[Federal Register Volume 60, Number 95 (Wednesday, May 17, 1995)]
[Rules and Regulations]
[Pages 26510-26558]
From the Federal Register Online via the Government Publishing Office [www.gpo.gov]
[FR Doc No: 95-11498]




[[Page 26509]]

_______________________________________________________________________

Part III





Environmental Protection Agency





_______________________________________________________________________



40 CFR Part 9, et al.



Acid Rain Program; Final, Proposed and Interim Rules

  Federal Register / Vol. 60, No. 95 / Wednesday, May 17, 1995 / Rules 
and Regulations   
[[Page 26510]] 

ENVIRONMENTAL PROTECTION AGENCY

40 CFR Parts 9, 72, and 75

[FRL-5203-3]


Acid Rain Program: Permits Regulation General Provisions and 
Continuous Emission Monitoring Rule Technical Revisions

AGENCY: Environmental Protection Agency (EPA).

ACTION: Direct final rule.

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SUMMARY: Title IV of the Clean Air Act (the Act), as amended by the 
Clean Air Act Amendments of 1990, authorizes the Environmental 
Protection Agency (EPA or Agency) to establish the Acid Rain Program. 
The program sets emissions limitations to reduce acidic deposition and 
its serious, adverse effects on natural resources, ecosystems, 
materials, visibility, and public health. On January 11, 1993, the 
Agency promulgated final rules under title IV. Several parties filed 
petitions for review of the rules. On April 17, 1995, the EPA and the 
parties signed a settlement agreement addressing continuous emission 
monitoring (CEM) issues.
    This direct final rule would amend the Continuous Emission 
Monitoring (CEM) provisions and the General Provisions of the Acid Rain 
Program for the purpose of making the implementation of the program 
simpler, streamlined, and more efficient for both the EPA and industry. 
The rule amendment is being issued as a direct final rule because the 
corrections are technical in nature and address various implementation 
issues without major changes in policy. Furthermore, the rule 
amendments are consistent with the April 17, 1995 settlement agreement. 
Therefore, EPA believes these amendments are noncontroversial and has 
provided for the amendments to be effective 60 days after publication 
in the Federal Register.

DATES: Effective Dates. This final rule will be effective July 17, 
1995. However, if significant adverse comments on portions of the rule 
are received by June 16, 1995, then the effective date of those 
provisions will be delayed, EPA will withdraw those portions of the 
rule, and timely notice will be published in the Federal Register. 
Sections 75.50, 75.51 and 75.52; redesignated section 2.4.3.1 of 
appendix D of part 75; and sections 4.3.1, 4.3.2, 4.3.3, 4.4.3, 5.3. 
and 5.4 of appendix F of part 75 are effective through December 31, 
1995. The incorporation by reference of certain publications listed in 
the regulation is approved by the Director of the Federal Register as 
of July 17, 1995.
    Compliance Dates. Information on compliance dates is in the 
Supplementary Information section of this preamble and in appendix J of 
part 75.

ADDRESSES: Any written comments must be identified with Docket No. A-
94-16, must be identified as comments on the direct final rule and 
companion proposal, and must be submitted in duplicate to: EPA Air 
Docket (6102), Environmental Protection Agency, 401 M Street SW, 
Washington, DC 20460. The docket is available for public inspection and 
copying between 8:30 a.m. and 3:30 p.m., Monday through Friday, at the 
address given above. A reasonable fee may be charged for copying. A 
detailed rationale for the revisions is set forth in the technical 
support document for the direct final rule, which can be obtained by 
writing to the Air Docket at the address given above.

FOR FURTHER INFORMATION CONTACT: Margaret Sheppard, Acid Rain Division 
(6204J), U.S. Environmental Protection Agency, 401 M Street SW, 
Washington, DC 20460, telephone number (202) 233-9180.

SUPPLEMENTARY INFORMATION: The EPA is revising the CEM provisions as a 
direct final rule without prior proposal because the Agency views these 
revisions as noncontroversial and anticipates no significant adverse 
comments. The EPA is also publishing a companion proposed rule to this 
direct final rule in this issue of the Federal Register in order to 
take comment on provisions of the direct final rule. If EPA does 
receive significant adverse comments, EPA will publish a document in 
the Federal Register withdrawing portions of the direct final rule. In 
addition, EPA is publishing an interim final rule in today's Federal 
Register to address other monitoring issues that may be controversial. 
The EPA will not institute a second comment period on the proposed 
rule, on the interim final rule, or on any subsequent final rule. Any 
parties interested in commenting on these revisions to parts 72 and 75 
should do so at this time.
    Significant adverse comment will be addressed in a subsequent final 
rulemaking document. If EPA withdraws portions of the direct final 
rule, EPA will accept comments for 15 days after publication of the 
notice of withdrawal in order to receive additional comments on 
withdrawn portions of the rule. If the effective date is delayed, 
timely notice will be published in the Federal Register.
    The owner or operator shall comply with the following requirements 
from July 17, 1995 through December 31, 1995: for the recordkeeping 
requirements of subpart F of part 75, by following either Secs. 75.50, 
75.51 and 75.52 or Secs. 75.54, 75.55 and 75.56; for 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 section 5.3 and 5.4 of appendix F of part 75; 
and for the missing data substitution requirements for fuel flowmeters 
by following either section 2.4.3.1 or sections 2.4.3.2 and 2.4.3.3 of 
appendix D of part 75.
    On or after January 1, 1996, the owner or operator shall comply 
with the following requirements: for the recordkeeping requirements of 
subpart F of part 75, by meeting the requirements of Secs. 75.54, 
75.55, and 75.56; and for the missing data substitution requirements 
for CO2 concentration, heat 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 part 75.
    The EPA has been engaged in settlement discussions with several 
parties who challenged certain provisions of the Acid Rain CEM rules 
promulgated on January 11, 1993. [See Environmental Defense Fund v. 
Browner, No. 93-1203 and consolidated cases, ``Complex'' (D.C. Cir. 
filed March 12, 1993).] Although the parties have been able to reach 
agreement on a number of issues, which are addressed in this direct 
final rulemaking, some additional issues remain outstanding. The 
outstanding issues, unlike the noncontroversial and routine technical 
corrections and other amendments addressed by this direct final rule, 
may not be considered noncontroversial and therefore are being 
addressed separately in an interim final rule, published elsewhere in 
this Federal Register.
I. Acid Rain Program Background

A. Rulemaking Background

    On January 11, 1993, EPA promulgated the ``core'' regulations that 
implemented the major provisions of title IV of the Clean Air Act (CAA 
or the Act), as amended November 15, 1990, including the General 
Provisions of the Permits Regulation (40 CFR part 72) and the CEM 
regulation at 40 CFR part 75 authorized under Sections 412 and 821 of 
the Act. The CEM rule specifies how each affected utility unit must 
install a system to continuously monitor the [[Page 26511]] emissions 
and to collect, record, and report emissions data to ensure that the 
mandated reductions in sulfur dioxide (SO2) and nitrogen dioxide 
(NOX) emissions are achieved, that opacity and CO2 emissions 
are measured, and that SO2 emissions are accurately measured so 
that the allowance system functions in an orderly manner. Technical 
corrections were published on June 23, 1993 and July 30, 1993. An 
amendment to the certification deadline for NOX and CO2 
monitoring for oil-fired units and gas-fired units was published on 
August 18, 1994.
    Since the CEM rule was promulgated, the operation of Phase I 
utility units have essentially completed the first stage of 
implementation of the rule, having submitted monitoring plans, 
conducted certification testing, submitted certification applications, 
and submitted their first quarterly reports. In addition, many Phase II 
utility units also have begun implementation. During early 
implementation, many technical issues have been raised, including many 
minor issues which could be addressed by technical corrections. The 
preamble discussion that follows outlines the changes that are 
contained in today's direct final rulemaking that will make these 
technical corrections.

B. Implementation Background

    The EPA held three Acid Rain Implementation Conferences (January 5-
6, 1993; January 25-26, 1993; and March 16-17, 1993). In these public 
meetings, EPA staff presented an overview of the Acid Rain Program and 
Acid Rain core rules. Some of the changes in today's revised rule 
resulted from issues raised by the public at these conferences.
    In order to respond to a multitude of questions raised by industry, 
EPA instituted a new ``Acid Rain monitoring'' section on the Agency's 
computerized Technology Transfer Network Bulletin Board System 
(TTNBBS). This bulletin board can be accessed by computer modem at 
(919) 541-5742. The EPA's Acid Rain Division periodically updates this 
section of the bulletin board with notices of meetings, interpretations 
of part 75, policy determinations, and other information relevant to 
State environmental regulators and the regulated community. In 
particular, EPA has published three installments of commonly asked 
questions and their answers in the ``Acid Rain CEM (Part 75) Policy 
Manual'' (Docket Item I-D-54). Many of these policy determinations and 
clarifications of part 75 are incorporated into today's revised rule.
    Some standard forms have been revised to be consistent with the 
changes in this rulemaking. Packages of revised standard forms, with 
instructions, will contain revised monitoring plan forms, certification 
forms, and electronic data reporting format, and will be available from 
EPA in electronic form from the TTNBBS by using computer modem at (919) 
541-5742 or on paper by calling the Acid Rain Hotline at (202) 233-
9620.

