community Planning and Development, Office of   24, V, VI
       Assistant Secretary for
  Equal Opportunity, Office of Assistant          24, I
       Secretary for
  Federal Acquisition Regulation                  48, 24
  Federal Housing Enterprise Oversight, Office    12, XVII
       of
  Government National Mortgage Association        24, III
  Housing--Federal Housing Commissioner, Office   24, II, VIII, X, XX
       of Assistant Secretary for
  Inspector General, Office of                    24, XII
  Public and Indian Housing, Office of Assistant  24, IX
       Secretary for
  Secretary, Office of                            24, Subtitle A, VII
Housing--Federal Housing Commissioner, Office of  24, II, VIII, X, XX
     Assistant Secretary for
Human Development Services, Office of             45, XIII
Immigration and Naturalization Service            8, I
Independent Counsel, Office of                    28, VII
Indian Affairs, Bureau of                         25, I, V
Indian Affairs, Office of the Assistant           25, VI
     Secretary
Indian Arts and Crafts Board                      25, II
Indian Health Service                             25, V
Information Agency, United States                 22, V
  Federal Acquisition Regulation                  48, 19
Information Resources Management, Office of       7, XXVII
Information Security Oversight Office, National   32, XX
     Archives and Records Administration
Inspector General
  Agriculture Department                          7, XXVI
  Health and Human Services Department            42, V
  Housing and Urban Development Department        24, XII
Institute of Peace, United States                 22, XVII
Inter-American Foundation                         5, LXIII; 22, X
Intergovernmental Relations, Advisory Commission  5, VII
     on
Interior Department
  Endangered Species Committee                    50, IV
  Federal Acquisition Regulation                  48, 14
  Federal Property Management Regulations System  41, 114
  Fish and Wildlife Service, United States        50, I, IV
  Geological Survey                               30, IV
  Indian Affairs, Bureau of                       25, I, V

[[Page 706]]

  Indian Affairs, Office of the Assistant         25, VI
       Secretary
  Indian Arts and Crafts Board                    25, II
  Land Management, Bureau of                      43, II
  Minerals Management Service                     30, II
  Mines, Bureau of                                30, VI
  National Indian Gaming Commission               25, III
  National Park Service                           36, I
  Reclamation, Bureau of                          43, I
  Secretary of the Interior, Office of            43, Subtitle A
  Surface Mining and Reclamation Appeals, Board   30, III
       of
  Surface Mining Reclamation and Enforcement,     30, VII
       Office of
Internal Revenue Service                          26, I
International Boundary and Water Commission,      22, XI
     United States and Mexico, United States 
     Section
International Development, Agency for             22, II
  Federal Acquisition Regulation                  48, 7
International Development Cooperation Agency,     22, XII
     United States
  International Development, Agency for           22, II; 48, 7
  Overseas Private Investment Corporation         5, XXXIII; 22, VII
International Investment, Office of               31, VIII
International Joint Commission, United States     22, IV
     and Canada
International Organizations Employees Loyalty     5, V
     Board
International Regulatory Agencies (Fishing and    50, III
     Whaling)
International Trade Administration                15, III; 19, III
International Trade Commission, United States     19, II
Interstate Commerce Commission                    5, XL
James Madison Memorial Fellowship Foundation      45, XXIV
Japan-United States Friendship Commission         22, XVI
Joint Board for the Enrollment of Actuaries       20, VIII
Justice Department                                28, I
  Drug Enforcement Administration                 21, II
  Federal Acquisition Regulation                  48, 28
  Federal Claims Collection Standards             4, II
  Federal Prison Industries, Inc.                 28, III
  Foreign Claims Settlement Commission of the     45, V
       United States
  Immigration and Naturalization Service          8, I
  Offices of Independent Counsel                  28, VI
  Prisons, Bureau of                              28, V
  Property Management Regulations                 41, 128
Labor Department
  Benefits Review Board                           20, VII
  Employees' Compensation Appeals Board           20, IV
  Employment and Training Administration          20, V
  Employment Standards Administration             20, VI
  Federal Acquisition Regulation                  48, 29
  Federal Contract Compliance Programs, Office    41, 60
       of
  Federal Procurement Regulations System          41, 50
  Labor-Management Relations and Cooperative      29, II
       Programs, Bureau of
  Labor-Management Programs, Office of            29, IV
  Mine Safety and Health Administration           30, I
  Occupational Safety and Health Administration   29, XVII
  Pension and Welfare Benefits Administration     29, XXV
  Public Contracts                                41, 50
  Secretary of Labor, Office of                   29, Subtitle A
  Veterans' Employment and Training, Office of    41, 61; 20, IX
       the Assistant Secretary for
  Wage and Hour Division                          29, V
  Workers' Compensation Programs, Office of       20, I
Labor-Management Relations and Cooperative        29, II
     Programs, Bureau of
Labor-Management Programs, Office of              29, IV
Land Management, Bureau of                        43, II
Legal Services Corporation                        45, XVI
Library of Congress                               36, VII

[[Page 707]]

  Copyright Office                                37, II
Management and Budget, Office of                  5, III, LXXVII; 48, 99
Marine Mammal Commission                          50, V
Maritime Administration                           46, II
Merit Systems Protection Board                    5, II
Micronesian Status Negotiations, Office for       32, XXVII
Mine Safety and Health Administration             30, I
Minerals Management Service                       30, II
Mines, Bureau of                                  30, VI
Minority Business Development Agency              15, XIV
Miscellaneous Agencies                            1, IV
Monetary Offices                                  31, I
National Aeronautics and Space Administration     5, LIX; 14, V
  Federal Acquisition Regulation                  48, 18
National Agricultural Library                     7, XLI
National Agricultural Statistics Service          7, XXXVI
National Archives and Records Administration      36, XII
  Information Security Oversight Office           32, XX
National Bureau of Standards                      15, II
National Capital Planning Commission              1, IV
National Commission for Employment Policy         1, IV
National Commission on Libraries and Information  45, XVII
     Science
National and Community Service, Corporation for   45, XXV
National Council on Disability                    34, XII
National Credit Union Administration              12, VII
National Drug Control Policy, Office of           21, III
National Foundation on the Arts and the           45, XI
     Humanities
National Highway Traffic Safety Administration    23, II, III; 49, V
National Indian Gaming Commission                 25, III
National Institute for Literacy                   34, XI
National Institute of Standards and Technology    15, II
National Labor Relations Board                    29, I
National Marine Fisheries Service                 50, II, IV
National Mediation Board                          29, X
National Oceanic and Atmospheric Administration   15, IX; 50, II, III, IV, 
                                                  VI
National Park Service                             36, I
National Railroad Adjustment Board                29, III
National Railroad Passenger Corporation (AMTRAK)  49, VII
National Science Foundation                       45, VI
  Federal Acquisition Regulation                  48, 25
National Security Council                         32, XXI
National Security Council and Office of Science   47, II
     and Technology Policy
National Telecommunications and Information       15, XXIII; 47, III
     Administration
National Transportation Safety Board              49, VIII
National Weather Service                          15, IX
Natural Resources Conservation Service            7, VI
Navajo and Hopi Indian Relocation, Office of      25, IV
Navy Department                                   32, VI
  Federal Acquisition Regulation                  48, 52
Neighborhood Reinvestment Corporation             24, XXV
Nuclear Regulatory Commission                     5, XLVIII; 10, I
  Federal Acquisition Regulation                  48, 20
Occupational Safety and Health Administration     29, XVII
Occupational Safety and Health Review Commission  29, XX
Offices of Independent Counsel                    28, VI
Operations Office                                 7, XXVIII
Overseas Private Investment Corporation           5, XXXIII; 22, VII
Panama Canal Commission                           48, 35
Panama Canal Regulations                          35, I
Patent and Trademark Office                       37, I
Payment From a Non-Federal Source for Travel      41, 304
     Expenses
Payment of Expenses Connected With the Death of   41, 303
     Certain Employees
Peace Corps                                       22, III
Pennsylvania Avenue Development Corporation       36, IX

[[Page 708]]

Pension and Welfare Benefits Administration       29, XXV
Pension Benefit Guaranty Corporation              29, XXVI
Personnel Management, Office of                   5, I; 45, VIII
  Federal Acquisition Regulation                  48, 17
  Federal Employees Group Life Insurance Federal  48, 21
       Acquisition Regulation
  Federal Employees Health Benefits Acquisition   48, 16
       Regulation
Postal Rate Commission                            5, XLVI; 39, III
Postal Service, United States                     5, LX; 39, I
Postsecondary Education, Office of                34, VI
President's Commission on White House             1, IV
     Fellowships
Presidential Commission on the Assignment of      32, XXIX
     Women in the Armed Forces
Presidential Documents                            3
Prisons, Bureau of                                28, V
Productivity, Technology and Innovation,          37, IV
     Assistant Secretary
Public Contracts, Department of Labor             41, 50
Public and Indian Housing, Office of Assistant    24, IX
     Secretary for
Public Health Service                             42, I
Railroad Retirement Board                         20, II
Reclamation, Bureau of                            43, I
Refugee Resettlement, Office of                   45, IV
Regional Action Planning Commissions              13, V
Relocation Allowances                             41, 302
Research and Special Programs Administration      49, I
Rural Business-Cooperative Service                7, XVIII, XLII
Rural Development Administration                  7, XLII
Rural Housing Service                             7, XVIII
Rural Telephone Bank                              7, XVI
Rural Utilities Service                           7, XVII, XVIII, XLII
Saint Lawrence Seaway Development Corporation     33, IV
Science and Technology Policy, Office of          32, XXIV
Science and Technology Policy, Office of, and     47, II
     National Security Council
Secret Service                                    31, IV
Securities and Exchange Commission                17, II
Selective Service System                          32, XVI
Small Business Administration                     13, I
  Federal Acquisition Regulation                  48, 22
Smithsonian Institution                           36, V
Social Security Administration                    20, III
Soldiers' and Airmen's Home, United States        5, XI
Special Counsel, Office of                        5, VIII
Special Education and Rehabilitative Services,    34, III
     Office of
State Department                                  22, I
  Federal Acquisition Regulation                  48, 6
Surface Mining and Reclamation Appeals, Board of  30, III
Surface Mining Reclamation and Enforcement,       30, VII
     Office of
Surface Transportation Board                      49, X
Susquehanna River Basin Commission                18, VIII
Technology Administration                         15, XI
Technology Policy, Assistant Secretary for        37, IV
Technology, Under Secretary for                   37, V
Tennessee Valley Authority                        5, LXIX; 18, XIII
Thrift Depositor Protection Oversight Board       12, XV
Thrift Supervision Office, Department of the      12, V
     Treasury
Trade Representative, United States, Office of    15, XX
Transportation, Department of
  Coast Guard                                     33, I; 46, I; 49, IV
  Commercial Space Transportation, Office of      14, III
  Contract Appeals, Board of                      48, 63
  Emergency Management and Assistance             44, IV
  Federal Acquisition Regulation                  48, 12
  Federal Aviation Administration                 14, I
  Federal Highway Administration                  23, I, II; 49, III
  Federal Railroad Administration                 49, II

[[Page 709]]

  Federal Transit Administration                  49, VI
  Maritime Administration                         46, II
  National Highway Traffic Safety Administration  23, II, III; 49, V
  Research and Special Programs Administration    49, I
  Saint Lawrence Seaway Development Corporation   33, IV
  Secretary of Transportation, Office of          14, II; 49, Subtitle A
  Surface Transportation Board                    49, X
Transportation, Office of                         7, XXXIII
Travel Allowances                                 41, 301
Treasury Department                               5, XXI; 17, IV
  Alcohol, Tobacco and Firearms, Bureau of        27, I
  Community Development Financial Institutions    12, XVIII
       Fund
  Comptroller of the Currency                     12, I
  Customs Service, United States                  19, I
  Engraving and Printing, Bureau of               31, VI
  Federal Acquisition Regulation                  48, 10
  Federal Law Enforcement Training Center         31, VII
  Fiscal Service                                  31, II
  Foreign Assets Control, Office of               31, V
  Internal Revenue Service                        26, I
  International Investment, Office of             31, VIII
  Monetary Offices                                31, I
  Secret Service                                  31, IV
  Secretary of the Treasury, Office of            31, Subtitle A
  Thrift Supervision, Office of                   12, V
Truman, Harry S. Scholarship Foundation           45, XVIII
United States and Canada, International Joint     22, IV
     Commission
United States and Mexico, International Boundary  22, XI
     and Water Commission, United States Section
United States Enrichment Corporation              10, XI
Utah Reclamation Mitigation and Conservation      43, III
     Commission
Veterans Affairs Department                       38, I
  Federal Acquisition Regulation                  48, 8
Veterans' Employment and Training, Office of the  41, 61; 20, IX
     Assistant Secretary for
Vice President of the United States, Office of    32, XXVIII
Vocational and Adult Education, Office of         34, IV
Wage and Hour Division                            29, V
Water Resources Council                           18, VI
Workers' Compensation Programs, Office of         20, I
World Agricultural Outlook Board                  7, XXXVIII

[[Page 711]]

                                     

                                     



                      Table of OMB Control Numbers



         PART 9--OMB APPROVALS UNDER THE PAPERWORK REDUCTION ACT

    Authority: 7 U.S.C. 135 et seq., 136-136y; 15 U.S.C. 2001, 2003, 
2005, 2006, 2601-2671; 21 U.S.C. 331j, 346a, 348; 31 U.S.C. 9701; 33 
U.S.C. 1251 et seq., 1311, 1313d, 1314, 1318, 1321, 1326, 1330, 1342, 
1344, 1345 (d) and (e), 1361; E.O. 11735, 38 FR 21243, 3 CFR, 1971-1975 
Comp. p. 973; 42 U.S.C. 241, 242b, 243, 246, 300f, 300g, 300g-1, 300g-2, 
300g-3, 300g-4, 300g-5, 300g-6, 300j-1, 300j-2, 300j-3, 300j-4, 300j-9, 
1857 et seq., 6901-6992k, 7401-7671q, 7542, 9601-9657, 11023, 11048.

Sec. 9.1  OMB approvals under the Paperwork Reduction Act.

    This part consolidates the display of control numbers assigned to 
collections of information in certain EPA regulations by the Office of 
Management and Budget (OMB) under the Paperwork Reduction Act (PRA). 
This part fulfills the requirements of section 3507(f) of the PRA.

------------------------------------------------------------------------
                                                            OMB control 
                     40 CFR citation                            No.     
------------------------------------------------------------------------
                           Public Information                           
                                                                        
Part 2, subpart B.......................................       2050-0143
------------------------------------------------------------------------
                                                                        
   General Regulation for Assistance Programs for Other than State and  
                           Local Governments                            
                                                                        
30.400..................................................       2030-0020
30.500..................................................       2030-0020
30.501..................................................       2030-0020
30.503..................................................       2030-0020
30.505..................................................       2030-0020
30.510..................................................       2030-0020
30.520..................................................       2030-0020
30.530..................................................       2030-0020
30.531..................................................       2030-0020
30.532..................................................       2030-0020
30.535..................................................       2030-0020
30.1002.................................................       2030-0020
30.1003.................................................       2030-0020
30.1200.................................................       2030-0020
------------------------------------------------------------------------
                                                                        
     Uniform Administrative Requirements for Grants and Cooperative     
               Agreements to State and Local Governments                
                                                                        
------------------------------------------------------------------------
31.10...................................................       2030-0020
31.20-31.21.............................................       2030-0020
31.31-31.32.............................................       2030-0020
31.36(g)-31.36(h).......................................       2030-0020
31.40...................................................       2030-0020
31.42...................................................       2030-0020
31.6....................................................       2030-0020
                                                                        
------------------------------------------------------------------------
                 Procurement Under Assistance Agreements                
                                                                        
------------------------------------------------------------------------
33.110..................................................       2030-0003
33.211..................................................       2030-0003
                                                                        
------------------------------------------------------------------------
                       State and Local Assistance                       
                                                                        
------------------------------------------------------------------------
35.2015.................................................       2040-0027
35.2025.................................................       2040-0027
35.2034.................................................       2040-0027
35.2040.................................................       2040-0027
35.2105-35.2107.........................................       2040-0027
35.2110.................................................       2040-0027
35.2114.................................................       2040-0027
35.2118.................................................       2040-0027
35.2120.................................................       2040-0027
35.2127.................................................       2040-0027
35.2130.................................................       2040-0027
35.2140.................................................       2040-0027
35.2211-35.2212.........................................       2040-0027
35.2215-35.2216.........................................       2040-0027
35.2218.................................................       2040-0027
35.3010.................................................       2040-0095
35.3030.................................................       2040-0095
35.3130.................................................       2040-0118
35.3135.................................................       2040-0118
35.3140.................................................       2040-0118
35.3145.................................................       2040-0118
35.3150.................................................       2040-0118
35.3155.................................................       2040-0118
35.3160.................................................       2040-0118
35.3165.................................................       2040-0118
35.3170.................................................       2040-0118
35.6055(a)(2)...........................................       2010-0020
35.6055(b)(1)...........................................       2010-0020
35.6055(b)(2)(i)-(ii)...................................       2010-0020
35.6105(a)(2)(i)-(v), (vii).............................       2010-0020
35.6110(b)(2)...........................................       2010-0020
35.6120.................................................       2010-0020
35.6145.................................................       2010-0020
35.6155(a), (c).........................................       2010-0020
35.6230(a), (c).........................................       2010-0020
35.6300(a)(3)...........................................       2010-0020
35.6315(c)..............................................       2010-0020
35.6320.................................................       2010-0020

