[Federal Register Volume 72, Number 113 (Wednesday, June 13, 2007)]
[Rules and Regulations]
[Pages 32710-32768]
From the Federal Register Online via the Government Publishing Office [www.gpo.gov]
[FR Doc No: E7-7673]
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Part II
Environmental Protection Agency
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40 CFR Part 60
Amendments to New Source Performance Standards (NSPS) for Electric
Utility Steam Generating Units and Industrial-Commercial-Institutional
Steam Generating Units; Final Rule
Federal Register / Vol. 72, No. 113 / Wednesday, June 13, 2007 /
Rules and Regulations
[[Page 32710]]
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ENVIRONMENTAL PROTECTION AGENCY
40 CFR Part 60
[EPA-HQ-OAR-2005-0031; FRL-8302-3]
RIN 2060-AN97
Standards of Performance for Fossil-Fuel-Fired Steam Generators
for Which Construction Is Commenced After August 17, 1971; Standards of
Performance for Electric Utility Steam Generating Units for Which
Construction Is Commenced After September 18, 1978; Standards of
Performance for Industrial-Commercial-Institutional Steam Generating
Units; and Standards of Performance for Small Industrial-Commercial-
Institutional Steam Generating Units
AGENCY: Environmental Protection Agency (EPA).
ACTION: Final reconsideration.
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SUMMARY: EPA is amending the new source performance standards (NSPS)
for electric utility steam generating units and industrial-commercial-
institutional steam generating units. These amendments to the
regulations are to add compliance alternatives for owners and operators
of certain affected sources, revise certain recordkeeping and reporting
requirements, correct technical and editorial errors, and update the
grammatical style of the four subparts to be more consistent across all
of the subparts.
DATES: This rule is effective on June 13, 2007. The incorporation by
reference of certain publications listed in these rules is approved by
the Director of the Federal Register as of June 13, 2007.
ADDRESSES: EPA has established a docket for this action under Docket ID
No. EPA-HQ-OAR-2005-0031. All documents in the docket are listed in the
Federal Docket Management System index at http://www.regulations.gov.
Although listed in the index, some information is not publicly
available, e.g., confidential business information or other information
whose disclosure is restricted by statute. Certain other material, such
as copyrighted material, is not placed on the Internet and will be
publicly available only in hard copy form. Publicly available docket
materials are available either electronically through
www.regulations.gov or in hard copy at the EPA Docket Center, Public
Reading Room, EPA West, Room 3334, 1301 Constitution Ave., NW.,
Washington, DC. The Public Reading Room is open from 8:30 a.m. to 4:30
p.m., Monday through Friday, excluding legal holidays. The telephone
number for the Public Reading Room is (202) 566-1744, and the telephone
number for the Air Docket is (202) 566-1742.
FOR FURTHER INFORMATION CONTACT: Mr. Christian Fellner, Energy
Strategies Group, Sector Policies and Programs Division (D243-01), U.S.
EPA, Research Triangle Park, NC 27711, telephone number (919) 541-4003,
facsimile number (919) 541-5450, electronic mail (e-mail) address:
[email protected].
SUPPLEMENTARY INFORMATION:
Outline. The information presented in this preamble is organized as
follows:
I. General Information
A. Does this action apply to me?
B. Where can I get a copy of this document?
C. Judicial Review
II. Background Information
III. Final Amendments and Changes Since Proposal
IV. Statutory and Executive Order Reviews
A. Executive Order 12866: Regulatory Planning and Review
B. Paperwork Reduction Act
C. Regulatory Flexibility Act
D. Unfunded Mandates Reform Act
E. Executive Order 13132: Federalism
F. Executive Order 13175: Consultation and Coordination With
Indian Tribal Governments
G. Executive Order 13045: Protection of Children From
Environmental Health and Safety Risks
H. Executive Order 13211: Actions Concerning Regulations That
Significantly Affect Energy Supply, Distribution, or Use
I. National Technology Transfer Advancement Act
J. Congressional Review Act
I. General Information
A. Does this action apply to me?
The regulated categories and entities potentially affected by this
final action include, but are not limited to, the following:
------------------------------------------------------------------------
Examples of
Category NAICS code \1\ potentially regulated
entities
------------------------------------------------------------------------
Industry...................... 221112 Fossil fuel-fired
electric utility
steam generating
units.
Federal Government............ 22112 Fossil fuel-fired
electric utility
steam generating
units owned by the
Federal Government.