II. Changes to Parts 72 and 75--General Provisions of the Permits 
Regulation and Continuous Emission Monitoring

    Several of the definitions in Sec. 72.2 related to monitoring have 
been revised. As explained below, EPA edited these definitions and 
added a few definitions to explain or clarify new or existing terms in 
part 75.
    The changes to part 75 are clarifications intended to ease 
implementation, and do not constitute major policy changes. The most 
significant changes in today's revised part 75 concern deadlines for 
completing certification testing, the procedures for exceptions to the 
use of CEMS found in appendices D and E, and the provisions for 
determining the span of NOX pollutant concentration monitors. The 
EPA has added to the list of certification testing deadlines to apply 
to more types of units that might require certification after the 
statutory deadline for installation of CEMS. In addition, the Agency 
rewrote major portions of appendices D and E to make them easier to 
understand and to implement. Changes to appendix E also substantially 
reduce the time and difficulty of testing required to obtain NOX 
emission rate data. Finally, the procedures for determining NOX 
span have been revised so that utilities with units having low NOX 
emission rates may select a single span representative of the situation 
at their plant, rather than being required to use both a high scale and 
a low scale measurement range. A list of compliance dates for the 
revised recordkeeping requirements and missing data substitution 
procedures are included in the new appendix J.
    The rationale and effect of the revisions to parts 72 and 75 are 
discussed in detail in a technical support document. This document may 
be obtained from the EPA Air Docket as Docket Item II-F-2, ``Technical 
Support Document (Attachment A),'' in Docket No. A-94-16. In addition, 
EPA is publishing this document under the CAA Title IV portion of EPA's 
TTNBBS. This bulletin board can be accessed by computer modem at (919) 
541-5742. The topics in the rule revisions discussed in the Technical 
Support Document are as follows:

I. Glossary of Terms and Abbreviations
II. Acid Rain Program Background
    A. Rulemaking Background
    B. Implementation Background
III. Changes to Part 72--Permits Regulation General Provisions
    A. Fuel-related Definitions
    B. Operating Hour Definitions
    C. Calibration Gas Definitions
    D. Bypass Operating Quarter, Unit Operating Quarter
    E. Ozone Nonattainment Area, Ozone Transport Region
    F. Other Definitions
IV. Changes to Part 75--Continuous Emission Monitoring
    A. General Revisions
    B. Changes to Subpart A, General
    1. Certification Deadlines
    a. Shutdown Units
    b. New Stacks or Flue Gas Desulfurization Systems
    c. Backup Fuel and Emergency Fuel
    d. Newly Affected Units
    e. EIA Forms
    f. Emissions Accounting Prior to Certification
    2. Incorporation by Reference
    3. Relative Accuracy and Availability Performance Analysis
    C. Changes to Subpart B, Monitoring Provisions
    1. Calculation of Average Emissions and Opacity Data
    2. Peaking Unit Definition and Applicability of Appendix E
    3. SO2 Monitoring During Combustion of Gas for Units With 
SO2 CEMS
    4. Monitoring Common Stacks, Bypass Stacks, and Multiple Stacks
    a. Common Stack Monitoring
    b. Multiple Stacks--NOXMonitoring
    c. Bypass Stack Monitoring
    5. Determining Emissions From Qualifying Phase I Technologies
    D. Changes to Subpart C, Operation and Maintenance Requirements
    1. Certification Procedures for CEMS
    a. Initial Certification and Recertification
    b. Loss of Certification Procedures
    c. Submission and Retesting Deadlines
    d. Audit Decertification
    e. Monitoring Systems To Be Certified
    f. Use of Backup or Portable Monitoring Systems
    2. Certification Procedures for Alternative Monitoring Systems
    3. Certification Procedures for Excepted Monitoring Systems
    E. Changes to Subpart D, Missing Data Procedures
    1. Missing Data Procedures for Peaking Units
    2. Addition to NOX and Flow Missing Data Procedures
    3. Changes to CO2 and Heat Input Procedures
    4. Missing Data Procedures for Units With Add-on Emission 
Controls
    5. SO2 Concentration Missing Data During Gas Combustion
    F. Changes to Subpart E, Alternative Monitoring Systems 
[[Page 26512]] 
    G. Changes to Subpart F, Recordkeeping Requirements
    1. Additional Sections 75.54, 75.55 and 75.56
    2. Changes to Emission Data Records
    3. Certification Records
    4. Monitoring Plans
    5. Records File
    H. Changes to Subpart G, Reporting Requirements
    1. Notifications to EPA and State Agencies
    2. Information Not Reported to EPA
    3. Effective Date of Revised Reporting Requirements
    4. Petitions to the Administrator
    5. Confidentiality of Data
    6. Reporting Addresses
    I. Changes to Appendix A, Specifications and Testing Procedures
    1. Changes to Span Requirements
    a. Span for SO2 Pollutant Concentration Monitors
    b. Span for NOX Pollutant Concentration Monitors
    c. Changes to Span
    2. Clarification of Certification Test Procedures
    a. Calibration Error Test
    b. Cycle Time Test
    c. Relative Accuracy Test for NOX
    d. RATAs for CO2 and O2
    3. Calibration Gases
    4. Changes to Appendix B, Quality Assurance and Quality Control 
Procedures
    5. Periodic RATAs for Monitors on Peaking Units and Bypass 
Stacks
    6. Incentive Standard and Out-of-Control for CO2 Monitors
    7. Incentive Standard for NOX Low Emitters
    8. Quality Assurance of Data Following Daily Calibration Error 
Test
    9. Recalibration
    10. Calibration Gas for Linearity Checks
    J. Changes to Appendix C, Missing Data Statistical Estimation 
Procedures
    1. Changes to Parametric Monitoring Procedure for Missing Data
    2. Clarifications of Load-Based Procedure for Missing Flow Rate 
and NOX Emission Rate Data
    K. Changes to Appendix D, Optional SO2 Emission Protocol 
for Gas-fired and Oil-fired Units
    1. Gaseous Fuels Other Than Natural Gas
    2. SO2 Emissions From Natural Gas
    3. Fuel Flowmeter Installation Requirements
    4. Gas Flowmeter Accuracy
    5. Fuel Flowmeter Calibration and Quality Assurance Requirements
    6. Fuel Sampling for Diesel Fuel
    7. Turnaround Time for Fuel Analysis
    8. Missing Data Procedures
    9. Heat Input
    L. Changes to Appendix E, Optional NOX Emission Estimation 
Protocol for Gas-fired Peaking Units and Oil-fired Peaking Units
    1. Testing by Fuel
    2. Heat Input as Unit Operating Load
    3. Number of Load Levels
    4. Tests by Excess O2 Level
    5. Efficiency Testing
    6. Stack Testing Procedures
    7. Quality Assurance and Quality Control Parameters
    8. Emergency Fuel Provisions
    M. Changes to Appendix F, Conversion Procedures
    1. Heat Input
    2. Diluent Cap Values
    3. NOX and SO2 Conversion Procedures
    N. Changes to Appendix G, Determination of CO2 Emissions

III. Impact Analyses

A. Paperwork Reduction Act

    The information collection requirements in this rule have been 
approved by the Office of Management and Budget (OMB) under the 
Paperwork Reduction Act, 44 U.S.C. 3501 et seq. and have been assigned 
control number 2060-0258.
    This collection of information has an estimated reporting burden 
averaging 40 hours per response and an estimated annual recordkeeping 
burden averaging 160 hours per respondent. These estimates include time 
for reviewing instructions, searching existing data sources, gathering 
and maintaining the data needed, and completing and reviewing the 
collection of information.
    The control numbers assigned to collections of information in 
certain EPA regulations by the OMB have been consolidated under 40 CFR 
part 9. The EPA finds there is ``good cause'' under Sections 553(b)(B) 
and 553(d)(3) of the Administrative Procedure Act to amend the 
applicable table in 40 CFR part 9 to display the OMB control number for 
this rule without prior notice and comment. Due to the technical nature 
of the table, further notice and comment would be unnecessary. For 
additional information, see 58 FR 18014, April 7, 1993, and 58 FR 
27472, May 10, 1993.
    Send comments regarding the burden estimate or any other aspect of 
this collection of information, including suggestions for reducing this 
burden to Chief, Information Policy Branch; EPA; 401 M St., SW (Mail 
Code 2136); Washington, DC 20460; and to the Office of Information and 
Regulatory Affairs, Office of Management and Budget, Washington, DC 
20503, marked ``Attention: Desk Officer for EPA.''