[[Page 712]]

                                                                        
35.6340(a)..............................................       2010-0020
35.6350.................................................       2010-0020
35.6500.................................................       2010-0020
35.6550(a)(1)(ii).......................................       2010-0020
35.6550(b)(1)(iii)......................................       2010-0020
35.6550(b)(2)(i)........................................       2010-0020
35.6585.................................................       2010-0020
35.6595(a)..............................................       2010-0020
35.6600(a)..............................................       2010-0020
35.6650.................................................       2010-0020
35.6655.................................................       2010-0020
35.6660.................................................       2010-0020
35.6665(a)..............................................       2010-0020
35.6700.................................................       2010-0020
35.6705.................................................       2010-0020
35.6710.................................................       2010-0020
35.6805.................................................       2010-0020
35.6815 (a), (d), (e)...................................       2010-0020
35.9000-35.9070.........................................       2040-0138
                                                                        
------------------------------------------------------------------------
 Requirements for Preparation, Adoption, and Submittal of Implementation
                                  Plans                                 
                                                                        
------------------------------------------------------------------------
51.160-51.166...........................................       2060-0003
51.321-51.323...........................................       2060-0088
51.353-51.354...........................................       2060-0252
51.365-51.366...........................................       2060-0252
51.370-51.371...........................................       2060-0252
51.850-51.860...........................................       2060-0279
                                                                        
------------------------------------------------------------------------
            Approval and Promulgation of Implementation Plans           
                                                                        
------------------------------------------------------------------------
52.21...................................................       2060-0003
52.741..................................................       2060-0203
                                                                        
------------------------------------------------------------------------
                 Outer Continental Shelf Air Regulations                
                                                                        
------------------------------------------------------------------------
55.4-55.8...............................................       2060-0249
55.11-55.14.............................................       2060-0249
                                                                        
------------------------------------------------------------------------
                    Ambient Air Quality Surveillance                    
                                                                        
------------------------------------------------------------------------
58.11-58.14.............................................       2060-0084
58.20-58.23.............................................       2060-0084
58.25-58.28.............................................       2060-0084
58.30-58.31.............................................       2060-0084
58.33...................................................       2060-0084
58.35...................................................       2060-0084
58.40-58.41.............................................       2060-0084
58.43...................................................       2060-0084
58.45...................................................       2060-0084
58.50...................................................       2060-0084
                                                                        
------------------------------------------------------------------------
         Standards of Performance for New Stationary Sources \1\        
                                                                        
------------------------------------------------------------------------
60.7(d).................................................       2060-0207
60.45-60.47.............................................       2060-0026
60.46a-60.49a...........................................       2060-0023
60.40b..................................................       2060-0072
60.42b..................................................       2060-0072
60.44b-60.49b...........................................       2060-0072
60.42c..................................................       2060-0202
60.44c-60.48c...........................................       2060-0202
60.53-60.54.............................................       2060-0040
60.50a..................................................       2060-0210
60.56a-60.59a...........................................       2060-0210
60.63-60.65.............................................       2060-0025
60.73-60.74.............................................       2060-0019
60.84-60.85.............................................       2060-0041
60.93...................................................       2060-0083
60.104-60.108...........................................       2060-0022
60.113a-60.115a.........................................       2060-0121
60.113b-60.116b.........................................       2060-0074
60.123..................................................       2060-0080
60.133..................................................       2060-0110
60.142-60.144...........................................       2060-0029
60.143a-60.145a.........................................       2060-0029
60.153-60.155...........................................       2060-0035
60.192(b)...............................................       2060-0031
60.194-60.195...........................................       2060-0031
60.203-60.204...........................................       2060-0037
60.213-60.214...........................................       2060-0037
60.223-60.224...........................................       2060-0037
60.233-60.234...........................................       2060-0037
60.243-60.244...........................................       2060-0037
60.253-60.254...........................................       2060-0122
60.273-60.276...........................................       2060-0038
60.273a-60.276a.........................................       2060-0038
60.284-60.286...........................................       2060-0021
60.292-60.293...........................................       2060-0054
60.296..................................................       2060-0054
60.303..................................................       2060-0082
60.310..................................................       2060-0106
60.313-60.316...........................................       2060-0106
60.334-60.335...........................................       2060-0028
60.343-60.344...........................................       2060-0063
60.373-60.374...........................................       2060-0081
60.384-60.386...........................................       2060-0016
60.393-60.396...........................................       2060-0034
60.398..................................................       2060-0034
60.403-60.404...........................................       2060-0111
60.433-60.435...........................................       2060-0105
60.443-60.447...........................................       2060-0004
60.453-60.456...........................................       2060-0108
60.463-60.466...........................................       2060-0107
60.473-60.474...........................................       2060-0002
60.482-2................................................       2060-0012
60.482-3................................................       2060-0012
60.482-4................................................       2060-0012
60.482-7................................................       2060-0012
60.482-8................................................       2060-0012
60.482-10...............................................       2060-0012
60.483-1................................................       2060-0012
60.483-2................................................       2060-0012
60.484-60.487...........................................       2060-0012
60.493-60.496...........................................       2060-0001
60.502-60.503...........................................       2060-0006
60.505..................................................       2060-0006
60.530-60.536...........................................       2060-0161
60.537 (a)(1)-(2), (a)(4)-(5), (b)-(i)..................       2060-0161
60.538-60.539...........................................       2060-0161
60.543 (b)(2)-(4), (c)-(n)..............................       2060-0156
60.544..................................................       2060-0156
60.545 (a)-(d), (f).....................................       2060-0156
60.546 (a)-(e), (f)(4)-(6), (g)-(j).....................       2060-0156
60.547..................................................       2060-0156
60.562-1................................................       2060-0145
60.562-2................................................       2060-0145
60.563-60.565...........................................       2060-0145
60.580..................................................       2060-0073
60.583-60.585...........................................       2060-0073
60.592-60.593...........................................       2060-0067
60.603-60.604...........................................       2060-0059
60.613-60.615...........................................       2060-0197
60.622..................................................       2060-0079
60.624-60.625...........................................       2060-0079
60.632-60.636...........................................       2060-0120
60.640..................................................       2060-0120
60.642-60.644...........................................       2060-0120
60.646-60.647...........................................       2060-0120
60.663-60.665...........................................       2060-0197
60.670..................................................       2060-0050

[[Page 713]]

                                                                        
60.672..................................................       2060-0050
60.674-60.676...........................................       2060-0050
60.683-60.685...........................................       2060-0114
60.692-1................................................       2060-0172
60.692-2................................................       2060-0172
60.692-3................................................       2060-0172
60.692-4................................................       2060-0172
60.692-5................................................       2060-0172
60.693-1................................................       2060-0172
60.693-2................................................       2060-0172
60.695-60.698...........................................       2060-0172
60.703-60.705...........................................       2060-0269
60.710..................................................       2060-0171
60.713-60.717...........................................       2060-0171
60.722-60.725...........................................       2060-0162
60.734-60.736...........................................       2060-0251
60.740..................................................       2060-0181
60.743-60.747...........................................       2060-0181
                                                                        
------------------------------------------------------------------------
      National Emission Standards for Hazardous Air Pollutants \2\      
                                                                        
------------------------------------------------------------------------
                                                                        
61.24-61.25.............................................       2060-0191
61.32-61.34.............................................       2060-0092
61.53-61.55.............................................       2060-0097
61.65(b)-(d)............................................       2060-0071
61.67-61.71.............................................       2060-0071
61.93-61.95.............................................       2060-0191
61.103-61.105...........................................       2060-0191
61.107..................................................       2060-0191
61.123-61.124...........................................       2060-0191
61.126..................................................       2060-0191
61.132-61.133...........................................       2060-0185
61.135-61.139...........................................       2060-0185
61.142..................................................       2060-0101
61.144-61.147...........................................       2060-0101
61.149..................................................       2060-0101
61.150-61.155...........................................       2060-0101
61.163-61.165...........................................       2060-0043
61.203..................................................       2060-0191
61.206-61.209...........................................       2060-0191
61.223-61.224...........................................       2060-0191
61.242-1................................................       2060-0068
61.242-2................................................       2060-0068
61.242-3................................................       2060-0068
61.242-4................................................       2060-0068
61.242-7................................................       2060-0068
61.242-8................................................       2060-0068
61.242-10...............................................       2060-0068
61.242-11...............................................       2060-0068
61.243-1................................................       2060-0068
61.243-2................................................       2060-0068
61.244-61.247...........................................       2060-0068
61.253-61.255...........................................       2060-0191
61.271-61.276...........................................       2060-0185
61.300..................................................       2060-0182
61.302-61.305...........................................       2060-0182
61.342..................................................       2060-0183
61.344-61.349...........................................       2060-0183
61.354-61.357...........................................       2060-0183
                                                                        
------------------------------------------------------------------------
   National Emission Standards for Hazardous Air Pollutants for Source  
                             Categories \3\                             
------------------------------------------------------------------------
                                                                        
------------------------------------------------------------------------
63.52-63.56.............................................       2060-0266
63.72...................................................       2060-0222
63.74-63.79.............................................       2060-0222
63.91-63.96.............................................       2060-0264
63.103..................................................       2060-0282
63.105..................................................       2060-0282
63.117-63.118...........................................       2060-0282
63.122-63.123...........................................       2060-0282
63.129-63.130...........................................       2060-0282
63.146-63.148...........................................       2060-0282
63.151-63.152...........................................       2060-0282
63.181-63.182...........................................       2060-0282
63.302-63.311...........................................       2060-0253
63.322-63.325...........................................       2060-0234
63.345-63.347...........................................       2060-0327
63.363-63.367...........................................       2060-0283
63.403-63.406...........................................       2060-0268
63.420..................................................       2060-0325
63.422-63.428...........................................       2060-0325
63.467-63.468...........................................       2060-0273
63.525-63.528...........................................       2060-0290
63.548-63.550...........................................       2060-0296
63.563-63.567...........................................       2060-0289
63.653..................................................       2060-0340
63.654..................................................       2060-0340
63.703-63.707...........................................       2060-0326
63.752-63.753...........................................       2060-0341
63.806-63.807...........................................       2060-0324
63.829-63.830...........................................       2060-0335
                                                                        
------------------------------------------------------------------------
                 Chemical Accident Prevention Provisions                
                                                                        
------------------------------------------------------------------------
68.120 (a), (e), and (g)................................       2050-0127
                                                                        
------------------------------------------------------------------------
                     State Operating Permit Programs                    
                                                                        
------------------------------------------------------------------------
70.3-70.11..............................................       2060-0243
                                                                        
------------------------------------------------------------------------
                    Federal Operating Permit Programs                   
                                                                        
------------------------------------------------------------------------
71.5....................................................       2060-0336
71.6(a),(c),(d),(g).....................................       2060-0336
71.7....................................................       2060-0336
71.9(e)-(j).............................................       2060-0336
71.24-71.26.............................................       2060-0276
                                                                        
------------------------------------------------------------------------
                           Permits Regulation                           
                                                                        
------------------------------------------------------------------------
72.7-72.10..............................................       2060-0258
72.20-72.25.............................................       2060-0258
72.30-72.33.............................................       2060-0258
72.40-72.44.............................................       2060-0258
72.50-72.51.............................................       2060-0258
72.60-72.69.............................................       2060-0258
72.70-72.74.............................................       2060-0258
72.80-72.85.............................................       2060-0258
72.90-72.96.............................................       2060-0258
                                                                        
------------------------------------------------------------------------
                            Allowance System                            
                                                                        
------------------------------------------------------------------------
73.10-73.13.............................................       2060-0261
73.16...................................................       2060-0261
73.18-73.21.............................................       2060-0261
73.30-73.38.............................................       2060-0258
73.50-73.53.............................................       2060-0258
73.70-73.77.............................................       2060-0221
73.80-73.86.............................................       2060-0258
73.90...................................................       2060-0258
                                                                        
------------------------------------------------------------------------
                         Sulfur Dioxide Opt-ins                         
                                                                        
------------------------------------------------------------------------
74.12...................................................       2060-0258
74.14...................................................       2060-0258
74.16...................................................       2060-0258
74.18...................................................       2060-0258

[[Page 714]]

                                                                        
74.20...................................................       2060-0258
74.22...................................................       2060-0258
74.24-74.25.............................................       2060-0258
74.41...................................................       2060-0258
74.43-74.44.............................................       2060-0258
74.46-74.47.............................................       2060-0258
74.60-74.64.............................................       2060-0258
                                                                        
------------------------------------------------------------------------
                     Continuous Emission Monitoring                     
                                                                        
------------------------------------------------------------------------
75.4-75.5...............................................       2060-0258
75.10-75.18.............................................       2060-0258
75.20-75.24.............................................       2060-0258
75.30-75.34.............................................       2060-0258
75.40-75.48.............................................       2060-0258
75.50-75.52.............................................       2060-0258
75.53-75.56.............................................       2060-0258
75.60-75.67.............................................       2060-0258
                                                                        
------------------------------------------------------------------------
               Nitrogen Oxides Emission Reduction Program               
                                                                        
------------------------------------------------------------------------
76.8-76.15..............................................       2060-0258
                                                                        
------------------------------------------------------------------------
                            Excess Emissions                            
                                                                        
------------------------------------------------------------------------
77.3-77.6...............................................       2060-0258
                                                                        
------------------------------------------------------------------------
                 Appeal Procedures for Acid Rain Program                
                                                                        
------------------------------------------------------------------------
78.1-78.20..............................................       2060-0258
                                                                        
------------------------------------------------------------------------
                Registration of Fuels and Fuel Additives                
                                                                        
------------------------------------------------------------------------
79.10-79.11.............................................       2060-0150
79.20-79.21.............................................       2060-0150
79.31-79.33.............................................       2060-0150
79.51(a), (c), (d), (g), (h)............................       2060-0150
79.52...................................................       2060-0150
79.57(a)(5).............................................       2060-0150
79.57(f)(5).............................................       2060-0150
79.58(e)................................................       2060-0150
79.59(b)-(d)............................................       2060-0150
79.60...................................................       2060-0150
79.61(e)................................................       2060-0150
79.62-79.68.............................................       2060-0297
                                                                        
------------------------------------------------------------------------
                 Regulation of Fuels and Fuel Additives                 
                                                                        
------------------------------------------------------------------------
80.20...................................................       2060-0066
80.25...................................................       2060-0066
80.27...................................................       2060-0178
80.29(c)................................................       2060-0308
80.141(c)-(f)...........................................       2060-0275
80.157..................................................       2060-0275
80.158..................................................       2060-0275
80.160..................................................       2060-0275
                                                                        
------------------------------------------------------------------------
                   Protection of Stratospheric Ozone                    
                                                                        
------------------------------------------------------------------------
82.9-82.13..............................................       2060-0170
82.21...................................................       2060-0170
82.36...................................................       2060-0247
82.38...................................................       2060-0247
82.40...................................................       2060-0247
82.42...................................................       2060-0247
82.122..................................................       2060-0259
82.156..................................................       2060-0256
82.160-82.162...........................................       2060-0256
82.164..................................................       2060-0256
82.166..................................................       2060-0256
82.176(a)...............................................       2060-0226
82.176(c)(3)............................................       2060-0226
82.178..................................................       2060-0226
82.180(a)(5)............................................       2060-0226
82.180(b)(3)............................................       2060-0226
82.184(c)...............................................       2060-0226
82.184(e)...............................................       2060-0226
                                                                        
------------------------------------------------------------------------
 Control of Air Pollution From Motor Vehicles and Motor Vehicle Engines 
                                                                        
------------------------------------------------------------------------
85.503..................................................       2060-0104
85.505..................................................       2060-0104
85.1503-85.1507.........................................       2060-0095
85.1509-85.1510.........................................       2060-0095
85.1511(b)-(d), (f).....................................       2060-0095
85.1511(b)(3)...........................................       2060-0007
85.1512.................................................       2060-0095
85.1514-85.1515.........................................       2060-0095
85.1703.................................................       2060-0124
85.1705-85.1706.........................................       2060-0007
85.1901-85.1909.........................................       2060-0048
85.2112-85.2123.........................................       2060-0065
85.2114.................................................       2060-0016
85.2115.................................................       2060-0016
                                                                        
------------------------------------------------------------------------
 Control of Air Pollution From New and In-Use Motor Vehicles and New and
     In-Use Motor Vehicle Engines: Certification and Test Procedures    
                                                                        
