[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 SO