B. Executive Order Requirements

1. Executive Order 12866
    Under Executive Order 12866 (58 FR 51735, October 4, 1993), the 
Agency must determine whether the regulatory action is ``significant'' 
and therefore subject to OMB review and the requirements of the 
Executive Order. The Order defines ``significant regulatory action'' as 
one that is likely to result in a rule that may:
    (1) Have an annual effect on the economy of $100 million or more or 
adversely affect in a material way the economy, a sector of the 
economy, productivity, competition, jobs, the environment, public 
health or safety, or State, local, or tribal governments or 
communities;
    (2) Create a serious inconsistency or otherwise interfere with an 
action taken or planned by another agency;
    (3) Materially alter the budgetary impact of entitlements, grants, 
user fees, or loan programs or the rights and obligations of recipients 
thereof; or
    (4) Raise novel legal or policy issues arising out of legal 
mandates, the President's priorities, or the principles set forth in 
the Executive Order.
    Pursuant to the terms of Executive Order 12866, OMB has notified 
EPA that it considers this a ``significant regulatory action'' within 
the meaning of the Executive Order. The EPA has submitted this action 
to OMB for review. Changes made in response to OMB suggestions or 
recommendations will be documented in the public record.
    The revisions to part 75 slightly decrease the overall cost of 
compliance for the regulated community. Therefore, the Agency did not 
prepare a Regulatory Impact Analysis (RIA). Revisions to appendix D of 
part 75, ``Optional SO2 Emissions Data Protocol for Gas-Fired and 
Oil-Fired Units,'' reduce the frequency of sampling and analysis of 
diesel fuel, reducing the cost of SO2 monitoring for units using 
No. 2 fuel oil as a backup fuel. Revisions to appendix E of part 75, 
``Optional NOX Emission Estimation Protocol for Gas-Fired Peaking 
Units and Oil-Fired Peaking Units,'' reduce the amount of testing for 
gas-fired peaking units and oil-fired peaking units using this optional 
procedure. A small gas-fired or oil-fired peaking unit using appendix D 
or appendix E would have monitoring costs reduced by 10 to 40 percent 
from the cost of the promulgated rule of January 11, 1993.
2. Executive Order 12875
    Executive Order 12875 generally prohibits Agencies from issuing 
regulations not required by statute that impose mandates on State, 
local, and tribal governments unless federal funding is provided for 
the direct costs of compliance or the Agency, after consultation with 
the affected entities, justifies the need for an unfunded mandate. 
Clean Air Act Section 412(a) required EPA to issue regulations 
specifying requirements for CEMS and alternative monitoring systems, as 
well as for recordkeeping and reporting of [[Page 26513]] information 
from such systems. This direct final rule revises the regulation 
required under Section 412(a) in order to address various issues that 
have come to light during early implementation and is therefore a 
statutorily-required regulation. In addition, as discussed above, the 
revisions to the regulation do not impose additional costs, but rather 
slightly decrease the overall cost of compliance for the regulated 
community. Therefore, the revisions meet the requirements of Executive 
Order 12875.

C. Regulatory Flexibility Act

    Pursuant to Section 605(b) of the Regulatory Flexibility Act, 5 
U.S.C. 605(b), the Administrator certifies on April 28, 1995 that this 
rule revision will not have a significant economic impact on a 
substantial number of small entities.
    The EPA performed an analysis of the effects upon small utilities 
of the Acid Rain core rules (58 FR 3649, January 11, 1993), including 
permitting, allowances, and continuous emission monitoring. The earlier 
document concluded that significant costs would occur to small 
utilities as a result of statutory requirements. For example, based 
upon a worst case for model utilities, total regulatory costs could 
represent as much as 6 to 7 percent of the average value of electricity 
produced in the year 2000. About one-third of the 105 small utilities 
currently affected could face impacts of up to this magnitude.
    Today's revisions to part 75 have a beneficial impact on small 
entities by reducing the burden of complying with the Acid Rain Program 
monitoring requirements for approximately 800 small utility units. 
Revisions to appendix D of part 75 reduce the frequency of sampling and 
analysis of diesel fuel, reducing the cost of SO2 monitoring for 
units using diesel fuel (No. 2 fuel oil) as a backup fuel. The EPA 
estimates that this will reduce the cost of complying with monitoring 
requirements by 15 percent per year for SO2 monitoring for units 
using diesel fuel. Revisions to appendix E of part 75 reduce the amount 
of testing for gas-fired peaking units and oil-fired peaking units. The 
EPA estimates that these changes will reduce the cost of appendix E 
testing by one-third for boilers and by one-tenth for stationary gas 
turbines and diesel reciprocating engines. A small gas-fired or oil-
fired peaking unit monitoring using appendix D or appendix E would have 
monitoring costs reduced by 10 to 40 percent from the cost of the 
promulgated rule of January 11, 1993.

D. Unfunded Mandates Act

    Section 202 of the Unfunded Mandates Reform Act of 1995 (``Unfunded 
Mandates Act'') (signed into law on March 22, 1995) requires that the 
Agency prepare a budgetary impact statement before promulgating a rule 
that includes a Federal mandate that may result in expenditure by 
State, local, and tribal governments, in aggregate, or by the private 
sector, of $100 million or more in any one year. Section 203 requires 
the Agency to establish a plan for obtaining input from and informing, 
educating, and advising any small governments that may be significantly 
or uniquely affected by the rule.
    Under section 205 of the Unfunded Mandates Act, the Agency must 
identify and consider a reasonable number of regulatory alternatives 
before promulgating a rule for which a budgetary impact statement must 
be prepared. The Agency must select from those alternatives the least 
costly, most cost-effective, or least burdensome alternative that 
achieves the objectives of the rule, unless the Agency explains why 
this alternative is not selected or why the selection of this 
alternative is inconsistent with law.
    Because this direct final rule and its associated proposed and 
interim final rules are estimated to have an impact of less than $100 
million in any one year, the Agency has not prepared a budgetary impact 
statement or specifically addressed the selection of the least costly, 
most cost-effective, or least burdensome alternative. Because small 
governments will not be significantly or uniquely affected by the 
revisions to parts 72 and 75, the Agency is not required to develop a 
plan with regard to small governments. However, as discussed in this 
preamble, the rule revisions have the net effect of reducing the burden 
of part 75 of the Acid Rain regulations on regulated entities, 
including both investor-owned and State and municipally-owned 
utilities.

List of Subjects in 40 CFR Parts 9, 72, and 75

    Environmental protection, Air pollution control, Carbon dioxide, 
Continuous emission monitors, Electric utilities, Incorporation by 
reference, Nitrogen oxides, Reporting and recordkeeping requirements, 
Sulfur dioxide.

    Dated: April 28, 1995.
Carol M. Browner,
Administrator.

    For the reasons set out in the preamble, parts 9, 72, and 75 of 
title 40, chapter I, of the Code of Federal Regulations are amended as 
follows:

PART 9--OMB APPROVALS UNDER THE PAPERWORK REDUCTION ACT

    1. The authority citation for part 9 continues to read as follows:

    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, 1321, 1326, 1330, 1344, 1345 
(d) and (e), 1361; E.O. 11735, 58 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, 7401-7767q, 7542, 9601-9657, 
11023, 11048.

    2. The table in Sec. 9.1 under the heading ``Continuous Emission 
Monitoring'' by removing the entries for ``Secs. 75.50 through 75.53'' 
and by adding entries for ``Secs. 75.50 through 75.52'' and 
``Secs. 75.53 through 75.56'' to read as follows:


Sec. 9.1  OMB approvals under the Paperwork Reduction Act.

* * * * *

------------------------------------------------------------------------
                                                             OMB Control
                      40 CFR Citation                            No.    
------------------------------------------------------------------------
                                                                        
                  *        *        *        *        *                 
Continuous Emission Monitoring                                          
                  *        *        *        *        *                 
75.50-75.52................................................    2060-0258
75.53-75.56................................................    2060-0258
                  *        *        *        *        *                 
------------------------------------------------------------------------

PART 72--PERMITS REGULATION

    3. The authority citation for part 72 continues to read as follows:

    Authority: 42 U.S.C. 7651, et seq.

Subpart A--Acid Rain Program General Provisions

    4. Section 72.2 is amended by revising the definitions of 
``Calibration gas'', ``Capacity factor'', ``Diesel fuel'', ``Gas-
fired'', ``Maximum potential NOx emission rate'', ``Monitor 
operating hour'', ``Natural gas'', ``Oil-fired'', ``Peaking unit'', 
``Quality assured monitoring operating hour'', ``Stationary gas 
turbine'' and ``Unit operating hours'', and by adding, in alphabetical 
order, new definitions for ``Backup fuel'', ``By-pass operating 
quarter'', ``Diesel-fired unit'', ``Emergency fuel'', ``Excepted 
monitoring system'', ``Flue gas desulfurization system'', ``Gaseous 
fuel'', ``Hour before and after'', ``NIST traceable reference 
material'', ``Ozone nonattainment area'', ``Ozone transport region'', 
``Pipeline natural gas'', [[Page 26514]] ``Research gas material'', 
``Unit operating day'', and ``Unit operating quarter''; and by removing 
the definition of ``zero ambient air material'' and adding a definition 
of ``zero air material'' to read as follows:


Sec. 72.2  Definitions.

* * * * *
    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.
* * * * *
    Bypass operating quarter means a calendar quarter during which 
emissions pass through a stack, duct or flue that bypasses add-on 
emission controls.
* * * * *
    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.
* * * * *
    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).
* * * * *
    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.
* * * * *
    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.
* * * * *
    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.''
* * * * *
    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.
* * * * *
    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
    (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.
* * * * *
    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.
    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.
* * * * *
    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) [[Page 26515]] collected 
during the hour or portion of an hour.
* * * * *
    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.
* * * * *
    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.
* * * * *
    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 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.
* * * * *
    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.
* * * * *
    Pipeline natural gas means natural gas that is provided by a 
supplier through a pipeline.
* * * * *
    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.
* * * * *
    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.
* * * * *
    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.
* * * * *
    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.
* * * * *
    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.
* * * * *
    5. Section 72.13 is amended by redesignating paragraphs (a)(8) and 
[[Page 26516]] (a)(9) as (a)(9) and (a)(10), and by adding paragraph 
(a)(8), and by revising newly designated paragraphs (a)(9) and (a)(10) 
to read as follows:


Sec. 72.13  Incorporation by reference.