------------------------------------------------------------------------
86.079-31-86.079-33.....................................       2060-0104
86.079-36...............................................       2060-0104
86.079-39...............................................       2060-0104
86.080-12...............................................       2060-0104
86.082-34...............................................       2060-0104
86.085-13...............................................       2060-0104
86.085-37...............................................       2060-0104
86.087-38...............................................       2060-0104
86.090..................................................       2060-0104
86.090-21...............................................       2060-0104
86.090-25...............................................       2060-0104
86.090-26...............................................       2060-0104
86.090-27...............................................       2060-0104
86.091-7................................................       2060-0104
86.091-15...............................................       2060-0104
86.091-21...............................................       2060-0104
86.091-23...............................................       2060-0104
86.091-28...............................................       2060-0104
86.091-30...............................................       2060-0104
86.092-14...............................................       2060-0104
86.092-15...............................................       2060-0104
86.092-23...............................................       2060-0104
86.092-24...............................................       2060-0104
86.092-26...............................................       2060-0104
86.092-35...............................................       2060-0104
86.094-7-86.094-9.......................................       2060-0104
86.094-15-86.094-16.....................................       2060-0104
86.094-17...............................................       2060-0104
86.094-18...............................................       2060-0104
86.094-21...............................................       2060-0104
86.094-23...............................................       2060-0104
86.094-24(a)(3)(iii)....................................       2060-0314
86.094-25...............................................       2060-0104
86.094-30...............................................       2060-0104
86.094-35...............................................       2060-0104
86.094-38...............................................       2060-0104
86.095-14...............................................       2060-0104
86.095-23...............................................       2060-0104
86.095-24...............................................       2060-0104
86.095-26...............................................       2060-0104

[[Page 715]]

                                                                        
86.095-30...............................................       2060-0104
86.095-35...............................................       2060-0104
86.096-7................................................       2060-0104
86.096-8................................................       2060-0104
86.096-9................................................       2060-0104
86.096-10...............................................       2060-0104
86.096-14...............................................       2060-0104
86.096-21...............................................       2060-0104
86.096-23...............................................       2060-0104
86.096-24...............................................       2060-0104
86.096-26...............................................       2060-0104
86.096-30...............................................       2060-0104
86.096-35...............................................       2060-0104
86.097-9................................................       2060-0104
86.098-23...............................................       2060-0104
86.098-28...............................................       2060-0104
86.099-8................................................       2060-0104
86.099-9................................................       2060-0104
86.099-10...............................................       2060-0104
86.111-94...............................................       2060-0104
86.113-82...............................................       2060-0104
86.113-87...............................................       2060-0104
86.113-90...............................................       2060-0104
86.113-91...............................................       2060-0104
86.113-94...............................................       2060-0104
86.135-82...............................................       2060-0104
86.135-90...............................................       2060-0104
86.135-94...............................................       2060-0104
86.142-90...............................................       2060-0104
86.144-90...............................................       2060-0104
86.144-94...............................................       2060-0104
86.150-98...............................................       2060-0104
86.336-79...............................................       2060-0104
86.337-79...............................................       2060-0104
86.412-78...............................................       2060-0104
86.414-78...............................................       2060-0104
86.415-78...............................................       2060-0104
86.416-80...............................................       2060-0104
86.421-78...............................................       2060-0104
86.423-78...............................................       2060-0104
86.427-78...............................................       2060-0104
86.428-80...............................................       2060-0104
86.429-78...............................................       2060-0104
86.431-78...............................................       2060-0104
86.432-78...............................................       2060-0104
86.434-78...............................................       2060-0104
86.435-78...............................................       2060-0104
86.436-78...............................................       2060-0104
86.437-78...............................................       2060-0104
86.438-78...............................................       2060-0104
86.439-78...............................................       2060-0104
86.440-78...............................................       2060-0104
86.513-94...............................................       2060-0104
86.537-90...............................................       2060-0104
86.542-90...............................................       2060-0104
86.603-88...............................................       2060-0064
86.604-84...............................................       2060-0064
86.605-88...............................................       2060-0064
86.606-84...............................................       2060-0064
86.607-84...............................................       2060-0064
86.608-88...............................................       2060-0064
86.608-90...............................................       2060-0064
86.608-96...............................................       2060-0104
86.609-84...............................................       2060-0064
86.609-96...............................................       2060-0104
86.612-84...............................................       2060-0064
86.614-84...............................................       2060-0064
86.615-84...............................................       2060-0064
86.709-94...............................................       2060-0104
86.709-99...............................................       2060-0104
86.884-5................................................       2060-0104
86.884-7................................................       2060-0104
86.884-9................................................       2060-0104
86.884-10...............................................       2060-0104
86.884-12...............................................       2060-0104
86.884-13...............................................       2060-0104
86.1003-88..............................................       2060-0064
86.1003-90..............................................       2060-0064
86.1004-84..............................................       2060-0064
86.1005-88..............................................       2060-0064
68.1005-90..............................................       2060-0064
86.1006-84..............................................       2060-0064
86.1007-84..............................................       2060-0064
86.1008-88..............................................       2060-0064
86.1008-90..............................................       2060-0064
86.1008-96..............................................       2060-0104
86.1009-84..............................................       2060-0064
86.1009-96..............................................       2060-0104
86.1012-84..............................................       2060-0064
86.1014-84..............................................       2060-0064
86.1015-87..............................................       2060-0064
86.1106-87..............................................       2060-0132
86.1108-87..............................................       2060-0132
86.1110-87..............................................       2060-0132
86.1111-87..............................................       2060-0104
86.1112-87-86.1115-87...................................       2060-0132
86.1213-85..............................................       2060-0104
86.1213-87..............................................       2060-0104
86.1242-85..............................................       2060-0104
86.1242-90..............................................       2060-0104
86.1308-84..............................................       2060-0104
86.1310-90..............................................       2060-0104
86.1311-94..............................................       2060-0104
86.1313-84..............................................       2060-0104
86.1313-87..............................................       2060-0104
86.1313-90..............................................       2060-0104
86.1313-91..............................................       2060-0104
86.1313-94..............................................       2060-0104
86.1314-84..............................................       2060-0104
86.1316-84..............................................       2060-0104
86.1316-90..............................................       2060-0104
86.1319-84..............................................       2060-0104
86.1319-90..............................................       2060-0104
86.1321-84..............................................       2060-0104
86.1321-90..............................................       2060-0104
86.1323-84..............................................       2060-0104
86.1327-84..............................................       2060-0104
86.1327-88..............................................       2060-0104
86.1327-90..............................................       2060-0104
86.1332-84..............................................       2060-0104
86.1332-90..............................................       2060-0104
86.1334-84..............................................       2060-0104
86.1335-90..............................................       2060-0104
86.1336-84..............................................       2060-0104
86.1340-84..............................................       2060-0104
86.1340-90..............................................       2060-0104
86.1341-90..............................................       2060-0104
86.1342-90..............................................       2060-0104
86.1344-94..............................................       2060-0104
86.1413.................................................       2060-0104
86.1427.................................................       2060-0104
86.1432.................................................       2060-0104
86.1434.................................................       2060-0104
86.1437.................................................       2060-0104
86.1442.................................................       2060-0104
86.1542-84..............................................       2060-0104
86.1544-84..............................................       2060-0104
86.2500.................................................       2060-0104
                                                                        
------------------------------------------------------------------------
                           Clean-Fuel Vehicles                          
                                                                        
------------------------------------------------------------------------
88.104-94 (a), (c), (e), (f), (g), (h), (i), (j), (k)...       2060-0104
88.105-94...............................................       2060-0104
88.204-94(b)(1).........................................       2060-0314
88.204-94(c)............................................       2060-0314

[[Page 716]]

                                                                        
88.305-94...............................................       2060-0104
88.306-94(a), (b) introductory text.....................       2060-0104
88.306-94(b)(1).........................................       2060-0314
88.306-94(b)(2).........................................       2060-0314
88.306-94(b)(4).........................................       2060-0314
88.306-94(c)............................................       2060-0314
88.306-94(f)............................................       2060-0314
                                                                        
------------------------------------------------------------------------
        Control of Emissions From New and In-Use Nonroad Engines        
                                                                        
------------------------------------------------------------------------
89.1....................................................       2060-0124
89.2....................................................       2060-0124
89.114-96-89.120-96.....................................       2060-0287
89.122-96-89.127-96.....................................       2060-0287
89.129-96...............................................       2060-0287
89.203-96-89.207-96.....................................       2060-0287
89.209-96-89.211-96.....................................       2060-0287
89.304-96-89.331-96.....................................       2060-0287
89.404-96-89.424-96.....................................       2060-0287
89.505-89.905...........................................       2060-0064
89.511..................................................       2060-0064
89.512..................................................       2060-0064
89.603-89.605...........................................       2060-0095
89.607-89.610...........................................       2060-0095
89.611..................................................      2060-0007,
                                                               2060-0095
89.612..................................................       2060-0095
89.801..................................................       2060-0048
89.803..................................................       2060-0048
89.903..................................................       2060-0048
89.905..................................................       2060-0007
89.906..................................................       2060-0007
                                                                        
------------------------------------------------------------------------
        Control of Emissions From New and In-use Nonroad Engines        
90.107-90.108...........................................       2060-0338
90.113..................................................       2060-0338
90.115-90.124...........................................       2060-0338
90.126..................................................       2060-0338
90.304-90.329...........................................       2060-0338
90.404-90.427...........................................       2060-0338
90.505-90.509...........................................       2060-0295
90.511-90.512...........................................       2060-0295
90.604..................................................       2060-0294
90.611-90.613...........................................       2060-0294
90.800..................................................       2060-0048
90.802-90.804...........................................       2060-0048
90.806..................................................       2060-0048
90.903..................................................       2060-0124
90.905-90.906...........................................       2060-0007
                                                                        
------------------------------------------------------------------------
      Determining Conformity of Federal Actions to State or Federal     
                          Implementation Plans                          
                                                                        
------------------------------------------------------------------------
93.150-93.160...........................................       2060-0279
                                                                        
------------------------------------------------------------------------
                        Mandatory Patent Licenses                       
                                                                        
------------------------------------------------------------------------
95.2....................................................       2060-0307
                                                                        
------------------------------------------------------------------------
                        Oil Pollution Prevention                        
                                                                        
------------------------------------------------------------------------
112.1-112.7.............................................       2050-0021
                                                                        
------------------------------------------------------------------------
 Oil Pollution Prevention; Non-Transportation-Related Onshore Facilities
                                                                        
------------------------------------------------------------------------
112.20..................................................       2050-0135
                                                                        
------------------------------------------------------------------------
   Designation, Reportable Quantities, and Notification for Hazardous   
                               Substances                               
                                                                        
------------------------------------------------------------------------
116.4...................................................       2050-0046
117.3...................................................       2050-0046
117.21..................................................       2050-0046
                                                                        
------------------------------------------------------------------------
   EPA Administered Permit Programs: The National Pollutant Discharge   
                           Elimination System                           
                                                                        
------------------------------------------------------------------------
122.21(f)-(l)...........................................      2040-0086,
                                                               2040-0170
122.21(j)(4)............................................       2040-0150
122.21(m)-(p)...........................................      2040-0068,
                                                               2040-0170
122.26(c), (d)..........................................       2040-0086
122.41(h)...............................................      2040-0068,
                                                               2040-0170
122.41(j)...............................................      2040-0009,
                                                              2040-0110,
                                                               2040-0170
122.41(l)...............................................      2040-0110,
                                                              2040-0068,
                                                               2040-0170
122.42(c)...............................................       2040-0086
122.42(a), (b), (l).....................................      2040-0068,
                                                               2040-0170
122.44(g), (i)..........................................      2040-0004,
                                                               2040-0170
122.44(r)...............................................       2040-0180
122.45(b)...............................................      2040-0004,
                                                               2040-0110
122.45(b)(4)............................................       2040-0068
122.47(a)...............................................      2040-0110,
                                                               2040-0170
122.47(b)...............................................      2040-0110,
                                                              2040-0068,
                                                               2040-0170
122.48..................................................      2040-0004,
                                                               2040-0170
122.62(a)...............................................      2040-0068,
                                                               2040-0170
122.63..................................................      2040-0068,
                                                               2040-0170
                                                                        
------------------------------------------------------------------------
                        State Permit Requirements                       
                                                                        
------------------------------------------------------------------------
123.21-123.24...........................................      2040-0057,
                                                               2040-0170
123.25..................................................      2040-0004,
                                                              2040-0110,
                                                              2040-0170,
                                                               2040-0180
123.26-123.29...........................................      2040-0057,
                                                               2040-0170
123.43..................................................      2040-0057,
                                                               2040-0170
123.44..................................................      2040-0057,
                                                              2040-0170,
                                                               2040-0180
123.45..................................................      2040-0057,
                                                               2040-0170
123.62..................................................      2040-0057,
                                                              2040-0170,
                                                               2040-0180

[[Page 717]]

                                                                        
123.63..................................................      2040-0057,
                                                              2040-0170,
                                                               2040-0180
123.64..................................................      2040-0057,
                                                               2040-0170
                                                                        
------------------------------------------------------------------------
                      Procedures for Decisionmaking                     
                                                                        
------------------------------------------------------------------------
124.5...................................................       2040-0068
124.31..................................................       2050-0149
124.32..................................................       2050-0149
124.33..................................................       2050-0149
124.53-124.54...........................................       2040-0057
                                                                        
------------------------------------------------------------------------
 Criteria and Standards for the National Pollutant Discharge Elimination
                                 System                                 
                                                                        
------------------------------------------------------------------------
125.59-125.67, and Appendix A and B.....................       2040-0088
                                                                        
------------------------------------------------------------------------
                  Water Quality Planning and Management                 
                                                                        
------------------------------------------------------------------------
130.6-130.10............................................       2040-0071
130.15..................................................       2040-0071
                                                                        
------------------------------------------------------------------------
                   Water Quality Standards Regulation                   
                                                                        
------------------------------------------------------------------------
131.1...................................................       2040-0180
131.5...................................................       2040-0180
131.6-131.8.............................................       2040-0049
131.20..................................................       2040-0049
131.21..................................................      2040-0049,
                                                               2040-0180
131.22..................................................       2040-0049
131.31-131.36...........................................       2040-0049
                                                                        
------------------------------------------------------------------------
            Water Quality Guidance for the Great Lakes System           
                                                                        
------------------------------------------------------------------------
132.1...................................................       2040-0180
132.2...................................................       2040-0180
132.3...................................................       2040-0180
132.4...................................................       2040-0180
132.5...................................................       2040-0180
Part 132, Appendix A....................................       2040-0180
Part 132, Appendix B....................................       2040-0180
Part 132, Appendix C....................................       2040-0180
Part 132, Appendix D....................................       2040-0180
Part 132, Appendix E....................................       2040-0180
Part 132, Appendix F....................................       2040-0180
                                                                        
------------------------------------------------------------------------
              National Primary Drinking Water Regulations               
                                                                        
------------------------------------------------------------------------
141.2...................................................       2040-0090
141.4...................................................       2040-0090
141.11-141.15...........................................       2040-0090
141.21-141.22...........................................       2040-0090
141.23-141.24...........................................       2040-0090
141.25-141.30...........................................       2040-0090
141.31-141.32...........................................       2040-0090
141.33-141.35...........................................       2040-0090
141.40..................................................       2040-0090
141.41-141.43...........................................       2040-0090
141.50-141.52...........................................       2040-0090
141.60-141.63...........................................       2040-0090
141.70-141.75...........................................       2040-0090
141.80-141.91...........................................       2040-0090
141.100.................................................       2040-0090
141.110-141.111.........................................       2040-0090
                                                                        
------------------------------------------------------------------------
       National Primary Drinking Water Regulations Implementation       
                                                                        
------------------------------------------------------------------------
142.2-142.3.............................................       2040-0090
142.10-142.15...........................................       2040-0090
142.16..................................................       2060-0090
142.17-142.24...........................................       2040-0090
142.56-142.57...........................................       2040-0090
142.60-142.61...........................................       2040-0090
142.62..................................................       2040-0090
142.63-142.64...........................................       2040-0090
142.70-142.78...........................................       2040-0090
142.81-142.81...........................................       2040-0090
                                                                        
------------------------------------------------------------------------
                  Underground Injection Control Program                 
                                                                        
------------------------------------------------------------------------
144.8...................................................       2040-0042
144.12..................................................       2040-0042
144.14-144.15...........................................       2040-0042
144.23..................................................       2040-0042
144.25-144.28...........................................       2040-0042
144.31-144.33...........................................       2040-0042
144.38..................................................       2040-0042
144.41..................................................       2040-0042
144.51-144.55...........................................       2040-0042
144.62-144.66...........................................       2040-0042
144.70..................................................       2040-0042
                                                                        
------------------------------------------------------------------------
      Underground Injection Control Program: Criteria and Standards     
                                                                        
------------------------------------------------------------------------
146.10..................................................       2040-0042
146.12-146.15...........................................       2040-0042
146.22-146.25...........................................       2040-0042
146.32-146.35...........................................       2040-0042
146.52..................................................       2040-0042
146.64..................................................       2040-0042
146.66-146.73...........................................       2040-0042
                                                                        
------------------------------------------------------------------------
              State Underground Injection Control Programs              
                                                                        
------------------------------------------------------------------------
147.104.................................................       2040-0042
147.304-147.305.........................................       2040-0042
147.504.................................................       2040-0042
147.754.................................................       2040-0042
147.904.................................................       2040-0042
147.1154................................................       2040-0042
147.1354-147.1355.......................................       2040-0042
147.1454................................................       2040-0042
147.1654................................................       2040-0042
147.1954................................................       2040-0042
147.2103-147.2104.......................................       2040-0042
147.2154................................................       2040-0042
147.2402................................................       2040-0042
147.2905................................................       2040-0042
147.2912-147.2913.......................................       2040-0042
147.2915................................................       2040-0042
147.2918................................................       2040-0042
147.2920-147.2926.......................................       2040-0042
147.2929................................................       2040-0042
147.3002-147.3003.......................................       2040-0042
147.3006-147.3007.......................................       2040-0042
147.3011................................................       2040-0042
147.3014-147.3016.......................................       2040-0042
147.3101................................................       2040-0042
147.3104-147.3105.......................................       2040-0042
147.3107-147.3109.......................................       2040-0042
                                                                        
------------------------------------------------------------------------

[[Page 718]]

                                                                        
                 Hazardous Waste Injection Restrictions                 
                                                                        
------------------------------------------------------------------------
148.5...................................................       2040-0042
148.20-148.23...........................................       2040-0042
                                                                        
------------------------------------------------------------------------
          Pesticide Registration and Classification Procedures          
                                                                        
------------------------------------------------------------------------
152.46..................................................       2070-0060
152.50..................................................      2070-0024,
                                                             2070-0040 &
                                                               2070-0060
152.80..................................................     2070-0040 &
                                                               2070-0060
152.85..................................................     2070-0040 &
                                                               2070-0060
152.98..................................................       2070-0060
152.122.................................................       2070-0060
152.132.................................................       2070-0044
152.135.................................................       2070-0060
152.164.................................................       2070-0060
152.404.................................................     2070-0040 &
                                                               2070-0060
152.406.................................................     2070-0040 &
                                                               2070-0060
152.412.................................................     2070-0040 &
                                                               2070-0060
152.414.................................................     2070-0040 &
                                                               2070-0060
                                                                        
------------------------------------------------------------------------
                         Registration Standards                         
                                                                        
------------------------------------------------------------------------
155.30..................................................       2070-0057
                                                                        
------------------------------------------------------------------------
            Labeling Requirements for Pesticides and Devices            
                                                                        
------------------------------------------------------------------------
156.36..................................................       2070-0052
156.206.................................................       2070-0060
156.208.................................................       2070-0060
156.210.................................................       2070-0060
156.212.................................................       2070-0060
                                                                        
------------------------------------------------------------------------
            Packaging Requirements for Pesticides and Devices           
                                                                        
------------------------------------------------------------------------
157.22..................................................       2070-0052
157.24..................................................       2070-0052
157.34..................................................       2070-0052
157.36..................................................       2070-0052
                                                                        
------------------------------------------------------------------------
                   Data Requirements for Registration                   
                                                                        
------------------------------------------------------------------------
158.30..................................................      2070-0040,
                                                              2070-0057,
                                                             2070-0060 &
                                                               2070-0107
158.32..................................................      2070-0040,
                                                              2070-0053,
                                                              2070-0057,
                                                             2070-0060 &
                                                               2070-0107
158.34..................................................      2070-0040,
                                                              2070-0057,
                                                             2070-0060 &
                                                               2070-0107
158.45..................................................      2070-0040,
                                                              2070-0057,
                                                             2070-0060 &
                                                               2070-0107
158.75..................................................      2070-0040,
                                                              2070-0057,
                                                             2070-0060 &
                                                               2070-0107
158.101.................................................      2070-0040,
                                                              2070-0057,
                                                             2070-0060 &
                                                               2070-0107
158.155.................................................      2070-0040,
                                                              2070-0057,
                                                             2070-0060 &
                                                               2070-0107
158.160.................................................      2070-0040,
                                                              2070-0057,
                                                             2070-0060 &
                                                               2070-0107
158.162.................................................      2070-0040,
                                                              2070-0057,
                                                             2070-0060 &
                                                               2070-0107
158.165.................................................      2070-0040,
                                                              2070-0057,
                                                             2070-0060 &
                                                               2070-0107
158.167.................................................      2070-0040,
                                                              2070-0057,
                                                             2070-0060 &
                                                               2070-0107
158.170.................................................      2070-0040,
                                                              2070-0057,
                                                             2070-0060 &
                                                               2070-0107
158.175.................................................      2070-0040,
                                                              2070-0057,
                                                             2070-0060 &
                                                               2070-0107
158.180.................................................      2070-0040,
                                                              2070-0057,
                                                             2070-0060 &
                                                               2070-0107
158.190.................................................      2070-0040,
                                                              2070-0057,
                                                             2070-0060 &
                                                               2070-0107
158.240.................................................      2070-0057,
                                                             2070-0060 &
                                                               2070-0107
158.290.................................................      2070-0057,
                                                             2070-0060 &
                                                               2070-0107
158.340.................................................      2070-0057,
                                                             2070-0060 &
                                                               2070-0107
158.390.................................................      2070-0057,
                                                             2070-0060 &
                                                               2070-0107
158.440.................................................      2070-0057,
                                                             2070-0060 &
                                                               2070-0107
158.490.................................................      2070-0057,
                                                             2070-0060 &
                                                               2070-0107
158.540.................................................      2070-0057,
                                                             2070-0060 &
                                                               2070-0107
158.590.................................................      2070-0057,
                                                             2070-0060 &
                                                               2070-0107
158.640.................................................      2070-0057,
                                                             2070-0060 &
                                                               2070-0107
158.690.................................................      2070-0057,
                                                             2070-0060 &
                                                               2070-0107

[[Page 719]]

                                                                        
158.740.................................................      2070-0057,
                                                             2070-0060 &
                                                               2070-0107
                                                                        
------------------------------------------------------------------------
                   Good Laboratory Practice Standards                   
                                                                        
------------------------------------------------------------------------
part 160................................................      2070-0024,
                                                              2070-0032,
                                                              2070-0040,
                                                              2070-0055,
                                                              2070-0057,
                                                             2070-0060 &
                                                               2070-0107
                                                                        
------------------------------------------------------------------------
                State Registration of Pesticide Products                
                                                                        
------------------------------------------------------------------------
162.153.................................................       2070-0055
                                                                        
------------------------------------------------------------------------
           Certification of Usefulness of Pesticide Chemicals           
                                                                        
------------------------------------------------------------------------
163.4...................................................     2070-0060 &
                                                               2070-0024
163.5...................................................     2070-0060 &
                                                               2070-0024
                                                                        
------------------------------------------------------------------------
   Exemption of Federal and State Agencies for Use of Pesticides Under  
                          Emergency Conditions                          
                                                                        
------------------------------------------------------------------------
166.20..................................................       2070-0032
166.32..................................................       2070-0032
166.43..................................................       2070-0032
166.50..................................................       2070-0032
                                                                        
------------------------------------------------------------------------
        Registration of Pesticide and Active Ingredient Producing       
             Establishments, Submission of Pesticide Reports            
                                                                        
------------------------------------------------------------------------
part 167................................................       2070-0078
                                                                        
------------------------------------------------------------------------
         Statements of Enforcement Policies and Interpretations         
                                                                        
------------------------------------------------------------------------
168.65..................................................       2070-0027
168.75..................................................       2070-0027
168.85..................................................      2070-0027,
                                                            2070-0028, &
                                                               2070-0078
                                                                        
------------------------------------------------------------------------
       Books and Records of Pesticide Production and Distribution       
                                                                        
------------------------------------------------------------------------
169.2...................................................       2070-0028
                                                                        
------------------------------------------------------------------------
         Worker Protection Standards for Agricultural Pesticides        
                                                                        
------------------------------------------------------------------------
170.112.................................................       2070-0060
part 170................................................       2070-0148
                                                                        
------------------------------------------------------------------------
                 Certification of Pesticide Applicators                 
                                                                        
------------------------------------------------------------------------
171.7...................................................       2070-0029
171.8...................................................       2070-0029
171.9...................................................       2070-0029
171.10..................................................       2070-0029
171.11..................................................       2070-0029
                                                                        
------------------------------------------------------------------------
                        Experimental Use Permits                        
                                                                        
------------------------------------------------------------------------
172.4...................................................       2070-0040
172.8...................................................       2070-0040
                                                                        
------------------------------------------------------------------------
                  Issuance of Food Additive Regulations                 
                                                                        
------------------------------------------------------------------------
177.81..................................................       2070-0024
177.92..................................................       2070-0024
177.98..................................................       2070-0024
177.99..................................................       2070-0024
177.102.................................................       2070-0024
177.105.................................................       2070-0024
177.110.................................................       2070-0024
177.116.................................................       2070-0024
                                                                        
------------------------------------------------------------------------
 Tolerances and Exemptions from Tolerances for Pesticide Chemicals in or
                     on Raw Agricultural Commodities                    
                                                                        
------------------------------------------------------------------------
180.7...................................................       2070-0024
180.8...................................................       2070-0024
180.9...................................................       2070-0024
180.31..................................................       2070-0024
180.32..................................................       2070-0024
180.33..................................................       2070-0024
                                                                        
------------------------------------------------------------------------
                      404 State Program Regulations                     
                                                                        
------------------------------------------------------------------------
233.10-233.12...........................................       2040-0168
233.21..................................................       2040-0168
233.30..................................................       2040-0168
233.50..................................................       2040-0168
233.52..................................................       2040-0168
233.61..................................................       2040-0140
                                                                        
------------------------------------------------------------------------
              Criteria for Municipal Solid Waste Landfills              
                                                                        
------------------------------------------------------------------------
258.10-258.16...........................................       2050-0122
258.20..................................................       2050-0122
258.23..................................................       2050-0122
258.28-258.29...........................................       2050-0122
258.51..................................................       2050-0122
258.53-258.55...........................................       2050-0122
258.57-258.58...........................................       2050-0122
258.60-258.61...........................................       2050-0122
258.71-258.74...........................................       2050-0122
                                                                        
------------------------------------------------------------------------
               Hazardous Waste Management System: General               
                                                                        
------------------------------------------------------------------------
260.20-260.22...........................................       2050-0053
260.23..................................................       2050-0145
260.31-260.33...........................................       2050-0053
                                                                        
------------------------------------------------------------------------
              Identification and Listing of Hazardous Waste             
                                                                        
------------------------------------------------------------------------
261.3...................................................       2050-0085
261.4...................................................       2050-0053
261.35..................................................       2050-0115
                                                                        
------------------------------------------------------------------------
          Standards Applicable to Generators of Hazardous Waste         
                                                                        
------------------------------------------------------------------------
262.12..................................................       2050-0028
262.20..................................................       2050-0039
262.22-262.23...........................................       2050-0039
262.34..................................................      2050-0035,
                                                               2050-0085

[[Page 720]]

                                                                        
262.40(a)...............................................       2050-0039
262.40(b)...............................................       2050-0024
262.40(c)...............................................       2050-0035
262.41..................................................       2050-0024
262.42..................................................       2050-0039
262.43..................................................       2050-0035
262.44(a)-(b)...........................................       2050-0039
262.44(c)...............................................       2050-0035
262.53-262.57...........................................       2050-0035
262.60..................................................       2050-0035
                                                                        
------------------------------------------------------------------------
         Standards Applicable to Transporters of Hazardous Waste        
                                                                        
------------------------------------------------------------------------
263.11..................................................       2050-0028
263.20-263.22...........................................       2050-0039
263.30..................................................       2050-0039
                                                                        
------------------------------------------------------------------------
    Standards for Owners and Operators of Hazardous Waste Treatment,    
                    Storage, and Disposal Facilities                    
                                                                        
------------------------------------------------------------------------
264.11..................................................       2050-0028
264.12 (a)..............................................       2050-0120
264.13..................................................     2050-0120 &
                                                               2050-0009
264.14..................................................       2050-0009
264.15..................................................     2050-0120 &
                                                               2050-0009
264.16..................................................     2050-0120 &
                                                               2050-0009
264.17..................................................       2050-0120
264.18..................................................       2050-0009
264.19..................................................       2050-0009
264.32..................................................       2050-0009
264.35..................................................       2050-0009
264.37..................................................       2050-0120
264.51..................................................       2050-0009
264.52..................................................       2050-0009
264.53..................................................       2050-0120
264.54..................................................       2050-0120
264.56..................................................       2050-0120
264.71..................................................       2050-0039
264.72..................................................       2050-0039
264.73..................................................       2050-0120
264.74..................................................       2050-0120
264.75..................................................       2050-0024
264.76..................................................       2050-0039
264.90..................................................       2050-0009
264.96..................................................       2050-0120
264.97 (g)..............................................       2050-0120
264.97 (h)..............................................       2050-0009
264.97 (j)..............................................       2050-0120
264.98 (c), (g)(1), (g)(5), (g)(6)......................       2050-0033
264.98 (g)(4), (h)......................................       2050-0009
264.99 (c), (g), (h)(1), (i)(1), (i)(2).................       2050-0033
264.99 (h)(2), (i)(3), (j)..............................       2050-0009
264.100 (e), (f), (g)...................................       2050-0033
264.100 (h).............................................       2050-0009
264.101.................................................       2050-0120
264.112 (a), (b), (c)...................................       2050-0009
264.112 (d).............................................       2050-0120
264.113 (a), (b), (d)...................................       2050-0120
264.113 (e).............................................       2050-0050
264.115.................................................       2050-0120
264.116.................................................       2050-0120
264.118.................................................       2050-0009
264.119 (a) & (b).......................................       2050-0120
264.119 (c).............................................       2050-0009
264.120.................................................       2050-0120
264.142 (a).............................................       2050-0009
264.142 (b), (c), (d)...................................       2050-0120
264.143.................................................       2050-0120
264.144 (a).............................................       2050-0009
264.144 (b), (c), (d)...................................       2050-0120
264.145.................................................       2050-0120
264.147 (a)(7), (b)(7), (f),(g).........................       2050-0120
264.147 (a)(1), (b)(1), (c), (f), (g), (h), (i), (j)....       2050-0009
264.148.................................................       2050-0120
264.149.................................................       2050-0009
264.150.................................................       2050-0009
264.190.................................................       2050-0050
264.191.................................................       2050-0050
264.192 (a).............................................       2050-0009
264.192 (g).............................................       2050-0050
264.193 (c), (d), (e), (g), (h).........................       2050-0009
264.193 (i).............................................       2050-0050
264.196.................................................       2050-0050
264.197 (b).............................................       2050-0050
264.197 (c).............................................       2050-0009
264.221.................................................       2050-0009
264.222 (a).............................................       2050-0009
264.222 (b).............................................       2050-0050
264.223 (a).............................................       2050-0009
264.223 (b), (c)........................................       2050-0050
264.226 (c).............................................     2050-0050 &
                                                               2050-0009
264.226 (d).............................................       2050-0050
264.227.................................................       2050-0050
264.231.................................................       2050-0009
264.251.................................................       2050-0009
264.252 (a).............................................       2050-0009
264.252 (b).............................................       2050-0050
264.253 (a).............................................       2050-0009
264.253 (b), (c)........................................       2050-0050
264.254.................................................       2050-0050
264.259.................................................       2050-0009
264.271.................................................       2050-0009
264.272.................................................       2050-0009
264.276.................................................     2050-0050 &
                                                               2050-0009
264.278 (a)-(f), (h)....................................       2050-0050
264.278 (g).............................................     2050-0050 &
                                                               2050-0009
264.280.................................................       2050-0050
264.283.................................................       2050-0009
264.301.................................................       2050-0009
264.302 (a).............................................       2050-0009
264.302 (b).............................................       2050-0050
264.303 (a).............................................       2050-0009
264.303 (b).............................................       2050-0050
264.304 (a).............................................       2050-0009
264.304 (b), (c)........................................       2050-0050
264.314.................................................       2050-0050
264.317.................................................       2050-0009
264.340.................................................       2050-0009
264.343.................................................       2050-0050
264.344.................................................       2050-0009
264.347.................................................       2050-0050
264.552.................................................       2050-0009
264.570.................................................       2050-0050
264.571.................................................       2050-0050
264.573.................................................       2050-0050
264.574.................................................       2050-0050
264.575.................................................       2050-0009
264.603.................................................       2050-0050
264.1033 (a)............................................       2050-0009
264.1033 (j)............................................       2050-0050
264.1034................................................       2050-0050
264.1035................................................       2050-0050
264.1036................................................       2050-0050
264.1061................................................       2050-0050
264.1062................................................       2050-0050
264.1063................................................       2050-0050
264.1064................................................     2050-0050 &
                                                               2050-0009

[[Page 721]]

                                                                        
264.1065................................................       2050-0050
264.1089................................................       2060-0318
264.1090................................................       2060-0318
264.1100................................................       2050-0050
264.1101................................................       2050-0050
                                                                        
------------------------------------------------------------------------
  Interim Status Standards for Owners and Operators of Hazardous Waste  
               Treatment, Storage, and Disposal Facilities              
                                                                        