* * * * *
    (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.
* * * * *

PART 75--CONTINUOUS EMISSIONS MONITORING

    6-7. The authority citation for part 75 is revised to read as 
follows:

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


Sec. 75.2  [Amended]

    8. Section 75.2 is amended by removing paragraph (b)(4).
    9. Section 75.4 is amended by revising the last sentence of 
paragraph (a) introductory text and by revising paragraphs (a)(1), 
(a)(2), (a)(3), (a)(4), (b), (c), and (d), by redesignating and 
revising paragraph (e) as paragraph (h) and by adding new paragraphs 
(e), (f), and (g) to read as follows:


Sec. 75.4  Compliance dates.

    (a) * * * 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) * * *
    (b) In accordance with Sec. 75.20, the owner or operator of each 
new affected unit shall ensure that all monitoring systems required 
under this part for monitoring of SO2, NO, CO2, 
opacity, and volumetric flow are installed and all certification tests 
are completed on or before the later of the following dates:
    (1) January 1, 1995, except that for a gas-fired unit or oil-fired 
unit located in an ozone nonattainment area or the ozone transport 
region, the date for installation and completion of all certification 
tests for NO and CO2 monitoring systems shall be July 1, 
1995 and for a gas-fired unit or an oil-fired unit not located in an 
ozone nonattainment area or the ozone transport region, the date for 
installation and completion of all certification tests for NO 
and CO2 monitoring systems shall be January 1, 1996; or
    (2) Not later than 90 days after the date the unit commences 
commercial operation, notice of which date shall be provided under 
subpart G of this part.
    (c) In accordance with Sec. 75.20, the owner or operator of any 
unit affected under any paragraph of Sec. 72.6(a)(3) (ii) through (vii) 
of this chapter shall ensure that all monitoring systems required under 
this part for monitoring of SO2, NO, CO2, opacity, 
and volumetric flow are installed and all certification tests are 
completed on or before the later of the following dates:
    (1) January 1, 1995, except that for a gas-fired unit or oil-fired 
unit located in an ozone nonattainment area or the ozone transport 
region, the date for installation and completion of all certification 
tests for NO and CO2 monitoring systems shall be July 1, 
1995 and for a gas-fired unit or an oil-fired unit not located in an 
ozone nonattainment area or the ozone transport region, the date for 
installation and completion of all certification tests for NO 
and CO2 monitoring systems shall be January 1, 1996; or
    (2) Not later than 90 days after the date the unit becomes subject 
to the requirements of the Acid Rain Program, notice of which date 
shall be provided under subpart G of this part.
    (d) In accordance with Sec. 75.20, the owner or operator of an 
existing unit that is shutdown and is not yet operating by the 
applicable dates listed in paragraph (a) of this section, 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 [[Page 26517]] atmosphere through the new stack, flue, or flue gas 
desulfurization system, notice of which date shall be provided under 
subpart G of this part. Until emissions first pass through the new 
stack, flue or flue gas desulfurization system, the unit is subject to 
the appropriate deadline in paragraph (a) of this section. The owner or 
operator shall determine and report SO2 concentration, 
NO emission rate, CO2 concentration, and flow data for 
all unit operating hours after emissions first pass through the new 
stack, flue, or flue gas desulfurization system until all required 
certification tests are successfully completed using either:
    (1) The appropriate value for substitution of missing data upon 
recertification pursuant to Sec. 75.20(b)(3); or
    (2) Reference methods under Sec. 75.22(b) of this part; or
    (3) Another procedure approved by the Administrator pursuant to a 
petition under Sec. 75.66.
    (f) In accordance with Sec. 75.20, the owner or operator of a gas-
fired or oil-fired peaking unit, if planning to use appendix E of this 
part, shall ensure that the required certification tests for excepted 
monitoring systems under appendix E are completed for backup fuel as 
defined in Sec. 72.2 of this chapter by no later than the later of: 30 
unit operating days after the date that the unit first combusted that 
backup fuel after the certification testing of the primary fuel; or The 
deadline in paragraph (a) of this section. The owner or operator shall 
determine and report NO emission rate data for all unit 
operating hours that the backup fuel is combusted after the applicable 
compliance date in paragraph (a) of this section until all required 
certification tests are successfully completed using either:
    (1) The maximum potential NO emission rate; or
    (2) Reference methods under Sec. 75.22(b) of this part; or
    (3) Another procedure approved by the Administrator pursuant to a 
petition under Sec. 75.66.
    (g) 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.
    10. Section 75.5 is amended by revising paragraph (e) and by adding 
paragraph (f) to read as follows:


Sec. 75.5  Prohibitions.

* * * * *
    (e) No owner or operator of an affected unit shall disrupt the 
continuous emission monitoring system, any portion thereof, or any 
other approved emission monitoring method, and thereby avoid monitoring 
and recording SO2, NOX, or CO2 emissions discharged to the 
atmosphere, except for periods of recertification, or periods when 
calibration, quality assurance, or maintenance is performed pursuant to 
Sec. 75.21 and appendix B of this part.
    (f) No owner or operator of an affected unit shall retire or 
permanently discontinue use of the continuous emission monitoring 
system, any component thereof, the continuous opacity monitoring 
system, or any other approved emission monitoring system under this 
part, except under any one of the following circumstances:
    (1) During the period that the unit is covered by an approved 
retired unit exemption under Sec. 72.8 of this chapter that is in 
effect; or
    (2) The owner or operator is monitoring emissions from the unit 
with another certified monitoring system 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.
    11. Section 75.6 is amended by revising paragraphs (a), (b)(1) 
through (b)(6); by removing paragraphs (b)(7) through (b)(9); and by 
adding paragraphs (c), (d), and (e) to read as follows:


Sec. 75.6  Incorporation by reference.

* * * * * *
    (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. [[Page 26518]] 
    (10) ASTM D1480-91, Standard Test Method for Density and Relative 
Density (Specific Gravity) of Viscous Materials by Bingham Pycnometer, 
for appendix D of this part.
    (11) ASTM D1481-91, Standard Test Method for Density and Relative 
Density (Specific Gravity) of Viscous Materials by Lipkin Bicapillary 
Pycnometer, for appendix D of this part.
    (12) ASTM D1552-90, Standard Test Method for Sulfur in Petroleum 
Products (High Temperature Method), for appendices A and D of the part.
    (13) ASTM D1826-88, Standard Test Method for Calorific (Heating) 
Value of Gases in Natural Gas Range by Continuous Recording 
Calorimeter, for 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.
    (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) * * *
    (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 [[Page 26519]] 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.
    12. Section 75.8 is added to Subpart A to read as follows:


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, 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.
Subpart B--Monitoring Provisions

    13. Section 75.10 is amended by revising paragraphs (a)(1), (a)(2), 
(a)(3), (d), (e), and (f) to read as follows:


Sec. 75.10  General operating requirements.

    (a) * * *
    (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
* * * * *
    (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 [[Page 26520]] 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 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.
* * * * *
    14. Section 75.11 is amended by revising paragraphs (c) and (d), 
redesignating paragraph (e) as paragraph (f), and reserving paragraph 
(e) to read as follows:


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

* * * * *
    (c) Unit with no location for a flow monitor meeting siting 
requirements. Where no location exists that satisfies the minimum 
physical siting criteria in appendix A to this part for installation of 
a flow monitor in either the stack or the ducts serving an affected 
unit or installation of a flow monitor in either the stack or ducts is 
demonstrated to the satisfaction of the Administrator to be technically 
infeasible, either:
    (1) The designated representative shall petition the Administrator 
for an alternative method for monitoring volumetric flow in accordance 
with Sec. 75.66; or
    (2) The owner or operator shall construct a new stack or modify 
existing ductwork to accommodate the installation of a flow monitor, 
and the designated representative shall petition the Administrator for 
an extension of the required certification date given in Sec. 75.4 and 
approval of an interim alternative flow monitoring methodology in 
accordance with Sec. 75.66. The Administrator may grant existing Phase 
I affected units an extension to January 1, 1995, and existing Phase II 
affected units an extension to January 1, 1996 for the submission of 
the certification application for the purpose of constructing a new 
stack or making substantial modifications to ductwork for installation 
of a flow monitor; or
    (3) The owner or operator shall install a flow monitor in any 
existing location in the stack or ducts serving the affected unit at 
which the monitor can achieve the performance specifications of this 
part.
    (d) Gas-fired 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) [Reserved]
* * * * *
    15. Section 75.12 is amended by revising paragraph (c) to read as 
follows:


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

* * * * *
    (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.
* * * * * [[Page 26521]] 
    16. Section 75.13 is amended by revising paragraphs (a) and (c) to 
read as follows:


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.''
* * * * *
    (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.''
    17. Section 75.14 is amended by revising paragraph (c) to read as 
follows:


Sec. 75.14  Specific provisions for monitoring opacity.