------------------------------------------------------------------------
265.11..................................................       2050-0028
265.12 (a)..............................................       2050-0120
265.13..................................................       2050-0120
265.15..................................................       2050-0120
265.16..................................................       2050-0120
265.19..................................................       2050-0120
265.37..................................................       2050-0120
265.51..................................................       2050-0120
265.52..................................................       2050-0120
265.53..................................................       2050-0120
265.54..................................................       2050-0120
265.56..................................................       2050-0120
265.71..................................................       2050-0039
265.72..................................................       2050-0039
265.73..................................................       2050-0120
265.75..................................................       2050-0024
265.76..................................................       2050-0039
265.90..................................................       2050-0033
265.92..................................................       2050-0033
265.93..................................................       2050-0033
265.94..................................................       2050-0033
265.112.................................................       2050-0120
265.113 (a), (b), (d)...................................       2050-0120
265.113 (e).............................................       2050-0050
265.115.................................................       2050-0120
265.116.................................................       2050-0120
265.118.................................................       2050-0120
265.119.................................................       2050-0120
265.120.................................................       2050-0120
265.142.................................................       2050-0120
265.143.................................................       2050-0120
265.144.................................................       2050-0120
265.145.................................................       2050-0120
265.147.................................................       2050-0120
265.148.................................................       2050-0120
265.149.................................................       2050-0120
265.150.................................................       2050-0120
265.190.................................................     2050-0035 &
                                                               2050-0050
265.191.................................................     2050-0035 &
                                                               2050-0050
265.192.................................................     2050-0035 &
                                                               2050-0050
265.193.................................................     2050-0035 &
                                                               2050-0050
265.195.................................................       2050-0120
265.196.................................................     2050-0035 &
                                                               2050-0050
265.197 (b).............................................       2050-0050
265.197 (c).............................................       2050-0120
265.221.................................................       2050-0050
265.222.................................................       2050-0050
265.223.................................................       2050-0050
265.225.................................................       2050-0050
265.226.................................................       2050-0050
265.229.................................................       2050-0050
265.254.................................................       2050-0050
265.255.................................................       2050-0050
265.259.................................................       2050-0050
265.260.................................................       2050-0050
265.273.................................................       2050-0120
265.276.................................................       2050-0050
265.278.................................................       2050-0050
265.280.................................................       2050-0050
265.301.................................................       2050-0050
265.302.................................................       2050-0050
265.303.................................................       2050-0050
265.304.................................................       2050-0050
265.314.................................................       2050-0050
265.340.................................................       2050-0050
265.352.................................................       2050-0050
265.383.................................................       2050-0050
265.404.................................................       2050-0050
265.440.................................................       2050-0050
265.441.................................................       2050-0050
265.443.................................................       2050-0050
265.444.................................................       2050-0050
265.445.................................................       2050-0120
265.1033................................................       2050-0050
265.1034................................................       2050-0050
265.1035................................................       2050-0050
265.1061................................................       2050-0050
265.1062................................................       2050-0050
265.1063................................................       2050-0050
265.1064................................................       2050-0050
265.1090................................................       2060-0318
265.1100................................................       2050-0050
265.1101................................................       2050-0050
                                                                        
------------------------------------------------------------------------
 Standards for the Management of Specific Hazardous Wastes and Specific 
             Types of Hazardous Waste Management Facilities             
                                                                        
------------------------------------------------------------------------
266.70 (b)..............................................       2050-0028
266.70 (c)..............................................       2050-0050
266.80..................................................       2050-0028
266.100.................................................       2050-0073
266.102.................................................       2050-0073
266.103.................................................       2050-0073
266.104.................................................       2050-0073
266.106.................................................       2050-0073
266.107.................................................       2050-0073
266.108.................................................       2050-0073
266.109.................................................       2050-0073
266.111.................................................       2050-0073
266.112.................................................       2050-0073
Appendix IX.............................................       2050-0073
                                                                        
------------------------------------------------------------------------
                       Land Disposal Restrictions                       
                                                                        
------------------------------------------------------------------------
268.4-268.5.............................................       2050-0085
268.6...................................................       2050-0062
268.7...................................................       2050-0085
268.9...................................................       2050-0085
268.42..................................................       2050-0085
268.44..................................................       2050-0085
                                                                        
------------------------------------------------------------------------
  EPA Administered Permit Programs: The Hazardous Waste Permit Program  
                                                                        
------------------------------------------------------------------------
270.1...................................................     2050-0028 &
                                                             2050-0034 &
                                                               2050-0009
270.10..................................................       2050-0009
270.11..................................................       2050-0034
270.13..................................................       2050-0034
270.14..................................................       2050-0009
270.14 (b)(21)..........................................     2050-0062 &
                                                               2050-0085
270.15..................................................       2050-0009
270.16..................................................       2050-0009
270.17..................................................       2050-0009
270.18..................................................       2050-0009

[[Page 722]]

                                                                        
270.19..................................................       2050-0009
270.20..................................................       2050-0009
270.21..................................................       2050-0009
270.22..................................................       2050-0073
270.23..................................................       2050-0009
270.24..................................................       2050-0009
270.25..................................................       2050-0009
270.26..................................................       2050-0115
270.30..................................................       2050-0120
270.33..................................................       2050-0009
270.40..................................................       2050-0009
270.41..................................................       2050-0009
270.42..................................................       2050-0009
270.51..................................................       2050-0009
270.62..................................................     2050-0009 &
                                                               2050-0149
270.63..................................................       2050-0009
270.65..................................................       2050-0009
270.66..................................................     2050-0073 &
                                                               2050-0149
270.72..................................................       2050-0034
270.73..................................................       2050-0009
                                                                        
------------------------------------------------------------------------
    Requirements for Authorization of State Hazardous Waste Programs    
                                                                        
------------------------------------------------------------------------
271.5-271.8.............................................       2050-0041
271.20-271.21...........................................       2050-0041
271.23..................................................       2050-0041
                                                                        
------------------------------------------------------------------------
                Standards for Universal Waste Management                
                                                                        
------------------------------------------------------------------------
273.14..................................................       2050-0145
273.15..................................................       2050-0145
273.18..................................................       2050-0145
273.32..................................................       2050-0145
273.34..................................................       2050-0145
273.35..................................................       2050-0145
273.38..................................................       2050-0145
273.39..................................................       2050-0145
273.61..................................................       2050-0145
273.62..................................................       2050-0145
273.80..................................................       2050-0145
                                                                        
------------------------------------------------------------------------
                  Standards for Management of Used Oil                  
                                                                        
------------------------------------------------------------------------
279.10-279.11...........................................       2050-0124
279.42..................................................      2050-0028,
                                                               2050-0124
279.43-279.44...........................................       2050-0124
279.46..................................................       2050-0050
279.51..................................................       2050-0028
279.52-279.55...........................................       2050-0124
279.56..................................................       2050-0050
279.57..................................................      2050-0050,
                                                               2050-0124
279.62..................................................       2050-0028
279.63..................................................       2050-0124
279.65-279.66...........................................       2050-0050
279.72..................................................       2050-0050
279.73..................................................       2050-0028
279.74-279.75...........................................       2050-0050
279.82..................................................       2050-0124
                                                                        
------------------------------------------------------------------------
  Technical Standards and Corrective Action Requirements for Owners and 
             Operators of Underground Storage Tanks (USTs)              
                                                                        
------------------------------------------------------------------------
                                                                        
280.11(a)...............................................       2050-0068
280.20(a)-(b)...........................................       2050-0068
280.20(e)...............................................       2050-0068
280.22(a)-(f)...........................................       2050-0068
280.22(g)...............................................       2050-0068
280.31..................................................       2050-0068
280.33(f)...............................................       2050-0068
280.34(a)...............................................       2050-0068
280.34(b)...............................................       2050-0068
280.34(c)...............................................       2050-0068
280.40..................................................       2050-0068
280.43..................................................       2050-0068
280.44..................................................       2050-0068
280.45..................................................       2050-0068
280.50..................................................       2050-0068
280.53..................................................       2050-0068
280.61..................................................       2050-0068
280.62..................................................       2050-0068
280.63..................................................       2050-0068
280.64..................................................       2050-0068
280.65..................................................       2050-0068
280.66(a)...............................................       2050-0068
280.66(c)...............................................       2050-0068
280.66(d)...............................................       2050-0068
280.67..................................................       2050-0068
280.71(a)...............................................       2050-0068
280.72(a)...............................................       2050-0068
280.74..................................................       2050-0068
280.95..................................................       2050-0068
280.96..................................................       2050-0068
280.97..................................................       2050-0068
280.98..................................................       2050-0068
280.99..................................................       2050-0068
280.100.................................................       2050-0068
280.101.................................................       2050-0068
280.102.................................................       2050-0068
280.103.................................................       2050-0068
280.104.................................................       2050-0068
280.105.................................................       2050-0068
280.106.................................................       2050-0068
280.107.................................................       2050-0068
280.108.................................................       2050-0068
280.109(a)..............................................       2050-0068
280.109(b)..............................................       2050-0068
280.110.................................................       2050-0068
280.111.................................................       2050-0068
280.111(b)(11)..........................................       2050-0068
280.114(a)-(d)..........................................       2050-0068
280.114(e)..............................................       2050-0068
                                                                        
------------------------------------------------------------------------
           Approval of State Underground Storage Tank Programs          
                                                                        
------------------------------------------------------------------------
281.120(a)..............................................       2050-0068
281.120(g)..............................................       2050-0068
281.121.................................................       2050-0068
281.122.................................................       2050-0068
281.124.................................................       2050-0068
281.125.................................................       2050-0068
281.140.................................................       2050-0068
281.143(a)..............................................       2050-0068
281.150.................................................       2050-0068
281.152.................................................       2050-0068
281.161.................................................       2050-0068
                                                                        
------------------------------------------------------------------------
    National Oil and Hazardous Substances Pollution Contingency Plan    
                                                                        
------------------------------------------------------------------------
300.405.................................................       2050-0046
300.425.................................................       2050-0095
300.430.................................................       2050-0096
300.435.................................................       2050-0096
300.920.................................................       2050-0141
Part 300, Appendix A....................................       2050-0095
                                                                        
------------------------------------------------------------------------

[[Page 723]]

                                                                        
          Designation, reportable quantities, and notification          
                                                                        
------------------------------------------------------------------------
302.4...................................................       2050-0046
302.6...................................................       2050-0046
302.8...................................................       2050-0086
                                                                        
------------------------------------------------------------------------
       Hazardous Substances Superfund; Response Claims Procedures       
                                                                        
------------------------------------------------------------------------
307.11-307.14...........................................       2050-0106
307.21-307.23...........................................       2050-0106
307.30-307.32...........................................       2050-0106
                                                                        
------------------------------------------------------------------------
 Reimbursement to Local Governments for Emergency Response to Hazardous 
                           Substance Releases                           
                                                                        
------------------------------------------------------------------------
310.05..................................................       2050-0077
310.10-310.12...........................................       2050-0077
310.20..................................................       2050-0077
310.30..................................................       2050-0077
310.40..................................................       2050-0077
310.50..................................................       2050-0077
310.60..................................................       2050-0077
310.70..................................................       2050-0077
310.80..................................................       2050-0077
310.90..................................................       2050-0077
Part 310, Appendix II...................................       2050-0077
                                                                        
------------------------------------------------------------------------
Worker Protection Standards for Hazardous Waste Operations and Emergency
                                Response                                
                                                                        
------------------------------------------------------------------------
311.1-311.2.............................................       2050-0105
                                                                        
------------------------------------------------------------------------
Trade Secrecy Claims for Emergency Planning and Community Right-to-Know;
                          Health Professionals                          
                                                                        
------------------------------------------------------------------------
350.5-350.16............................................       2050-0078
350.27..................................................       2050-0078
350.40..................................................       2050-0078
                                                                        
------------------------------------------------------------------------
                   Emergency planning and notification                  
                                                                        
------------------------------------------------------------------------
Part 355, Appendix A, Appendix B........................       2050-0046
                                                                        
------------------------------------------------------------------------
        Toxic Chemical Release Reporting: Community Right-to-Know       
                                                                        
------------------------------------------------------------------------
part 372................................................       2070-0093
part 372, subpart A.....................................     2070-0093 &
                                                               2070-0143
372.22..................................................     2070-0093 &
                                                               2070-0143
372.25..................................................       2070-0093
372.27..................................................       2070-0143
372.30..................................................     2070-0093 &
                                                               2070-0143
372.38..................................................     2070-0093 &
                                                               2070-0143
part 372, subpart C.....................................     2070-0093 &
                                                               2070-0143
part 372, subpart D.....................................     2070-0093 &
                                                               2070-0143
372.85..................................................       2070-0093
372.95..................................................       2070-0143
                                                                        
------------------------------------------------------------------------
    General Pretreatment Regulations for Existing and New Sources of    
                                Pollution                               
                                                                        
------------------------------------------------------------------------
403.5(b)................................................       2040-0009
403.6-403.7.............................................       2040-0009
403.8(a)-(e)............................................       2040-0009
403.8(f)................................................       2040-0009
403.9-403.10............................................       2040-0009
403.12(b)-(g)...........................................       2040-0009
403.12 (h), (i).........................................       2040-0009
403.12 (j), (k), (l), (o)...............................       2040-0009
403.12 (m), (p).........................................       2040-0009
403.13..................................................       2040-0009
403.15..................................................       2040-0009
403.17-403.18...........................................      2040-0009,
                                                               2040-0170
                                                                        
------------------------------------------------------------------------
            Steam Electric Generating Point Source Category             
                                                                        
------------------------------------------------------------------------
423.12-423.13...........................................       2040-0033
423.15..................................................       2040-0033
                                                                        
------------------------------------------------------------------------
           Pulp, Paper, and Paperboard Point Source Category            
                                                                        
------------------------------------------------------------------------
430.14-430.17...........................................       2040-0033
430.24-430.27...........................................       2040-0033
430.54-430.57...........................................       2040-0033
430.64-430.67...........................................       2040-0033
430.74-430.77...........................................       2040-0033
430.84-430.87...........................................       2040-0033
430.94-430.97...........................................       2040-0033
430.104-430.107.........................................       2040-0033
430.114-430.117.........................................       2040-0033
430.134-430.137.........................................       2040-0033
430.144-430.147.........................................       2040-0033
430.154-430.157.........................................       2040-0033
430.164-430.167.........................................       2040-0033
430.174-430.177.........................................       2040-0033
430.184-430.187.........................................       2040-0033
430.194-430.197.........................................       2040-0033
430.204-430.207.........................................       2040-0033
430.214-430.217.........................................       2040-0033
430.224-430.227.........................................       2040-0033
430.234-430.237.........................................       2040-0033
430.244-430.247.........................................       2040-0033
430.254-430.257.........................................       2040-0033
430.264-430.267.........................................       2040-0033
                                                                        
------------------------------------------------------------------------
        The Builders' Paper and Board Mills Point Source Category       
                                                                        
------------------------------------------------------------------------
431.14-431.17...........................................       2040-0033
                                                                        
------------------------------------------------------------------------
            Pharmaceutical Manufacturing Point Source Category          
                                                                        
------------------------------------------------------------------------
439.14-439.17...........................................       2040-0033
439.24-439.27...........................................       2040-0033
439.34-439.37...........................................       2040-0033
439.44-439.47...........................................       2040-0033
                                                                        
------------------------------------------------------------------------
                   Coil Coating Point Source Category                   
                                                                        
------------------------------------------------------------------------
465.03..................................................       2040-0033
                                                                        
------------------------------------------------------------------------
               Porcelain Enameling Point Source Category                
                                                                        
------------------------------------------------------------------------
466.03..................................................       2040-0033
                                                                        
------------------------------------------------------------------------

[[Page 724]]

                                                                        
                 Aluminum Forming Point Source Category                 
                                                                        
------------------------------------------------------------------------
467.03..................................................       2040-0033
                                                                        
------------------------------------------------------------------------
              State Sludge Management Program Requirements              
                                                                        
------------------------------------------------------------------------
501.15(a)...............................................      2040-0086,
                                                               2040-0110
501.15(b)...............................................      2040-0004,
                                                              2040-0068,
                                                               2040-0110
501.15(c)...............................................       2040-0068
501.16..................................................       2040-0057
501.21..................................................       2040-0057
                                                                        
------------------------------------------------------------------------
           Standards for the Use or Disposal of Sewage Sludge           
                                                                        
------------------------------------------------------------------------
503.17-503.18...........................................       2040-0157
503.27-503.28...........................................       2040-0157
503.47-503.48...........................................       2040-0157
                                                                        
------------------------------------------------------------------------
                     Fuel Economy of Motor Vehicles                     
                                                                        
------------------------------------------------------------------------
600.006-86..............................................       2060-0104
600.007-80..............................................       2060-0104
600.010-86..............................................       2060-0104
600.113-88..............................................       2060-0104
600.113-93..............................................       2060-0104
600.206-86..............................................       2060-0104
600.207-86..............................................       2060-0104
600.209-85..............................................       2060-0104
600.306-86..............................................       2060-0104
600.307-86..............................................       2060-0104
600.311-86..............................................       2060-0104
600.312-86..............................................       2060-0104
600.313-86..............................................       2060-0104
600.314-86..............................................       2060-0104
600.507-86..............................................       2060-0104
600.509-86..............................................       2060-0104
600.510-86..............................................       2060-0104
600.512-86..............................................       2060-0104
                                                                        
------------------------------------------------------------------------
                  Toxic Substances Control Act: General                 
                                                                        
------------------------------------------------------------------------
700.45..................................................     2070-0012 &
                                                               2070-0038
                                                                        
------------------------------------------------------------------------
                Reporting and Recordkeeping Requirements                
                                                                        
------------------------------------------------------------------------
704.5...................................................     2010-0019 &
                                                               2070-0067
704.11..................................................     2010-0019 &
                                                               2070-0067
704.25..................................................       2070-0067
704.33..................................................       2070-0067
704.43..................................................       2070-0067
704.45..................................................       2070-0067
704.95..................................................       2070-0067
704.102.................................................       2070-0067
704.104.................................................       2070-0067
704.175.................................................       2070-0067
                                                                        
------------------------------------------------------------------------
                      Chemical Imports and Exports                      
                                                                        
------------------------------------------------------------------------
707.65..................................................       2070-0030
707.67..................................................       2070-0030
707.72..................................................       2070-0030
                                                                        
------------------------------------------------------------------------
                     Inventory Reporting Regulations                    
                                                                        
------------------------------------------------------------------------
part 710................................................       2070-0070
                                                                        
------------------------------------------------------------------------
                       Chemical Information Rules                       
                                                                        
------------------------------------------------------------------------
712.5...................................................       2070-0054
712.7...................................................       2070-0054
712.20..................................................       2070-0054
712.28..................................................       2070-0054
712.30..................................................       2070-0054
                                                                        
------------------------------------------------------------------------
                    Health and Safety Data Reporting                    
                                                                        
------------------------------------------------------------------------
716.5...................................................       2070-0004
716.10..................................................       2070-0004
716.20..................................................       2070-0004
716.25..................................................       2070-0004
716.30..................................................       2070-0004
716.35..................................................       2070-0004
716.40..................................................       2070-0004
716.45..................................................       2070-0004
716.50..................................................       2070-0004
716.60..................................................       2070-0004
716.65..................................................       2070-0004
716.105.................................................       2070-0004
716.120.................................................       2070-0004
                                                                        
------------------------------------------------------------------------
    Records and Reports of Allegations that Chemical Substances Cause   
       Significant Adverse Reactions to Health or the Environment       
                                                                        
------------------------------------------------------------------------
717.5...................................................       2070-0017
717.7...................................................       2070-0017
717.12..................................................       2070-0017
717.15..................................................       2070-0017
717.17..................................................       2070-0017
                                                                        
------------------------------------------------------------------------
                       Premanufacture Notification                      
                                                                        
------------------------------------------------------------------------
720.1...................................................       2070-0012
720.22..................................................       2070-0012
720.25..................................................       2070-0012
720.30..................................................       2070-0012
720.36..................................................       2070-0012
720.38..................................................       2070-0012
part 720, subpart C.....................................       2070-0012
720.62..................................................       2070-0012
720.75..................................................       2070-0012
720.78..................................................       2070-0012
720.80..................................................       2070-0012
720.85..................................................       2070-0012
720.87..................................................       2070-0012
720.90..................................................       2070-0012
720.102.................................................       2070-0012
part 720, Appendix A....................................       2070-0012
                                                                        
------------------------------------------------------------------------
               Significant New Uses of Chemical Substances              
                                                                        
------------------------------------------------------------------------
part 721, subpart A.....................................     2070-0012 &
                                                               2070-0038
721.72..................................................     2070-0012 &
                                                               2070-0038
721.125.................................................     2070-0012 &
                                                               2070-0038
721.160.................................................     2070-0012 &
                                                               2070-0038
721.170.................................................     2070-0012 &
                                                               2070-0038

[[Page 725]]

                                                                        
721.185.................................................     2070-0012 &
                                                               2070-0038
721.225.................................................       2070-0012
721.275.................................................       2070-0012
721.285.................................................       2070-0012
721.320.................................................       2070-0012
721.323.................................................       2070-0012
721.325.................................................       2070-0012
721.370.................................................       2070-0012
721.390.................................................       2070-0012
721.400.................................................       2070-0012
721.415.................................................       2070-0012
721.430.................................................       2070-0012
721.445.................................................       2070-0012
721.460.................................................       2070-0012
721.470.................................................       2070-0012
721.490.................................................       2070-0012
721.505.................................................       2070-0012
721.520.................................................       2070-0012
721.530.................................................       2070-0012
721.536.................................................       2070-0012
721.540.................................................       2070-0012
721.550.................................................       2070-0012
721.562.................................................       2070-0012
721.575.................................................       2070-0012
721.600.................................................       2070-0012
721.625.................................................       2070-0012
721.639.................................................       2070-0012
721.642.................................................       2070-0012
721.650.................................................       2070-0038
721.700.................................................       2070-0012
721.715.................................................       2070-0012
721.750.................................................       2070-0012
721.757.................................................       2070-0012
721.775.................................................       2070-0012
721.805.................................................       2070-0012
721.825.................................................       2070-0012
721.840.................................................       2070-0012
721.875.................................................       2070-0012
721.925.................................................       2070-0012
721.950.................................................       2070-0012
721.982.................................................       2070-0012
721.1000................................................       2070-0012
721.1025................................................       2070-0038
721.1050................................................       2070-0012
721.1068................................................       2070-0012
721.1075................................................       2070-0012
721.1120................................................       2070-0012
721.1150................................................       2070-0012
721.1175................................................       2070-0012
721.1187................................................       2070-0012
721.1193................................................       2070-0012
721.1210................................................       2070-0012
721.1225................................................       2070-0012
721.1240................................................       2070-0012
721.1300................................................       2070-0012
721.1325................................................       2070-0012
721.1350................................................       2070-0012
721.1372................................................       2070-0012
721.1375................................................       2070-0012
721.1425................................................       2070-0038
721.1430................................................       2070-0038
721.1435................................................       2070-0038
721.1440................................................       2070-0038
721.1450................................................       2070-0012
721.1500................................................       2070-0012
721.1525................................................       2070-0012
721.1550................................................       2070-0012
721.1555................................................       2070-0012
721.1568................................................       2070-0012
721.1575................................................       2070-0012
721.1612................................................       2070-0012
721.1625................................................       2070-0012
721.1630................................................       2070-0012
721.1637................................................       2070-0012
721.1640................................................       2070-0012
721.1643................................................       2070-0012
721.1645................................................       2070-0012
721.1650................................................       2070-0012
721.1675................................................       2070-0012
721.1700................................................       2070-0012
721.1725................................................       2070-0012
721.1728................................................       2070-0012
721.1732................................................       2070-0012
721.1735................................................       2070-0012
721.1740................................................       2070-0012
721.1745................................................       2070-0012
721.1750................................................       2070-0012
721.1755................................................       2070-0012
721.1765................................................       2070-0012
721.1769................................................       2070-0012
721.1775................................................       2070-0012
721.1790................................................       2070-0038
721.1800................................................       2070-0012
721.1820................................................       2070-0012
721.1825................................................       2070-0012
721.1850................................................       2070-0012
721.1875................................................       2070-0012
721.1900................................................       2070-0012
721.1907................................................       2070-0012
721.1920................................................       2070-0012
721.1925................................................       2070-0012
721.1950................................................       2070-0012
721.2025................................................       2070-0012
721.2050................................................       2070-0012
721.2075................................................       2070-0012
721.2084................................................       2070-0038
721.2085................................................       2070-0012
721.2086................................................       2070-0012
721.2088................................................       2070-0012
721.2089................................................       2070-0012
721.2092................................................       2070-0038
721.2120................................................       2070-0012
721.2140................................................       2070-0012
721.2170................................................       2070-0012
721.2175................................................       2070-0012
721.2250................................................       2070-0012
721.2260................................................       2070-0012
721.2270................................................       2070-0012
721.2275................................................       2070-0012
721.2287................................................       2070-0038
721.2340................................................       2070-0012
721.2355................................................       2070-0038
721.2380................................................       2070-0012
721.2410................................................       2070-0012
721.2420................................................       2070-0012
721.2475................................................       2070-0012
721.2520................................................       2070-0012
721.2540................................................       2070-0012
721.2560................................................       2070-0012
721.2565................................................       2070-0012
721.2575................................................       2070-0012
721.2600................................................       2070-0038
721.2625................................................       2070-0012
721.2650................................................       2070-0012
721.2675................................................       2070-0012
721.2725................................................       2070-0038
721.2750................................................       2070-0012
721.2800................................................       2070-0038
721.2815................................................       2070-0012
721.2825................................................       2070-0012
721.2840................................................       2070-0012
721.2860................................................       2070-0012
721.2880................................................       2070-0012
721.2900................................................       2070-0012
721.2920................................................       2070-0012

[[Page 726]]

                                                                        
721.2930................................................       2070-0012
721.2940................................................       2070-0012
721.2950................................................       2070-0012
721.2980................................................       2070-0012
721.3000................................................       2070-0012
721.3020................................................       2070-0012
721.3028................................................       2070-0012
721.3034................................................       2070-0012
721.3040................................................       2070-0012
721.3060................................................       2070-0012
721.3080................................................       2070-0012
721.3100................................................       2070-0012
721.3120................................................       2070-0012
721.3140................................................       2070-0012
721.3152................................................       2070-0012
721.3160................................................       2070-0038
721.3180................................................       2070-0012
721.3200................................................       2070-0012
721.3220................................................       2070-0038
721.3248................................................       2070-0012
721.3260................................................       2070-0012
721.3320................................................       2070-0012
721.3340................................................       2070-0012
721.3350................................................       2070-0038
721.3360................................................       2070-0012
721.3364................................................       2070-0012
721.3374................................................       2070-0012
721.3380................................................       2070-0012
721.3390................................................       2070-0012
721.3420................................................       2070-0012
721.3430................................................       2070-0038
721.3435................................................       2070-0012
721.3437................................................       2070-0012
721.3440................................................       2070-0012
721.3460................................................       2070-0012
721.3480................................................       2070-0012
721.3486................................................       2070-0012
721.3500................................................       2070-0012
721.3520................................................       2070-0012
721.3560................................................       2070-0012
721.3620................................................       2070-0012
721.3625................................................       2070-0012
721.3627................................................       2070-0012
721.3629................................................       2070-0012
721.3640................................................       2070-0012
721.3680................................................       2070-0012
721.3700................................................       2070-0012
721.3720................................................       2070-0012
721.3740................................................       2070-0012
721.3760................................................       2070-0012
721.3764................................................       2070-0012
721.3780................................................       2070-0012
721.3790................................................       2070-0012
721.3800................................................       2070-0012
721.3815................................................       2070-0012
721.3840................................................       2070-0012
721.3860................................................       2070-0012
721.3870................................................       2070-0012
721.3880................................................       2070-0012
721.3900................................................       2070-0012
721.4000................................................       2070-0012
721.4020................................................       2070-0012
721.4040................................................       2070-0012
721.4060................................................       2070-0012
721.4080................................................       2070-0038
721.4100................................................       2070-0012
721.4110................................................       2070-0012
721.4128................................................       2070-0012
721.4133................................................       2070-0012
721.4140................................................       2070-0038
721.4155................................................       2070-0038
721.4160................................................       2070-0038
721.4180................................................       2070-0038
721.4200................................................       2070-0012
721.4215................................................       2070-0012
721.4220................................................       2070-0012
721.4240................................................       2070-0012
721.4250................................................       2070-0012
721.4255................................................       2070-0012
721.4260................................................       2070-0012
721.4270................................................       2070-0012
721.4280................................................       2070-0012
721.4300................................................       2070-0012
721.4320................................................       2070-0012
721.4340................................................       2070-0012
721.4360................................................       2070-0038
721.4380................................................       2070-0012
721.4390................................................       2070-0012
721.4400................................................       2070-0012
721.4420................................................       2070-0012
721.4460................................................       2070-0012
721.4463................................................       2070-0012
721.4466................................................       2070-0012
721.4470................................................       2070-0012
721.4473................................................       2070-0012
721.4480................................................       2070-0012
721.4490................................................       2070-0012
721.4500................................................       2070-0012
721.4520................................................       2070-0012
721.4550................................................       2070-0012
721.4568................................................       2070-0012
721.4585................................................       2070-0012
721.4590................................................       2070-0012
721.4594................................................       2070-0012
721.4600................................................       2070-0012
721.4620................................................       2070-0012
721.4640................................................       2070-0012
721.4660................................................       2070-0012
721.4680................................................       2070-0012
721.4700................................................       2070-0012
721.4720................................................       2070-0012
721.4740................................................       2070-0038
721.4780................................................       2070-0012
721.4790................................................       2070-0012
721.4794................................................       2070-0012
721.4800................................................       2070-0012
721.4820................................................       2070-0012
721.4840................................................       2070-0012
721.4880................................................       2070-0012
721.4925................................................       2070-0038
721.5050................................................       2070-0012
721.5075................................................       2070-0012
721.5175................................................       2070-0038
721.5192................................................       2070-0012
721.5200................................................       2070-0012
721.5225................................................       2070-0012
721.5250................................................       2070-0012
721.5275................................................       2070-0012
721.5278................................................       2070-0012
721.5282................................................       2070-0012
721.5285................................................       2070-0012
721.5300................................................       2070-0012
721.5310................................................       2070-0012
721.5325................................................       2070-0012
721.5330................................................       2070-0012
721.5350................................................       2070-0012
721.5375................................................       2070-0012
721.5385................................................       2070-0012
721.5400................................................       2070-0012
721.5425................................................       2070-0012
721.5450................................................       2070-0012
721.5475................................................       2070-0012
721.5500................................................       2070-0012
721.5525................................................       2070-0012
721.5540................................................       2070-0012
721.5550................................................       2070-0012

[[Page 727]]

                                                                        
721.5575................................................       2070-0012
721.5600................................................       2070-0038
721.5700................................................       2070-0012
721.5705................................................       2070-0012
721.5710................................................       2070-0038
721.5740................................................       2070-0012
721.5760................................................       2070-0012
721.5763................................................       2070-0012
721.5769................................................       2070-0012
721.5780................................................       2070-0012
721.5800................................................       2070-0012
721.5820................................................       2070-0012
721.5840................................................       2070-0012
721.5860................................................       2070-0012
721.5867................................................       2070-0012
721.5880................................................       2070-0012
721.5900................................................       2070-0012
721.5910................................................       2070-0012
721.5915................................................       2070-0012
721.5920................................................       2070-0012
721.5960................................................       2070-0012
721.5970................................................       2070-0012
721.5980................................................       2070-0012
721.5990................................................       2070-0012
721.6000................................................       2070-0038
721.6020................................................       2070-0012
721.6060................................................       2070-0012
721.6070................................................       2070-0012
721.6080................................................       2070-0012
721.6085................................................       2070-0012
721.6090................................................       2070-0012
721.6100................................................       2070-0012
721.6110................................................       2070-0012
721.6120................................................       2070-0012
721.6140................................................       2070-0012
721.6160................................................       2070-0012
721.6180................................................       2070-0012
721.6186................................................       2070-0012
721.6200................................................       2070-0012
721.6220................................................       2070-0012
721.6440................................................       2070-0012
721.6470................................................       2070-0012
721.6500................................................       2070-0012
721.6520................................................       2070-0012
721.6540................................................       2070-0012
721.6560................................................       2070-0012
721.6580................................................       2070-0012
721.6600................................................       2070-0012
721.6620................................................       2070-0012
721.6625................................................       2070-0012
721.6640................................................       2070-0012
721.6660................................................       2070-0012
721.6680................................................       2070-0012
721.6700................................................       2070-0012
721.6720................................................       2070-0012
721.6740................................................       2070-0012
721.6760................................................       2070-0012
721.6780................................................       2070-0012
721.6820................................................       2070-0012
721.6840................................................       2070-0012
721.6880................................................       2070-0012
721.6900................................................       2070-0012
721.6920................................................       2070-0012
721.6940................................................       2070-0012
721.6960................................................       2070-0012
721.6980................................................       2070-0012
721.7000................................................       2070-0012
721.7020................................................       2070-0012
721.7040................................................       2070-0012
721.7046................................................       2070-0012
721.7080................................................       2070-0012
721.7100................................................       2070-0012
721.7140................................................       2070-0012
721.7160................................................       2070-0012
721.7180................................................       2070-0012
721.7200................................................       2070-0012
721.7210................................................       2070-0012
721.7220................................................       2070-0012
721.7240................................................       2070-0012
721.7260................................................       2070-0012
721.7280................................................       2070-0012
721.7300................................................       2070-0012
721.7320................................................       2070-0012
721.7340................................................       2070-0012
721.7360................................................       2070-0012
721.7370................................................       2070-0012
721.7400................................................       2070-0012
721.7420................................................       2070-0012
721.7440................................................       2070-0012
721.7450................................................       2070-0012
721.7460................................................       2070-0012
721.7480................................................       2070-0012
721.7500................................................       2070-0012
721.7540................................................       2070-0012
721.7560................................................       2070-0012
721.7580................................................       2070-0012
721.7600................................................       2070-0012
721.7620................................................       2070-0012
721.7655................................................       2070-0012
721.7660................................................       2070-0012
721.7680................................................       2070-0012
721.7780................................................       2070-0012
721.7710................................................       2070-0012
721.7720................................................       2070-0012
721.7700................................................       2070-0012
721.7740................................................       2070-0012
721.7760................................................       2070-0012
721.7770................................................       2070-0012
721.8075................................................       2070-0012
721.8082................................................       2070-0012
721.8090................................................       2070-0012
721.8100................................................       2070-0012
721.8155................................................       2070-0012
721.8160................................................       2070-0012
721.8170................................................       2070-0012
721.8175................................................       2070-0012
721.8225................................................       2070-0012
721.8250................................................       2070-0012
721.8265................................................       2070-0012
721.8275................................................       2070-0012
721.8290................................................       2070-0012
721.8300................................................       2070-0012
721.8325................................................       2070-0012
721.8335................................................       2070-0012
721.8350................................................       2070-0012
721.8375................................................       2070-0012
721.8400................................................       2070-0012
721.8425................................................       2070-0012
721.8450................................................       2070-0012
721.8475................................................       2070-0012
721.8500................................................       2070-0012
721.8525................................................       2070-0012
721.8550................................................       2070-0012
721.8575................................................       2070-0012
721.8600................................................       2070-0012
721.8650................................................       2070-0012
721.8654................................................       2070-0012
721.8670................................................       2070-0012
721.8675................................................       2070-0012
721.8700................................................       2070-0012
721.8750................................................       2070-0012
721.8775................................................       2070-0012
721.8825................................................       2070-0012
721.8850................................................       2070-0012
721.8875................................................       2070-0012
721.8900................................................       2070-0012