* * * * *
    (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.
* * * * *
    18. Section 75.15 is amended by revising paragraphs (a) 
introductory text, (a)(1), (a)(2), and Equations 5 and 7 in paragraph 
(b)(1) to read as follows:


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

    (a) Additional monitoring provisions. In addition to the SO2 
monitoring requirements in Sec. 75.11 or Sec. 75.16, for the purposes 
of adequately monitoring SO2 emissions removal by qualifying Phase 
I technology operated pursuant to Sec. 72.42 of this chapter, the owner 
or operator shall, except where specified below, use both an inlet 
SO2-diluent continuous emission monitoring system and an outlet 
SO2-diluent continuous emission monitoring system, consisting of 
an SO2 pollutant concentration monitor and a diluent CO2 or 
O2 monitor. (The outlet SO2-diluent continuous emission 
monitoring system may consist of the same SO2 pollutant 
concentration monitor that is required under Sec. 75.11 or Sec. 75.16 
for the measurement of SO2 emissions discharged to the atmosphere 
and the diluent monitor used as part of the NO continuous 
emission monitoring system that is required under Sec. 75.12 or 
Sec. 75.17 for the measurement of NO emissions discharged 
into the atmosphere.) During the period when required to measure 
emissions removal efficiency, from January 1, 1997 through December 31, 
1999, the owner or operator shall meet the general operating 
requirements in Sec. 75.10 for both the inlet and the outlet SO2-
diluent continuous emission monitoring systems, and in addition, the 
owner or operator shall comply with the monitoring provisions in this 
section. On January 1, 2000, the owner or operator may cease operating 
and/or reporting on the inlet SO2-diluent continuous emission 
monitoring system results for the purposes of the Acid Rain Program.
    (1) Pre-combustion technology. The owner or operator of an affected 
unit for which a precombustion technology has been employed for the 
purpose of meeting qualifying Phase I technology requirements shall use 
sections 4 and 5 of Method 19 in appendix A of part 60 of this chapter 
to estimate, daily, for the purposes of this part, the percentage 
SO2 removal efficiency from such technology, and shall substitute 
the following ASTM methods for sampling, preparation, and analysis of 
coal for those cited in Method 19: ASTM D2234-89, Standard Test Method 
for Collection of a Gross Sample of Coal (Type I, Conditions A, B, or C 
and systematic spacing), ASTM D2013-86, Standard Method of Preparing 
Coal Samples for Analysis, ASTM D2015-91, Standard Test Method for 
Gross Calorific Value of Coal and Coke by the Adiabatic Calorimeter, 
and ASTM D3177-89, Standard Test Methods for Total Sulfur in the 
Analysis Sample of Coal and Coke, or ASTM D4239-85, Standard Test 
Method for Sulfur in the Analysis Sample of Coal and Coke Using High 
Temperature Tube Furnace Combustion Methods. Each of the preceding ASTM 
methods is incorporated by reference in Sec. 75.6.
    (2) Combustion technology. The owner or operator of an affected 
unit for which a combustion technology has been installed and operated 
for the purpose of meeting qualifying Phase I technology requirements 
shall use the coal sampling and analysis procedures in paragraph (a)(1) 
of this section and Equation 5 in paragraph (b) of this section to 
estimate the percentage SO2 removal efficiency from such 
technology.
* * * * *
    (b) * * *
    (1) * * *
[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.
(Eq. 6) * * *
[GRAPHIC][TIFF OMITTED]TR17MY95.001


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.
* * * * *
    19. Section 75.16 is revised to read as follows: [[Page 26522]] 


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) 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 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 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 
[[Page 26523]] 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''.
    (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.
    20. Section 75.17 is amended by revising paragraph (a)(2)(i)(B), 
adding paragraph (a)(2)(i)(C), removing paragraph (c), redesignating 
paragraph (d) as paragraph (c), and revising the newly designated 
paragraph (c) to read as follows:


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

    (a) * * *
    (2) * * *
    (i) * * *
    (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.
* * * * *
    (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 [[Page 26524]] 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.
    21. Section 75.18 is amended by revising paragraph (b) to read as 
follows:


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

    (a) * * *
    (b) Unit using bypass stack. Where any portion of the flue gases 
from an affected unit can be routed so as to bypass the installed 
continuous opacity monitoring system, the owner or operator shall 
install, certify, operate, and maintain a certified continuous opacity 
monitoring system on each bypass stack flue, duct, or stack gas stream 
unless either:
    (1) An applicable Federal, State, or local opacity regulation or 
permit exempts the unit from a requirement to install a continuous 
opacity monitoring system in the bypass stack; or
    (2) A continuous opacity monitoring system is already installed and 
certified at the inlet of the add-on emissions controls; or
    (3) The owner or operator monitors opacity using Method 9 of 
appendix A, part 60 of this chapter whenever emissions pass through the 
bypass stack.

Subpart C--Operation and Maintenance Requirements

    22. Section 75.20 is amended by revising paragraphs (a) 
introductory text, (a)(1), (a)(2), (a)(3), (a)(4) introductory text, 
(a)(4)(iii), (a)(4)(iv), (a)(5), (b), the last sentence of paragraph 
(c) introductory text, (c)(1)(v), (c)(2)(ii), (c)(2)(iii), (c)(4), 
(c)(5) introductory text, (c)(5)(iv), (c)(6)(i), (c)(8), (d), (f) 
introductory text, (f)(1), the last sentence of paragraph (f)(2), 
(f)(3) and (g), by adding a new sentence at the end of paragraph 
(f)(2), and by removing paragraph (c)(9) to read as follows:


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.
* * * * *
    (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 [[Page 26525]] 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 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. 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 [[Page 26526]] apply in the 
event of a loss of recertification.
    (c) * * * 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) * * *
    (v) A cycle time test.
    (2) * * *
    (ii) Relative accuracy test audits at three flue gas velocities; 
and
    (iii) A bias test (at normal operating load).
    (3) * * *
    (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:
* * * * *
    (iv) A cycle-time test.
    (6) * * *
    (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.
* * * * *
    (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 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.
* * * * *
    (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 and procedures 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 by performing all of the tests under paragraph 
(c) of this section that can be applied to the alternative monitoring 
system. 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 (f)(1), (f)(2), and (f)(3) of this section.
    (1) Each alternative monitoring system shall be certified by the 
Administrator before it may be authorized for use under the Acid Rain 
Program.
    (i) Certification testing notification. The designated 
representative shall provide certification testing notification 
according to the procedures in subparagraph (a)(1) of this section 
prior to conducting certification testing.
    (ii) Monitoring plan. The designated representative shall submit an 
initial monitoring plan at least 45 days prior to the first day of 
certification testing.
    (iii) Certification application. The designated representative 
shall submit a certification application for the alternative monitoring 
system prior to use in the Acid Rain Program. Each complete 
certification application shall include:
    (A) Information and test results for the relative accuracy test and 
any other applicable tests in paragraph (c) of this section;
    (B) A revised monitoring plan; and
    (C) Results of the tests for verification of the accuracy of 
emissions calculations and missing data [[Page 26527]] procedures 
performed by the automated data acquisition and handling system.
    (2) * * * The procedures for provisional certification under 
paragraph (a)(3) of this section and for a 120-day EPA review period 
for initial certification under paragraph (a)(4) of this section shall 
apply to alternative monitoring systems, provided that the 
Administrator has already approved the petition or petitions required 
under subpart E of this part. The designated representative shall 
report no data from an alternative monitoring system in a quarterly 
report from a period prior to both Administrator approval of the 
petition or petitions under subpart E of this part and also successful 
completion of certification testing.
    (3) The recertification requirements of paragraph (b) of this 
section shall apply to alternative monitoring systems, except that the 
owner or operator shall perform the tests specified under paragraph 
(f)(1)(iii) of this section.
    (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 
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.
    23. Section 75.21 is amended by adding paragraphs (d) and (e) to 
read as follows:


Sec. 75.21  Quality assurance and quality control requirements.

* * * * *
    (d) Notification for periodic relative accuracy test audits. The 
owner or operator or the designated representative shall submit a 
written notice of the dates of relative accuracy testing as specified 
in Sec. 75.61.
    (e) Consequences of audits. The owner or operator shall invalidate 
data from a continuous emission monitoring system or continuous opacity 
monitoring system upon failure of an audit under 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) [[Page 26528]] 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.
    24. Section 75.22 is amended by revising paragraphs (a) 
introductory text, (a)(5), and (a)(6) and by adding paragraphs (b) and 
(c) to read as follows:


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.
* * * * *
    (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.
    25. Section 75.23 is revised to read as follows:
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)
    26. Section 75.24 is amended by revising paragraphs (d) and (e) 
introductory text to read as follows:


Sec. 75.24  Out-of-control periods.

* * * * *
    (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.

Subpart D--Missing Data Substitution Procedures

    27. Section 75.30 is revised to read as follows:


Sec. 75.30  General provisions.

    (a) Except as provided in Sec. 75.34, the owner or operator shall 
provide substitute data for each affected unit using a continuous 
emission monitoring system according to the missing data procedures in 
this subpart whenever the unit combusts any fuel and:
    (1) A valid, quality-assured hour of SO2 concentration data 
(in ppm) has not been measured and recorded for an affected unit by a 
certified SO2 pollutant concentration monitor, or by an approved 
alternative monitoring method under subpart E of this part, except as 
provided in paragraph (d) of this section; or
    (2) A valid, quality-assured hour of flow data (in scfh) has not 
been measured and recorded for an affected unit from a certified flow 
monitor, or by an approved alternative monitoring system under subpart 
E of this part; or
    (3) A valid, quality-assured hour of NOX emission rate data 
(in lb/mmBtu) has not been measured 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, [[Page 26529]] 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) [Reserved]
    (e) [Reserved]
    28. Section 75.31 is amended by revising paragraphs (a), (b) and 
(c)(3) to read as follows:
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) * * *
    (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.
    29. Section 75.32 is amended by revising paragraphs (a) 
introductory text, the first sentence of paragraphs (a)(1) and (a)(2) 
and paragraph (b) to read as follows:


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. * * 
*
    (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. 
* * *
    (3) * * *
    (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.
    30. Section 75.33 is amended by adding a sentence to the end of 
paragraph (a) and by adding paragraph (c)(5) to read as follows:


Sec. 75.33  Standard missing data procedures.