[[Page 728]]

                                                                        
721.8965................................................       2070-0012
721.9000................................................       2070-0038
721.9075................................................       2070-0012
721.9100................................................       2070-0012
721.9220................................................       2070-0012
721.9240................................................       2070-0012
721.9260................................................       2070-0012
721.9280................................................       2070-0012
721.9300................................................       2070-0012
721.9320................................................       2070-0012
721.9360................................................       2070-0012
721.9400................................................       2070-0012
721.9420................................................       2070-0012
721.9460................................................       2070-0012
721.9470................................................       2070-0038
721.9480................................................       2070-0012
721.9500................................................       2070-0012
721.9505................................................       2070-0012
721.9510................................................       2070-0012
721.9520................................................       2070-0012
721.9525................................................       2070-0012
721.9526................................................       2070-0012
721.9527................................................       2070-0012
721.9530................................................       2070-0012
721.9540................................................       2070-0012
721.9550................................................       2070-0012
721.9570................................................       2070-0012
721.9580................................................       2070-0038
721.9620................................................       2070-0012
721.9630................................................       2070-0012
721.9650................................................       2070-0012
721.9656................................................       2070-0012
721.9658................................................       2070-0012
721.9660................................................       2070-0038
721.9665................................................       2070-0012
721.9675................................................       2070-0012
721.9700................................................       2070-0012
721.9720................................................       2070-0012
721.9730................................................       2070-0012
721.9740................................................       2070-0012
721.9750................................................       2070-0012
721.9780................................................       2070-0012
721.9800................................................       2070-0012
721.9820................................................       2070-0012
721.9850................................................       2070-0012
721.9870................................................       2070-0012
721.9892................................................       2070-0012
721.9900................................................       2070-0012
721.9920................................................       2070-0012
721.9925................................................       2070-0012
721.9930................................................       2070-0038
721.9940................................................       2070-0012
721.9957................................................       2070-0038
721.9975................................................       2070-0012
                                                                        
------------------------------------------------------------------------
                 Premanufacture Notification Exemptions                 
                                                                        
------------------------------------------------------------------------
723.50..................................................       2070-0012
723.175.................................................       2070-0012
723.250(m)(1)...........................................       2070-0012
                                                                        
------------------------------------------------------------------------
Lead-Based Paint Poisioning Prevention in Certain Residential Structures
                                                                        
------------------------------------------------------------------------
part 745, subpart F.....................................       2070-0151
                                                                        
------------------------------------------------------------------------
                        Water Treatment Chemicals                       
                                                                        
------------------------------------------------------------------------
part 749, subpart D.....................................       2060-0193
749.68..................................................       2060-0193
                                                                        
------------------------------------------------------------------------
Polychlorinated Biphenyls (PCBs) Manufacturing, Processing, Distribution
                    in Commerce, and Use Prohibitions                   
                                                                        
------------------------------------------------------------------------
761.20..................................................     2070-0008 &
                                                               2070-0021
761.30..................................................      2070-0003,
                                                             2070-0008 &
                                                               2070-0021
761.60..................................................       2070-0011
761.65..................................................       2070-0112
761.70..................................................       2070-0011
761.75..................................................       2070-0011
761.80..................................................       2070-0021
761.93(a)(1)(iii).......................................       2070-0149
761.93(b)...............................................       2070-0149
761.125.................................................       2070-0112
761.180.................................................       2070-0112
761.185.................................................       2070-0008
761.187.................................................       2070-0008
761.193.................................................       2070-0008
761.202.................................................       2070-0112
761.205.................................................       2070-0112
761.207.................................................       2070-0112
761.207(a)..............................................       2050-0039
761.208.................................................       2070-0112
761.209.................................................       2070-0112
761.210.................................................       2070-0112
761.211.................................................       2070-0112
761.215.................................................       2070-0112
761.218.................................................       2070-0112
                                                                        
------------------------------------------------------------------------
                                Asbestos                                
                                                                        
------------------------------------------------------------------------
part 763, subpart E.....................................       2070-0091
part 763, subpart G.....................................       2070-0072
part 763, subpart I.....................................       2070-0082
                                                                        
------------------------------------------------------------------------
                    Dibenzo-para-dioxin/Dibenzofurans                   
                                                                        
------------------------------------------------------------------------
766.35(b)(1)............................................       2070-0054
766.35(b)(2)............................................       2070-0054
766.35(b)(3)............................................       2070-0017
766.35(b)(4)(iii).......................................       2070-0054
766.35(c)(1)(i).........................................       2070-0054
766.35(c)(1)(ii)........................................       2070-0054
766.35(c)(1)(iii).......................................       2070-0017
766.35(d) Form..........................................       2070-0017
766.38..................................................       2070-0054
                                                                        
------------------------------------------------------------------------
     Procedures Governing Testing Consent Agreements and Test Rules     
                                                                        
------------------------------------------------------------------------
790.5...................................................       2070-0033
790.42..................................................       2070-0033
790.45..................................................       2070-0033
790.50..................................................       2070-0033
790.55..................................................       2070-0033
790.60..................................................       2070-0033
790.62..................................................       2070-0033
790.68..................................................       2070-0033
790.80..................................................       2070-0033
790.82..................................................       2070-0033
790.85..................................................       2070-0033
790.99..................................................       2070-0033
                                                                        
------------------------------------------------------------------------
                   Good Laboratory Practice Standards                   
                                                                        
------------------------------------------------------------------------
part 792................................................      2010-0019,

[[Page 729]]

                                                                        
                                                              2070-0004,
                                                              2070-0017,
                                                              2070-0033,
                                                             2070-0054 &
                                                               2070-0067
                                                                        
------------------------------------------------------------------------
                       Provisional Test Guidelines                      
                                                                        
------------------------------------------------------------------------
795.45..................................................       2070-0067
795.232.................................................       2070-0033
                                                                        
------------------------------------------------------------------------
    Identification of Specific Chemical Substance and Mixture Testing   
                              Requirements                              
                                                                        
------------------------------------------------------------------------
799.1053................................................       2070-0033
799.1250................................................       2070-0033
799.1560................................................       2070-0033
799.1575................................................       2070-0033
799.1645................................................       2070-0033
799.1700................................................       2070-0033
799.2155................................................       2070-0033
799.2325................................................       2070-0033
799.2475................................................       2070-0033
799.2500................................................       2070-0033
799.2700................................................       2070-0033
799.3300................................................       2070-0033
799.4360................................................       2070-0033
799.4440................................................       2070-0033
799.5000................................................       2070-0033
799.5025................................................       2070-0033
799.5050................................................       2070-0033
799.5055................................................       2070-0033
799.5075................................................       2070-0033
------------------------------------------------------------------------
\1\ The ICRs referenced in this section of the Table encompass the      
  applicable general provisions contained in 40 CFR part 60, subpart A, 
  which are not independent information collection requirements.        
\2\ The ICRs referenced in this section of the Table encompass the      
  applicable general provisions contained in 40 CFR part 61, subpart A, 
  which are not independent information collection requirements.        
\3\ The ICRs referenced in this section of the Table encompass the      
  applicable general provisions contained in 40 CFR part 63, subpart A, 
  which are not independent information collection requirements.        


[58 FR 27472, May 10, 1993]

    Editorial Note: For Federal Register citations affecting Sec. 9.1 
see the List of CFR Sections Affected in the Finding Aids section of 
this volume.

    Effective Date Notes: 1. At 61 FR 16309, Apr. 12, 1996, in Sec. 9.1 
table, the heading ``Public Information'' and its entry for part 2, 
subpart B were added, effective July 11, 1996.

    2. At 61 FR 33206, June 26, 1996, in Sec. 9.1 table, the entry for 
170.112 was removed and the entry for part 170 was added, effective Aug. 
26, 1996.

    3. At 61 FR 34228, July 1, 1996, in Sec. 9.1 table, entries 71.5, 
71.6(a),(c),(d),(g), 71.7, and 71.9(e)-(j) were added, effective July 
31, 1996.

[[Page 731]]



List of CFR Sections Affected



All changes in this volume of the Code of Federal Regulations which were 
made by documents published in the Federal Register since January 1, 
1986, are enumerated in the following list. Entries indicate the nature 
of the changes effected. Page numbers refer to Federal Register pages. 
The user should consult the entries for chapters and parts as well as 
sections for revisions.
Title 40 was established at 36 FR 12213, June 29, 1971. For the period 
before January 1, 1986, see the ``List of CFR Sections Affected, 1964-
1972 and 1973-1985,'' published in six separate volumes.

                                  1986

40 CFR
                                                                   51 FR
                                                                    Page
Chapter I
80.24  (a) introductory text, (1), and (2) and (b)(2) revised......33731

                                  1987

40 CFR
                                                                   52 FR
                                                                    Page
Chapter I
80  Appendix B heading revised; text amended.........................259

                                  1988

                       (No Regulations Published)

                                  1989

40 CFR
                                                                   54 FR
                                                                    Page
Chapter I
80  Authority citation revised.....................................11883
80.2  (l) revised; (t), (u), and (v) added.........................11883
80.27  Added.......................................................11883
    Table amended..................................................33219
    (a), (d)(1) and (3)(iii) corrected.............................27017
80.28  Added.......................................................11885
    (f) and (g)(4)(iii)(F) corrected...............................27017
80  Appendix D added...............................................11886
    Appendix E added...............................................11897
    Appendix F added...............................................11903
    Appendix D corrected...........................................27017
    Appendix E corrected...........................................27018

                                  1990

40 CFR
                                                                   55 FR
                                                                    Page
Chapter I
80.2  (h), (j), (l), (o), (r) and (t) revised; (w), (x), (y), (z), 
        (aa), and (bb) added.......................................34137
80.27  Table designated as (a)(1); heading and (a)(2) added; eff. 
        7-11-90....................................................23667
80.29  Added.......................................................34138
80.30  Added.......................................................34138
80.31  Added.......................................................34140
80  Appendix G added...............................................34140

                                  1991

40 CFR
                                                                   56 FR
                                                                    Page
Chapter I
73  Added..........................................................65601
80  Interpretative rule.............................................5352
    Program extension.......................................46119, 57986
    Authority citation revised.....................................64710
80.2  (d) removed..................................................13768
    (cc) and (dd) added............................................64710
80.22  (b) and (c) removed.........................................13768
80.27  (a) table amended...........................................20548
    (a) table amended..............................................37022

[[Page 732]]

    (a)(1) introductory text removed; (a) introductory text 
redesignated as (a)(1) introductory text and revised; (a)(2) 
introductory text and (d) revised..................................64710
80.28  (b)(1), (3), (c)(1), (4), (d)(1), (4), (e)(1), (2), (5), 
        (f)(1), (2) and (4) revised; (g)(8) added..................64711
80  Appendix B amended.............................................13768
    Appendix C removed.............................................13768

                                  1992

40 CFR
                                                                   57 FR
                                                                    Page
Chapter I
80  Program extension..............................................46316
80.2  (bb) removed.................................................19537
    (pp), (qq) and (rr) added......................................47771
80.27  (a)(2) table amended........................................20205
80.29  (c) removed; (d) and (e) redesignated as (c) and (d); (a), 
        new (c) and (d) revised....................................19537
80.31  Removed.....................................................19538
80.35 (Subpart C)  Added...........................................47771

                                  1993

40 CFR
                                                                   58 FR
                                                                    Page
Chapter I
72  Added...........................................................3650
72.2  Amended......................................................15647
    Corrected........................................33770, 40746, 40747
72.6  (a)(2) revised; (a)(3)(iii) through (vii), (b)(4), (5), (6), 
        (7) and (c) added..........................................15648
72.8  (c)(2)(ii) corrected.........................................40747
72.30  (b)(2)(iv) through (viii) added.............................15649
72.41  (e)(3)(iii) and (iv) corrected..............................40747
72.44  (f)(3)(i) and (ii) revised; (g)(1)(ii) amended..............15649
72.74  (b)(1)(iii) corrected.......................................40747
72.91  (a) introductory text and (3)(iii) corrected................40747
72.92  (c)(2)(v)(C) corrected......................................40747
72  Appendix D added...............................................15649
73  Notice of procedure............................................48318
73.1--73.3 (Subpart A)  Revised.....................................3687
73.1  (f) added....................................................15650
73.10--73.27 (Subpart B)  Added.....................................3687
73.10  (b), (c) and (d) added......................................15650
    Table 2 corrected; Table 4 correctly revised...................33770
    (a) Table 1 corrected..........................................40747
73.11  Added.......................................................15705
73.12  Added.......................................................15707
73.13  Added.......................................................15708
73.16  Added.......................................................15708
73.18  Added.......................................................15710
73.19  Added.......................................................15710
73.20  Added.......................................................15711
73.21  Added.......................................................15713
73.26  Added.......................................................15714
73.27  (a)(2), (3), (b)(2) through (5) and (c)(2) through (5) 
        added......................................................15714
73.30--73.38 (Subpart C)  Added.....................................3691
73.30  (a) corrected...............................................40747
73.31  (c)(1) introductory text corrected..........................40747
73.32  (a)(1) corrected............................................40747
73.50--73.53 (Subpart D)  Added.....................................3694
73.72  (c) revised..................................................3695
    Table 2 redesignated as Table 1................................15650
    Technical correction...........................................40747
73.80--73.86 (Subpart F)  Added.....................................3695
73.80  (b) corrected...............................................40747
73.81  (b)(4) corrected............................................40747
73.82  Heading corrected...........................................40747
73.90 (Subpart G)  Added...........................................15716
    (a) introductory text     corrected............................33770
75  Added...........................................................3701
    Authority citation revised.....................................15716
    Meeting........................................................67692
75.1  (b) corrected................................................34126
    (b) existing text redesignated as (b)(1) and (2); new (b)(2) 
corrected..........................................................40747
75.2  (b)(2) and (3) revised.......................................15716
75.4  (c) revised..................................................15717
75.5  (b) corrected................................................40747
75.6  (a)(12) corrected............................................34126
    (a)(4) corrected...............................................40747
75.7  Corrected....................................................40747
75.11  (c) introductory text corrected.............................40747
75.12  (c)(1) corrected............................................34126
75.14  (d) corrected...............................................34126
75.15  (a)(3)(iii) and (b) heading corrected.......................34126

[[Page 733]]