    (a) * * * 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. * * *
* * * * *
    (c) * * *
    (5) Whenever no proper 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.
* * * * *
    31. Section 75.35 is added as follows:


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 [[Page 26530]] 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.
    32. Section 75.36 is added as follows:


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 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.

Subpart E--Alternative Monitoring Systems
    33. Section 75.41 is amended by adding a sentence to the end of 
paragraph (a)(1), revising paragraphs (b)(1)(i), (b)(2)(iv)(A), 
(b)(2)(iv)(C), (c)(1)(i), (c)(1)(ii) and (c)(2)(ii) to read as follows:


Sec. 75.41  Precision criteria.

    (a) * * * [[Page 26531]] 
    (1) * * * For the purposes of this subpart, each reference method 
run shall be 30 to 60 minutes in duration.
* * * * *
    (b) * * *
    (1) * * *
    (i) Apply the log transformation to each measured value of either 
the certified continuous emissions monitoring system, certified flow 
monitor or reference method, using the following equation:

lv = ln ev (Eq. 11)

Where:

ev= Hourly value generated by the certified continuous emissions 
monitoring system, certified flow monitoring system, or reference 
method.
* * * * *
    (2) * * *
    (iv) * * *
    (A) The set of measured hourly values, ev, generated by the 
certified continuous emissions monitoring system, certified flow 
monitoring system, or reference method.
* * * * *
    (C) The set of hourly differences, ev - ep, between the 
hourly values, ev, generated by the certified continuous emissions 
monitoring system, certified flow monitoring system, or reference 
method and the hourly values, ep, generated by the proposed 
alternative monitoring system.
* * * * *
    (c) * * *
    (1) * * *
    (i) Calculate the variance of the certified continuous emission 
monitoring system, certified flow monitor, or reference method as 
applicable, Sv2, and the proposed method, Sp2, 
using the following equation.
[GRAPHIC][TIFF OMITTED]TR17MY95.002


(Eq. 23)
Where:

ei = Measured values of either the certified continuous emission 
monitoring system, certified flow monitor, or reference method, as 
applicable, or proposed method.
em = Mean of either the certified continuous emission monitoring 
system or certified flow monitor, or reference method, 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, certified flow monitor, or reference method, as 
applicable, by calculating the F-value using the following equation.
[GRAPHIC][TIFF OMITTED]TR17MY95.003


    (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) * * *
    (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]TR17MY95.004


(Eq. 27)
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.
* * * * *
    34. Section 75.47 is revised to read as follows:


Sec. 75.47   Criteria for a class of affected units.

    (a) The owner or operator of an affected unit that is determined by 
the Administrator to be representative of a class of affected units may 
petition the Administrator under Sec. 75.48 for approval of an 
alternative monitoring system that may be used at any unit in that 
class based on testing performed only at the representative unit.
    (b) The owner or operator of an affected unit representing a class 
of affected units shall provide the following information to obtain 
class status:
    (1) A description of the affected unit at which the demonstration 
will be performed and how it appropriately represents the class of 
affected units; and
    (2) A description and listing of the class of affected units, 
including a listing of all units and data describing all the affected 
units which will comprise the class; and
    (3) A demonstration that the magnitude of emissions for 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 of 
each request for approval of class status and shall provide a 30-day 
period for public comment, prior to granting approval.
    (d) The designated representative shall provide the information 
required in Sec. 75.48 based on testing at the representative unit when 
petitioning for approval of the alternative monitoring system for 
members of the class. A request for class status under this section may 
be submitted simultaneously with a petition under Sec. 75.48, or 
following approval of a petition under Sec. 75.48.
    35. Section 75.48 is amended by revising paragraphs (a) 
introductory text, and (a)(1), and by adding paragraphs (b) and (c) to 
read as follows:


Sec. 75.48   Petition for an alternative monitoring system.
    (a) The designated representative shall submit the following 
information in the petition for approval of an alternative monitoring 
system for an affected unit, or a class of affected units approved 
pursuant to Sec. 75.47.
    (1) Source identification information for the affected unit at 
which testing was performed.
* * * * *
    (b) The Administrator will publish a notice of receipt of each 
petition for approval of an alternative monitoring 
[[Page 26532]] system in the Federal Register and, following a public 
comment period of 30 days, will issue a notice of approval or 
disapproval of the alternative monitoring system.
    (c) No alternative monitoring system approved under this section 
shall be used under the Acid Rain Program prior to successful 
completion of all certification tests under Sec. 75.20(f).

Subpart F--Recordkeeping Requirements

    36. Section 75.50 is amended by revising paragraph (a) to read as 
follows:


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.
* * * * *
    37. Section 75.51 is amended by adding paragraph (e) to read as 
follows:


Sec. 75.51   General recordkeeping provisions for specific situations.

* * * * *
    (e) 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. 75.51 or 75.55 prior to January 1, 1996. On or after 
January 1, 1996, the owner or operator shall meet the requirements of 
Sec. 75.55 only.
    38. Section 75.52 is amended by adding paragraph (b) to read as 
follows:


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

    (a) * * *
    (b) 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. 75.52 or 75.56 prior to January 1, 1996. On or after 
January 1, 1996, the owner or operator shall meet the requirements of 
Sec. 75.56 only.
    39. Section 75.53 is amended by revising paragraphs (a), (b), (c) 
introductory text, (c)(1), (c)(2)(ii), (c)(4) introductory text, 
(c)(4)(ii), (c)(4)(vi), (c)(5)(ii), (c)(6), (c)(7), (c)(8), (c)(9), 
(d)(1), and (d)(2) and by adding paragraphs (c)(10), and (d)(3) to read 
as follows:


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) * * *
    (ii) Classification of unit as one of the following: Phase I 
(including substitution or compensating units), Phase II, new, or 
nonaffected;
* * * * *
    (4) Monitoring component table. Identification and description of 
each monitoring component (including each monitor and its identifiable 
components such as analyzer and/or probe) in the continuous emission 
monitoring systems (i.e., SO2 pollutant concentration monitor, 
flow monitor, moisture monitor; NOX pollutant concentration 
monitor and diluent gas monitor) the continuous opacity monitoring 
system, or excepted monitoring system (i.e., fuel flowmeter, data 
acquisition and handling system), including:
* * * * *
    (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;
* * * * *
    (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) * * *
    (ii) For software components, identification of the provider and a 
brief description of features;
* * * * *
    (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 monitor. In addition, 
the table must identify [[Page 26533]] calibration gas levels for the 
calibration error test and the linearity check, and calculations made 
to determine each span value.
    (d) * * *
    (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.
    40. Section 75.54 is added to read as follows:


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 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. [[Page 26534]] 
    (3) For SO2 mass emissions as measured and reported from the 
certified primary monitoring system(s), certified redundant or non-
redundant back-up monitoring system(s), or other approved method(s) of 
emissions determination:
    (i) Date and hour;
    (ii) Hourly SO2 mass emissions (lb/hr, rounded to the nearest 
tenth);
    (iii) Hourly SO2 mass emissions (lb/hr, rounded to the nearest 
tenth) adjusted for bias, if bias adjustment factor required, as 
provided for in Sec. 75.24(d); and
    (iv) Identification code for emissions formula used to derive 
hourly SO2 mass emissions from SO2 concentration and flow 
data in paragraphs (c)(1) and (c)(2) of this section as provided for in 
Sec. 75.53.

     Table 4.--Codes for Method of Emissions and Flow Determination     
                                [Amended]                               
------------------------------------------------------------------------
   Code        Hourly emissions/flow measurement or 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);
    (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 [[Page 26535]] 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.
    41. Section 75.55 is added to read as follows:


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
    (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) [Reserved]
    (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
    (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 [[Page 26536]] 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) [Reserved]
    (f) The owner or operator shall meet the requirements of this 
section on or after January 1, 1996.
    42. Section 75.56 is added to read as follows:


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, 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: 
[[Page 26537]] 
    (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) [Reserved]
    (7) Results of all trial runs and certification tests and quality 
assurance activities and measurements (including all reference method 
field test sheets, charts, records of combined system responses, 
laboratory analyses, and example calculations) necessary to 
substantiate compliance with all relevant appendices in this part. This 
information shall include, but shall not be limited to, the following 
reference method data:
    (i) For each run of each test using Method 2 in appendix A of part 
60 of this chapter to determine volumetric flow rate:
    (A) Pitot tube coefficient;
    (B) Date of pitot tube calibration;
    (C) Average square root of velocity head of stack gas (inches of 
water) for the run;
    (D) Average absolute stack gas temperature,  deg.R;
    (E) Barometric pressure at test port, inches of mercury;
    (F) Stack static pressure, inches of 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
    (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
    (vi) Description of fuel flowmeter calibration specification or 
procedure (in the certification application, or periodically if a 
different method is used for annual quality assurance testing).
    (2) For gas-fired peaking units or oil-fired peaking units using 
the optional procedures of appendix E of this part, for each initial 
performance, periodic, or quality assurance/quality control-related 
test:
    (i) For each run of emissions data;
    (A) Run start date and time;
    (B) Run end date and time;
    (C) Fuel flow (lb/hr, gal/hr, scf/hr, bbl/hr, or m3/hr);
    (D) Gross calorific value (heat content) of fuel (Btu/lb or Btu/
scf);
    (E) Density of fuel (if needed to convert mass to volume);
    (F) Total heat input during the run (mmBtu);
    (G) Hourly heat input rate for run (mmBtu/hr);
    (H) Response time of the O2 and NOX reference method 
analyzers;
    (I) NOX concentration (ppm);
    (J) O2 concentration (percent O2); [[Page 26538]] 
    (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.