    (a) introductory text, (2) and (b)(1) corrected................40747
75.16  (b)(2)(i) corrected.........................................34126
    (e) corrected..................................................40747
75.17  (b) heading corrected.......................................34126
    (a)(2)(iii)(a) correctly redesignated as (a)(2)(iii)(A)........40747
    (a)(2)(iii)(B)  and (b)(2) corrected...........................40748
75.20  (a)(1) heading corrected....................................34126
    (b)(3), (c) introductory text, (9)(i) introductory text, (B) 
and (d) corrected; (c)(5)(iv) correctly added......................40748
75.31  (b)(2), (c)(2) and (3) corrected............................40748
75.32  (b) correctly revised.......................................40748
75.33  (c)(2)(ii)(B) corrected.....................................34126
75.34  (b)(1) corrected............................................40748
75.41  (b)(2)(i) and (c)(2)(ii)     corrected......................34126
    (a)(9)(i), (ii), (b)(1)(i), (2)(i), (iv)(A), (C), (v)(A), (B), 
(c)(1)(i), (ii) and (2)(i) corrected...............................40748
75.48  (a)(3)(vii) corrected.......................................34126
    (a)(3) corrected...............................................40748
75.50  (c)(3)(ii) corrected........................................34126
    (b) introductory text, (6), (c)(1)(iii), (iv), (vi), (2)(iii), 
(iv), (v), (vii), (3)(ii), (iii), (iv) Table 3, (d) introductory 
text, (3) through (6), (8), (9), (e)(1)(iii), (iv), (v), (vii), 
(viii), (2)(ii), (iv) and (v) corrected............................40749
75.51  (b)(1)(vii) correctly designated as (b)(1)(viii); 
        (a)(1)(iii) through (vi), (viii), (2)(i), (iii), (b) 
        introductory text, new (b)(1)(viii), (ix), (c)(1)(ii), 
        (vi), (d)(1)(ii) and (iv) corrected........................40749
75.52  (a)(5)(iv)(G) and (H) correctly redesignated as (a)(5)(v) 
        and (vi)...................................................40749
75.53  (a) introductory text, (c)(2) introductory text and (4)(vi) 
        corrected..................................................40749
    (c)(8)  and (9) corrected; (c)(10), (i), (ii), (A) and (B) 
correctly redesignated as (d), (1), (2), (i) and (ii)..............40750
75  Appendixes A, C, D, E and F corrected..........................34126
    Appendixes A, B and C     corrected............................40750
    Appendixes  C through H corrected..............................40751
    Appendix H corrected...........................................40752
77  Added...........................................................3757
78  Added...........................................................3760
79  Authority citation revised.....................................65554
79.8  Revised......................................................65554
80  Meeting........................................................13413
    Authority citation revised.....................................16019
    OMB number.....................................................34370
    Petition for exemption.........................................48968
80.5  Revised......................................................65554
80.22  (j) added...................................................16019
80.27  (b) and (c) revised; (e)   added............................14484
    (a)(2) table amended....................................26069, 46511
80.28  (g)(1)(i), (3)(ii), and (6)(ii) removed; (g)(1)(iii), 
        (3)(iii), (6)(iii), and (iv) redesignated as (g)(1)(i), 
        (3)(ii), (6)(ii), and (iii); (b)(1), (2), (3), (f)(3), 
        (4), new (g)(1)(i), (ii), (2) introductory text, (ii), (3) 
        introductory text, new (ii), (4)(i), new (6)(ii), (iii), 
        and (7) revised; (b)(4) and (f)(5) added...................14484
80  Appendix D amended.............................................14485
    Appendix E revised.............................................14488
    Appendix D corrected...........................................19152

                                  1994

40 CFR
                                                                   59 FR
                                                                    Page
Chapter I
72  Authority citation revised.....................................60229
72.41  (b)(1)(i), (c)(3) introductory text, (i)(B), (C), (ii), 
        (4)(ii), (d)(2) and (e)(1)(i) revised; (c)(3)(i)(D), (iii) 
        and (d)(3) added...........................................60230
    (c)(5) and (e)(3)(iv) revised; (c)(6), (7) and (e)(1)(iii) 
added..............................................................60238
72.43  (a) introductory text, (1) introductory text, (b)(1) 
        introductory text, (ii)(A), (3)(i), (c)(4)(i), (ii), (iv), 
        (d) and (f)(1)(ii) revised; (a)(2) added...................60230
72.91  (a)(3)(iii) introductory text, (iv), (4), (5), (6) and 
        (b)(2) revised; (a)(7) added...............................60231

[[Page 734]]

75.4  (a)(3) revised; (a)(4) added.................................42511
76  Added..........................................................13564
79  Authority  citation revised....................................33092
79.2  (d), (e) and (f) revised.....................................33092
79.3  Revised......................................................33092
79.4  (b)(1) revised...............................................33092
79.6  Revised......................................................33092
79.10  Revised.....................................................33092
79.11  Introductory text revised; (h) amended; (i) and (j) added 
                                                                   33092
79.12  Revised.....................................................33093
79.13  (a) revised.................................................33093
79.20  Revised.....................................................33093
79.21  Introductory text and (d) revised; (h) and (i) added........33093
79.22  Revised.....................................................33093
79.23  (a) revised; (b) removed; (c) redesignated as (b)...........33093
79.31  (b) revised.................................................33093
79.50--79.68 (Subpart F)  Added....................................33093
79.51  OMB number pending..........................................33094
79.52  OMB number pending..........................................33099
79.57  OMB number pending..........................................33111
79.58  OMB number pending..........................................33115
79.59  OMB number pending..........................................33117
79.60  OMB number pending..........................................33119
79.61  OMB number pending..........................................33124
79.62  OMB number pending..........................................33129
79.63  OMB number pending..........................................33132
79.64  OMB number pending..........................................33134
79.65  OMB number pending..........................................33135
79.66  OMB number pending..........................................33137
79.67  OMB number pending..........................................33139
79.68  OMB number pending..........................................33140
80  Petition  for exemption.................................13610, 26129
    Announcement...................................................44633
80.2  (ee) through (nn) added (OMB number pending)..................7812
    (ss) added.....................................................39289
    (j) and (o) revised; (oo), (tt) and (uu) added.................48489
    Regulation at 59 FR 39289 stayed...............................60715
80.22  Heading revised.............................................48490
80.27  (a)(2)  table amended................................15629, 15633
80.29  Revised; interim (OMB number pending).......................35858
80.30  (g)(7) added; interim.......................................35859
80.32  Added.......................................................48490
80.33  Added.......................................................48490
80.40--80.82 (Subpart D)  Added (OMB number pending)................7813
80.41  (h)(2)(iii), (j)(2) and (m)(1) introductory text revised....36958
80.42  (a) introductory text, (b)(1)(ii), (2)(ii) and (3)(ii) 
        amended; (b)(4) added; (c)(1) table revised................36958
80.45  (b)(3) Table 3, (c)(1)(iv)(A) Table 6, (C)(5), (11), (12), 
        (14), (D)(5), (11), (12), (14), (8)(ii), (d)(1)(iv)(A), 
        Table 7, (C)(5), (e)(3) introductory text and (f)(1) 
        revised; (c)(1)(iv)(B), (C)(9), (13), (D)(9), (13), 
        (3)(i), (ii), (4)(ii), (d)(1)(iv)(B), (C)(9), (e)(1)(ii), 
        (4)(iii), (5)(iv), (6)(iv), (9) and (10) amended; 
        (e)(3)(i) and (ii) removed.................................36959
80.46  (f)(1)(ii)(K) table revised.................................36961
80.48  (c)(1) introductory text and (g) revised; (c)(1)(v) and 
        (2)(iii) amended...........................................36962
80.49  (a)(5)(i) table and (b)(3)(iii) revised.....................36962
80.59  (a) amended.................................................36962
80.65  (d)(2)(iii), (v)(B), (vi), (3), (e)(2)(i) table, (ii)(A), 
        (f)(4) introductory text and (h) revised; (e)(1) amended 
                                                                   36962
    (d)((2)(vi) revised............................................39289
    Regulation at 59 FR 39289 stayed...............................60715
80.66  (g)(1) and (2)(ii) revised..................................36963
80.68  (c)(12) redesignated as (c)(13); (c)(8)(ii)(A), (9)(ii)(A), 
        (B), (10)(i), new (13)(v)(G), (H) and (L) revised; new 
        (c)(12) added; new (c)(13) introductory text amended.......36963
80.69  (a)(7)(ii) introductory text and (b)(3) revised.............36964
80.70  (d)(3)(viii), (ix), (j)(4)(i), (ii), (10)(iv), (11)(i) and 
        (14)(xvii) revised; (d)(3)(x) and (xi) added; (j)(15) 
        removed....................................................36964
80.75  (b), (f)(2)(ii)(A)(1) and (j) revised.......................36964
80.76  (c)(2), (3) introductory text, (i) and (ii) revised.........36965
80.77  (g)(2)(iii), (iv)(A), (B) and (h) introductory text 
        revised; (g)(3) added......................................36965

[[Page 735]]

80.78  (a)(1)(v)(B) and (C) revised................................36965
80.81  (a)(2)(iii), (b)(4) and (h) revised.........................36965
    (c)(2), (5), (6) and (10) revised..............................39289
    Regulation at 59 FR 39289 stayed...............................60715
80.83  Added (OMB number pending in part)..........................39290
    Regulation at 59 FR 39290 stayed...............................60715
80.90--80.106 (Subpart E)  Added (OMB number pending)...............7860
80.90  (b)(1) amended; (e)(2) revised..............................36965
80.91  (c)(5)(iv), (e)(5)(vi)(A), (B) and (7)(i)(D) added; 
        (d)(1)(i)(A) introductory text, (B), (e)(2)(iv), (v)(A), 
        (4)(i)(A), (B), (ii)(A), (B) and (5)(vi) amended; 
        (d)(1)(i)(A)(1), (e)(5)(vii) introductory text, (viii), 
        (7)(i)(A), (C) and (f)(2)(ii) revised......................36966
80.93  (a)(3)(ii) amended; (a)(3)(iv) added; (c)(9) revised........36968
80.101  (e)(3), (f)(4)(i), (ii), (g)(1) and (i)(1) introductory 
        text revised...............................................36968
80.102  (b)(1), (d)(1)(i) and (2)(i) amended; (d)(3)(iv), 
        (e)(2)(i) and (f)(2)(i) revised; (d)(3)(v) added...........36969
80.104  (a)(2)(ix) revised.........................................36969
80.105  (a)(2) revised.............................................36969
80.125  (a) revised................................................36969
80.125--80.130 (Subpart F)  Added (OMB number pending)..............7875
80.128  (e)(2), (5) and (g)(3)(iii) revised........................36969
    (a) and (e)(2) revised; (e)(4) and (5) amended; (e)(6) added 
                                                                   39292
    Regulation at 59 FR 39292 stayed...............................60715
80.129  (e) revised................................................36969
    (a), (d)(3)(iii) and (iv) revised; (d)(3)(v) added.............39292
    Regulation at 59 FR 39292 stayed...............................60715
80.140--80.160 (Subpart G)  Added..................................54706
80.141  OMB number pending.........................................54707
80.157  OMB number pending.........................................54713
80.158  OMB number pending.........................................54714
80.160  OMB number pending.........................................54715

                                  1995

40 CFR
                                                                   60 FR
                                                                    Page
Chapter I
72  Authority citation revised.....................................17111
72.2  Amended...............................................17111, 18468
    Amended; interim; eff. 7-17-95.................................26514
72.4  (a)(1) and (2) revised.......................................17113
72.9  (g)(6) and (7) revised.......................................17113
72.13  (a)(8) and (9) redesignated as (a)(9) and (10); new (a)(8) 
        added; new (a)(9) and new (10) revised; interim; eff. 7-
        17-95......................................................26516
72.21  (e) revised.................................................17113
72.30  (c) revised.................................................17113
72.33  (a), (b)(2), (3), (c)(2), (4), (e) and (f) revised..........18468
72.40  (b)(1) introductory text revised............................17113
72.43  (e) revised.................................................18470
72.72  (b)(1) introductory text, (i)(A), (B), (ii)(A), (C), (v), 
        (xiv) and (5)(vi) revised; (b)(5)(i) amended...............17113
72.81  (b)(3) and (4) amended; (b)(5) added........................17114
72.83  (a)(6) and (11) revised; (a)(12) added......................17114
72.91  (a) introductory text revised...............................18470
72.92  (a), (b)(2)(ii)(F), (G), (H), (c)(2)(v) and Table 1 
        revised; (b)(1) removed; (b)(2)(ii)(I) and (J) added.......18470
73  Authority citation revised.....................................17114
73.34  (c)(2) and (6) revised......................................17114
73.35  (b)(1) and (2) revised......................................17114
73.52  (a)(3) revised..............................................17114
74  Added..........................................................17115
75  Authority citation revised..............................26516, 26566
75.2  (b)(4) removed; interim; eff. 7-17-95........................26516
75.4  (a) introductory text revised; (a)(5) added..................17131
    (a) introductory text amended; (e) redesignated as (h); (a)(1) 
through (4), (b), (c), (d) and new (h) revised; new (e), (f) and 
(g) added; interim; eff. 7-17-95...................................26516
75.5  (e) revised; (f) added; interim; eff. 7-17-95................26517
75.6  (a), (b)(1) through (6) revised; (b)(7), (8) and (9); (c), 
        (d) and (e) added; interim; eff. 7-17-95...................26517

[[Page 736]]

75.8  Added; interim; eff. 7-17-95.................................26519
75.10  (a)(1), (2), (3), (d), (e) and (f) revised; interim; eff. 
        7-17-95....................................................26519
75.11  (c) and (d) revised; (e) redesignated as (f); interim; eff. 
        7-17-95....................................................26520
    (a) amended; (e) and (g) added; interim; eff. 7-17-95 through 
12-31-96...........................................................26566
75.12  (c) revised; interim; eff. 7-17-95..........................26520
75.13  (a) and (c) revised; interim; eff. 7-17-95..................26521
75.14  (c) revised; interim; eff. 7-17-95..........................26521
75.15  (a) introductory text, (1) and (2) revised; (b)(1) amended; 
        interim; eff. 7-17-95......................................26521
75.16  (a)(2)(ii)(A) and (b)(2)(ii)(A) revised.....................17131
    Revised; interim; eff. 7-17-95.................................26522
75.17  (a)(2)(i)(C) added; (c) removed; (d) redesignated as (c); 
        (a)(2)(i)(B) and new (c) revised; interim; eff. 7-17-95....26523
75.18  (b) revised.................................................26524
    (b)(2) revised; (b)(3) removed.................................40296
75.20  (a)(3) amended..............................................17131
    (a) introductory text, (1), (2), (3), (4) introductory text, 
(iii), (iv), (5), (c)(1)(v), (2)(ii), (iii), (4), (5) introductory 
text, (iv), (6)(i), (8), (d), (f) introductory text, (1), (3) and 
(g) revised; (c) introductory text and (f)(2) amended; (c)(9) 
removed; interim; eff. 7-17-95.....................................26524
    (f) revised....................................................40296
75.21  (d) and (e) added; interim; eff. 7-17-95....................26527
    (a) amended; (f) added; interim; eff. 7-17-95 through 12-31-96
                                                                   26566
75.22  (a) introductory text, (5) and (6) revised; (b) and (c) 
        added; interim; eff. 7-17-95...............................26528
75.23  Revised; interim; eff. 7-17-95..............................26528
75.24  (d) and (e) revised; interim; eff. 7-17-95..................26528
75.30  Revised; interim; eff. 7-17-95..............................26528
    (d) and (e) added; interim; eff. 7-17-95 through 12-31-96......26566
75.31  (a), (b) and (c)(3) revised; interim; eff. 7-17-95..........26529
75.32  (a) introductory text and (b) revised; (a)(1) and (2) 
        amended; interim; eff. 7-17-95.............................26529
    (a)(3) amended; (a)(4) added; interim; eff. 7-17-95 through 
12-31-96...........................................................26567
75.33  (a) amended; (c)(5) added; interim; eff. 7-17-95............26529
75.34  Revised; interim; eff. 7-17-95..............................26567
75.35  Added; interim; eff. 7-17-95................................26529
75.36  Added; interim; eff. 7-17-95................................26530
75.41  (a)(1) amended; (b)(1)(i), (2)(iv)(A), (C), (c)(1)(i), (ii) 
        and (2)(ii) revised; interim; eff. 7-17-95.................26530
    (a)(1), (b)(1)(i), (2)(iv)(A), (C), (c)(1)(i), (ii) and 
(2)(ii) revised....................................................40296
75.47  Revised; interim; eff. 7-17-95..............................26531
    Revised........................................................40297
75.48  (a) introductory text and (1) revised; (b) and (c) added; 
        interim; eff. 7-17-95......................................26531
    Revised........................................................40297
75.50  (a) revised; interim; eff. 7-17-95 through 12-31-95.........26532
75.51  (e) added; interim; eff. 7-17-95 through 12-31-95...........26532
75.52  (b) added; interim; eff. 7-17-95 through 12-31-95...........26532
75.53  (a), (b), (c) introductory text, (1), (2)(ii), (4) 
        introductory text, (ii), (vi), (5)(ii), (6) through (9), 
        (d)(1) and (2) revised; (c)(10) and (d)(3) added; interim; 
        eff. 7-17-95...............................................26532
    (d) introductory text revised; interim; eff. 7-17-95...........26568
75.54  Added; interim; eff. 7-17-95................................26533
75.55  Added; interim; eff. 7-17-95................................26535
    (b) and (e) added; interim; eff. in part 7-17-95 and in part 
7-17-95 through 12-31-96...........................................26568
75.56  Added; interim; eff. 7-17-95................................26536

[[Page 737]]

    (a)(6) added; interim; eff. 7-17-95 through 12-31-96...........26569
75.60  (b)(1) and (2) revised; (c) added; interim; eff. 7-17-95....26538
75.61  Revised; interim; eff. 7-17-95..............................26538
75.62  (a) revised; (c) added; interim; eff. 7-17-95...............26539
75.63  (a) and (b)(1) revised......................................17131
    Revised; interim; eff. 7-17-95.................................26539
75.64  (a) introductory text and (e) introductory text amended; 
        (a)(5), (b) and (d) revised; (e)(1) and (2) removed; 
        interim; eff. 7-17-95......................................26540
    (a)(1) and (c) revised; interim; eff. 7-17-95..................26569
75.65  Revised; interim; eff. 7-17-95..............................26540
75.66  (a), (b), (c), (d), (e) and (f) redesignated as (b), (c), 
        (d), (e), (f) and (i); new (a), (g) and (h) added; new 
        (b), new (c) and new (i) revised; interim; eff. 7-17-95....26540
    (e) and (f) revised; interim; eff. 7-17-95.....................26569
75.67  Revised.....................................................17131
    (a) revised; interim; eff. 7-17-95.............................26541
75