Subpart G--Reporting Requirements

    43. Section 75.60 is amended by revising paragraphs (b)(1) and 
(b)(2), and by adding paragraph (c) to read as follows:


Sec. 75.60  General provisions.

* * * * *
    (b) * * *
    (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 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.
    44. Section 75.61 is revised to read as follows:


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 [[Page 26539]] 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.
    (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) Periodic relative accuracy test audits. The owner or operator 
or designated representative of an affected unit shall submit written 
notice of the date of periodic relative accuracy testing performed 
under appendix B of this part no later than 21 days prior to the first 
scheduled day of testing. Testing may be performed on a date other than 
that already provided in a notice under this subparagraph as long as 
notice of the new date is provided either in writing or by telephone or 
other means at least 7 days prior to the original scheduled test date 
or the revised test date, whichever is earlier. Notwithstanding these 
notice requirements, the owner or operator may elect to repeat a 
periodic relative accuracy test immediately, without additional 
notification whenever the owner or operator has determined that a test 
was failed, or that a second test is necessary in order to attain a 
reduced relative accuracy test frequency.
    (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.
    (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.
    45. Section 75.62 is amended by revising paragraph (a) and adding 
paragraph (c) to read as follows:


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.
* * * * *
    (c) Format. Each monitoring plan shall be submitted in a format 
specified by the Administrator, including information in electronic 
format and on paper.
    46. Section 75.63 is revised to read as follows:


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 [[Page 26540]] 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.
    47. Section 75.64 is amended by revising the first two sentences of 
paragraph (a) introductory text, by revising paragraphs (a)(5), (b) and 
(d), by revising the last sentence of paragraph (e) introductory text 
and by removing paragraphs (e)(1) and (2) to read as follows:


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. 
* * *
    (5) Total heat input (mmBtu) for quarter and cumulative heat input 
for calendar year.
* * * * *
    (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.
* * * * *
    (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) * * * Each report shall include all measurements and 
calculations necessary to substantiate that the qualifying technology 
achieves the overall percentage reduction in SO2 emissions.
    48. Section 75.65 is revised to read as follows:


Sec. 75.65  Opacity reports.

    The owner or operator or designated representative shall report 
excess emissions of opacity recorded under Secs. 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.
    49. Section 75.66 is amended by redesignating paragraphs (a), (b), 
(c), (d), (e) and (f) as paragraphs (b), (c), (d), (e), (f) and (i), by 
adding new paragraphs (a), (g), and (h), and by revising newly 
designated paragraphs (b), (c), and (i), to read as follows:


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.
* * * * *
    (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 
[[Page 26541]] 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.
    50. Section 75.67 is amended by revising paragraph (a) to read as 
follows:


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.
* * * * *

Appendix A to Part 75--Specifications and Test Procedures

    51. Appendix A to part 75, section 1 is amended by revising section 
1.1.2, by revising the fourth sentence in section 1.2; and by revising 
section 1.2.1 and by revising the first sentence of section 1.2.2 to 
read as follows:

1. Installation and Measurement Location

1.1  * * *

1.1.1  * * *

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

    * * * 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. * * *

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  Flow Monitor Certification Date Extension

    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 the required 
certification date for the flow monitor. * * *
* * * * *
    52. Appendix A to part 75, section 2 is amended by revising 
sections 2.1.1; revising the first paragraph of section 2.1.1.1, and by 
revising sections 2.1.1.2, 2.1.1.4, 2.1.2, 2.1.2.1, 2.1.2.2, 2.1.2.4, 
2.1.3 and 2.1.4 to read as follows:

2. Equipment Specifications

2.1  * * *

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 26542]]

[GRAPHIC][TIFF OMITTED]TR17MY95.005


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 * * *

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 26543]]
  Table 2-1.--Maximum Potential Concentration for NOX--Coal-Fired Units 
------------------------------------------------------------------------
        Unit type          Maximum potential concentration for NOX (ppm)
------------------------------------------------------------------------
Tangentially-fired dry     460                                          
 bottom and fluidized bed.                                              
Wall-fired dry bottom,     675                                          
 turbo-fired dry bottom,                                                
 stokers.                                                               
Roof-fired (vertically-    975                                          
 fired) dry bottom, cell                                                
 burners, arch-fired.                                                   
Cyclone, wall-fired wet    1200                                         
 bottom, wet bottom 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     380                                          
 bottom.                                                                
Wall-fired dry bottom....  600                                          
Roof-fired (vertically-    550                                          
 fired) dry bottom, arch-                                               
 fired.                                                                 
Existing combustion        200                                          
 turbine or combined                                                    
 cycle turbine.                                                         
New stationary gas         50                                           
 turbine/combustion                                                     
 turbine.                                                               
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 * * *

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 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 
[[Page 26544]] 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,
%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.
* * * * *
    53. Appendix A to part 75, section 3 is amended by revising 
sections 3.3.3 and 3.5 to read as follows:

3. Performance Specifications

* * * * *

3.3  * * *

3.3.1  * * *

3.3.2  * * *

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.
* * * * *

3.5  Cycle Time

    The cycle time for pollutant concentration monitors, and 
continuous emission monitoring systems shall not exceed 15 min.
* * * * *
    54. Appendix A to part 75, section 4 is amended by adding a third 
paragraph to read as follows:

4. Data Acquisition and Handling Systems

* * * * *
    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.
* * * * *
    55. Appendix A to part 75, section 5 is amended by revising section 
5.1.2 and by adding sections 5.1.4, 5.1.5, and 5.1.6 to read as 
follows:

5. Calibration Gas

5.1 Reference Gases

5.1.1  * * *

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  * * *

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 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. 
[[Page 26545]] 

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.
* * * * *
    56. Appendix A to part 75, section 6 is amended by adding a 
sentence to the end of section 6.1; by revising the first sentence in 
the second paragraph of section 6.2; and by revising sections 6.5, 
6.5.1, 6.5.2, 6.5.5, 6.5.6, 6.5.7, and 6.5.10 to read as follows:

6. Certification Tests and Procedures

6.1  Pretest Preparation

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

6.2  Linearity Check

* * * * *
    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. * * 
*
* * * * *

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 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  * * *

6.5.4  * * *

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  * * *

6.5.9  * * *

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; [[Page 26546]] 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.
* * * * *
    58. Appendix A to part 75, section 7 is amended by revising section 
7.2.2; by revising the section heading for section 7.3; and by revising 
sections 7.6.4 and 7.6.5 to read as follows:

7. Calculations

* * * * *

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).

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

* * * * *

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:

CEMi Adjusted=Data (measurement) provided by the monitor 
at time i.
CEMi Monitor=Data value, adjusted for bias, at time i.
BAF=Bias adjustment factor, defined by
[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.
* * * * *

APPENDIX B TO PART 75--QUALITY ASSURANCE AND QUALITY CONTROL 
PROCEDURES

    59. Appendix B to part 75, section 2 is amended by revising 
sections 2.1.4, 2.2, 2.2.1, 2.2.2, 2.3, 2.3.1, and 2.3.2; and by 
amending Figure 2 at the end of the appendix to read as follows:
* * * * *

2. Frequency of Testing

2.1  Daily Assessments * * *
2.1.1  * * *

2.1.2  * * *

2.1.3  * * *

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.
* * * * *

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  * * *

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 [[Page 26547]] 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 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.
* * * * *

                          Figure 2.--Relative Accuracy Test Frequency Incentive System                          
----------------------------------------------------------------------------------------------------------------
                                                     Semiannually\1\                                            
                      RATA                              (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.                 

Appendix C to Part 75--Missing Data Estimation Procedures

    60. Appendix C to part 75, section 1 is amended by revising the 
section heading and the first paragraph of section 1.2 and by revising 
the first paragraph of section 1.3 to read as follows:

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

* * * * *

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 [[Page 26548]] Administrator 
will review all applications on a case-by-case basis.
* * * * *

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.
* * * * *
    61. Appendix C to part 75, section 2 is amended by revising section 
2.2.1, Table C-1, and sections 2.2.3, 2.2.3.1, 2.2.3.5, and 2.2.5 to 
read as follows:
* * * * *

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
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  * * *
    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  * * *
    2.2.3.3  * * *
    2.2.3.4  * * *
    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  * * *
    2.2.3.7  * * *
    2.2.3.8  * * *
    2.2.4  * * *
    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  * * *

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

    62. Appendix D to part 75, section 1 is amended by revising section 
1.1; by removing section 1.2 and revising and redesignating section 1.3 
as section 1.2; and by removing section 1.4 to read as follows:

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.

    63. Appendix D to part 75, section 2 is revised to read as follows:

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 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 [[Page 26549]] 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, bypass 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 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, bypass 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 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 [[Page 26550]] 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 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  When data from the fuel flowmeter are missing, 
substitute for each hour in the missing data period the average 
hourly oil flow rate measured and recorded by the fuel flowmeter at 
the closest unit load (in MWe) greater than the load recorded for 
the missing data period for which oil flow rate data are available 
during the previous 720 hours during which the unit combusted oil. 
If no oil flow rate data are available at a load greater than the 
load recorded during the missing data period, substitute the maximum 
flow rate that the flowmeter can measure.
    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.
* * * * * [[Page 26551]] 
    64. Appendix D to part 75, section 3 is amended by revising the 
introductory paragraph; by revising the section heading of section 3.1; 
by revising the definition of the variable ``MSO2'' in Equation D-
2 in section 3.1.1; by revising section 3.1.2; by revising the section 
heading of section 3.2; by revising section 3.2.1; and by adding 
sections 3.3, 3.3.1, 3.3.2, 3.3.3, and 3.4 to read as follows:

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 * * *
Where:

MSO2=Hourly mass of SO2 emitted from combustion of oil, 
lb/hr.
* * * * *
    3.1.2  Record the SO2 mass emissions from oil for each hour 
that oil is combusted.

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.
* * * * *

3.3  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.
* * * * *

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

    65.  Appendix E to part 75, section 1 is amended by revising 
section 1.1; by removing section 1.2, redesignating sections 1.3, 1.3.1 
and 1.3.2 as sections 1.2, 1.2.1 and 1.2.2 and revising new sections 
1.2, 1.2.1 and 1.2.2 to read as follows:

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.
* * * * *
    66. Appendix E to part 75, section 2 is amended by revising 
sections 2.1, 2.1.1, 2.1.2, 2.1.2.1, and 2.1.2.2; by removing section 
2.1.2.3 and redesignating section 2.1.2.4 as 2.1.2.3; by revising 
sections 2.1.3, 2.1.3.1, and 2.1.3.2; by revising sections 2.1.4, 
2.1.5, 2.1.6, 2.1.6.1, and 2.1.6.2; by revising sections 2.3, 2.3.1 and 
2.3.2; by removing sections 2.1.4.1, 2.1.4.2, 2.1.4.3, 2.1.4.4, 2.3.3, 
2.3.3.1 and 2.3.3.3; by redesignating section 2.3.3.2 as section 2.3.3 
and revising new section 2.3.3; by revising section 2.4.1; by revising 
section 2.4.2 and adding sections 2.4.3 and 2.4.4; by revising section 
2.5 and adding sections 2.5.1, 2.5.2, 2.5.3, 2.5.4, and 2.5.5 to read 
as follows:
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 [[Page 26552]] 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 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  * * *

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 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 
[[Page 26553]] 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.
* * * * *
    67. Appendix E to part 75, section 3 is amended by revising section 
3.1; by removing section 3.2, redesignating section 3.3 as 3.2, and 
revising new section 3.2; by redesignating sections 3.4, 3.4.1, 3.4.2, 
3.4.3 as 3.3, 3.3.1, 3.3.2, and 3.3.3; and by removing sections 3.4.4 
and 3.5 and adding section 3.3.4 to read as follows:

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.

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.
* * * * *
    68. Appendix E to part 75, section 4 is amended by revising the 
introductory paragraph and section 4.1 to read as follows:

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.
* * * * *

Appendix F to Part 75--Conversion Procedures

    69. Appendix F to part 75, section 2 is amended by revising section 
2.4 to read as follows:
* * * * *

2. Procedures for SO2 Emissions

* * * * *
    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).
* * * * *
    70. Appendix F to part 75, section 3 is amended by revising the 
equation in section 3.2, by adding a sentence to the end of 3.3.4. 
and by revising sections 3.3.6.1, 3.3.6.2, and 3.4 to read as 
follows: [[Page 26554]] 

3. Procedures for NOX Emission Rate

* * * * *
    3.2  When the NOX continuous emission monitoring system 
uses CO2 as the diluent, use the following conversion 
procedure:
[GRAPHIC][TIFF OMITTED]TR17MY95.014


where:

K, E, Ch, Fc, and %CO2 are defined in section 3.3 of this 
appendix.
Where 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.
* * * * *
    3.3.4  * * * 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.
    3.3.5  * * *
    3.3.6  * * *
    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  * * *
    3.3.6.4  * * *
    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]TR17MY95.016


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  * * *
* * * * *
    71. Appendix F to part 75, section 4 is amended by revising the 
introductory paragraph, by revising the definition of the variable 
``Ch'' in Equation F-11 in section 4.1, by revising sections 4.4.1 
and 4.4.2. and by adding two sentences to the beginning of sections 
4.3.1, 4.3.2, 4.3.3, and 4.4.3 to read as follows:

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  * * *
(Eq. F-11)

Where:
* * * * *
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.
* * * * *
    4.2  * * *
    4.3  * * *
    4.3.1  On or after January 1, 1996, use the missing data 
provisions of Sec. 75.35 and do not use the provisions of this 
section. Prior to January 1, 1996, use either the provisions of this 
section or the provisions of Sec. 75.35. * * *
    4.3.2  On or after January 1, 1996, use the missing data 
provisions of Sec. 75.35 and do not use the provisions of this 
section. Prior to January 1, 1996, use either the provisions of this 
section or the provisions of Sec. 75.35. * * *
    4.3.3  On or after January 1, 1996, use the missing data 
provisions of Sec. 75.35 and do not use the provisions of this 
section. Prior to January 1, 1996, use either the provisions of this 
section or the provisions of Sec. 75.35. * * *
    4.4  For an affected unit, when the owner or operator is 
continuously monitoring O2 concentration (in percent by volume) 
of flue gases using an O2 monitor, use the equations and 
procedures in section 4.4.1 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).

[[Page 26555]]

[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

(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.
    4.4.3  On or after January 1, 1996, use the missing data 
provisions of Sec. 75.35 and do not use the provisions of this 
section. Prior to January 1, 1996, either use the provisions of 
Sec. 75.35 or use the provisions of this section. * * *
* * * * *
    72. Appendix F to part 75, section 5 is amended by revising section 
5.1 and by revising the definition of the variable ``%CO2w'' in 
Equation F-15 in section 5.2.1, by revising the definition of the 
variable ``%CO2d'' in Equation F-16 in section 5.2.2, by revising 
the definition of the variable ``%O2w'' in Equation F-17 in 
section 5.2.3, and by revising the definition of the variable 
``%O2d'' in Equation F-18 in section 5.2.4, by revising seciton 
5.5.1, by adding two sentences to the beginning of sections 5.3, and 
5.4; by revising section 5.5; by revising section 5.5.2; by revising 
section 5.5.3.1; by revising section 5.5.3.2;by revising section 
5.5.3.3; and by adding new sections 5.5.4, 5.5.5, 5.5.6, and 5.5.7 to 
read as follows:

5. Procedures for Heat Input

* * * * *
    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  * * *
    5.2.1  * * *
(Eq. F-15)

Where:

%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  * * *
(Eq. F-16)

Where:

%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.
* * * * *
    5.2.3  * * *
(Eq. F-17)
Where:

%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.
* * * * *
    5.2.4  * * *
(Eq. F-18)

Where:
%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  On or after January 1, 1996, use the missing data 
provisions of Sec. 75.36 and do not use the provisions of this 
section. Prior to January 1, 1996, use either the missing data 
provisions of this section or the provisions of Sec. 75.36. * * *
    5.4 On or after January 1, 1996, use the missing data provisions 
of Sec. 75.36 and do not use the provisions of this section. Prior 
to January 1, 1996, use either the missing data provisions of this 
section or the provisions of Sec. 75.36. * * *
    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)
[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  * * *
    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 [[Page 26556]] 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.
* * * * *
    73. Appendix F to part 75, section 6 is amended by revising the 
definitions for Equation F-22 to read as follows:

6. Procedure for Converting Volumetric Flow to STP

* * * * *
(Eq. F-22)

Where:

FSTP=Flue gas volumetric flow rate at standard temperature and 
pressure, scfh.
FActual=Flue gas volumetric flow rate at actual temperature and 
pressure, acfh.
TStd=Standard temperature=528  deg.R.
TStack=Flue gas temperature at flow monitor location,  deg.R, 
where  deg.R=460+ deg.F.
PStack=The absolute flue gas pressure=barometric pressure at 
the flow monitor location + flue gas static pressure, inches of 
mercury.
PStd=Standard pressure=29.92 inches of mercury.

    74. Appendix F to part 75 is amended by reserving section 7:
    7. [Reserved]
* * * * *

Appendix G to Part 75--Determination of CO2 Emissions

    75. Appendix G to part 75, section 2 is amended by revising 
sections 2.1, 2.2 and 2.3 to read as follows:
* * * * *

2. Procedures for Estimating CO2 Emissions From Combustion

* * * * *
    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 26557]]

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.
* * * * *
    2.3  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.
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.
* * * * *
    76. Appendix G to part 75, section 3 is amended by revising the 
introductory paragraph; by revising section 3.1.2 before the equation 
and the definition of the variable ``WS02''; and by adding 
Equation G-7 and definitions to section
3.1.2 to read as follows:

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  * * *
    3.1.1  * * *
    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).
(Eq. G-6)
where:
* * * * *
WSO2=Sulfur dioxide removed, lb/day, as calculated below using 
Eq. G-7.
* * * * *
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.
* * * * *

Appendix J to Part 75--Compliance Dates for Revised Recordkeeping 
Requirements and Missing Data Procedures

    77. Appendix J to part 75 is added to read as follows:

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 [[Page 26558]] 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.

[FR Doc. 95-11498 Filed 5-10-95; 3:40 pm]
BILLING CODE 6560-50-P