State/local/tribal government. 22112 Fossil fuel-fired
electric utility
steam generating
units owned by
municipalities.
921150 Fossil fuel-fired
electric steam
generating units in
Indian Country.
Any industrial, commercial, or 211 Extractors of crude
institutional facility using petroleum and natural
a steam generating unit as gas.
defined in 60.40b or 60.40c.
321 Manufacturers of
lumber and wood
products.
322 Pulp and paper mills.
325 Chemical
manufacturers.
324 Petroleum refiners and
manufacturers of coal
products.
316, 326, 339 Manufacturers of
rubber and
miscellaneous plastic
products.
331 Steel works, blast
furnaces.
332 Electroplating,
plating, polishing,
anodizing, and
coloring.
336 Manufacturers of motor
vehicle parts and
accessories.
221 Electric, gas, and
sanitary services.
622 Health services.
611 Educational Services.
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\1\ North American Industry Classification System (NAICS) code.
This table is not intended to be exhaustive, but rather provides a
guide for readers regarding entities likely to be regulated by this
action. To determine whether your facility is regulated by this action,
you should examine the applicability criteria in Sec. 60.40a, 60.40b,
or 60.40c of 40 CFR part 60. If you have any questions regarding the
applicability of this action to a particular entity, consult either the
air permit authority for the entity or your
[[Page 32711]]
EPA regional representative as listed in 40 CFR 63.13 of subpart A
(General Provisions).
B. Where can I get a copy of this document?
In addition to being available in the docket, an electronic copy of
this final action will also be available on the Worldwide Web (WWW)
through the Technology Transfer Network (TTN). Following signature, a
copy of this final action will be posted on the TTN's policy and
guidance page for newly proposed or promulgated rules at the following
address: http://www.epa.gov/ttn/oarpg/. The TTN provides information
and technology exchange in various areas of air pollution control.
C. Judicial Review
Under section 307(b)(1) of the Clean Air Act (CAA), judicial review
of these final rules is available only by filing a petition for review
in the U.S. Court of Appeals for the District of Columbia Circuit by
August 13, 2007. Under section 307(d)(7)(B) of the CAA, only an
objection to these final rules that was raised with reasonable
specificity during the period for public comment can be raised during
judicial review. Moreover, under section 307(b)(2) of the CAA, the
requirements established by these final rules may not be challenged
separately in any civil or criminal proceedings brought by EPA to
enforce these requirements.
II. Background Information
In response to petitions for reconsideration filed by the Utility
Air Regulatory Group and the Council of Industrial Boiler Owners of the
amendments to the new source performance standards for steam generating
units that EPA promulgated on February 27, 2006 (71 FR 9866), EPA
proposed revised amendments to address issues for which the petitioners
requested reconsideration (see docket entries EPA-HQ-OAR-2005-0031-0224
and EPA-HQ-OAR-2005-0031-0225). EPA proposed on February 9, 2007, (72
FR 6320) to amend 40 CFR part 60, subparts D, Da, Db, and Dc to clarify
the intent for applying and implementing specific rule requirements,
provide additional compliance alternatives, and to correct
unintentional technical omissions and editorial errors. In addition,
EPA proposed to republish 40 CFR 60.17 (Incorporations by reference)
and subparts D, Da, Db, and Dc in their entirety for the purpose of
revising the wording and writing style to be more consistent across all
the NSPS subparts applicable to steam generating units.
A 30-day comment period (February 9, 2007 to March 12, 2007) was
provided to accept comments on the proposed rule. An opportunity for a
public hearing was provided to allow any interested persons to present
oral comments on the proposed rule. However, EPA did not receive a
request for a formal public hearing, so a public hearing was not held.
EPA did receive a request for a 15-day extension to the comment period.
EPA granted an extension of the public comment period to March 26, 2007
(72 FR 9903, March 6, 2007). We received comments on the proposed
amendments from 20 commenters during the comment period.
III. Final Amendments and Changes Since Proposal
We are amending 40 CFR part 60, subparts D, Da, Db, and Dc to add
compliance alternatives for owners and operators of certain affected
sources, revise certain recordkeeping and reporting requirements,
correct technical and editorial errors, and update the grammatical
style of the four subparts to be more consistent across all of the
subparts. This action promulgates the proposed regulatory language for
the amendments except for those significant provisions, as noted below,
for which modifications were made to the regulatory language for the
final amendments in response to specific public comments. EPA did not
receive negative comments on the conforming changes to the regulatory
text and is, therefore, finalizing all those changes.
The final amendments promulgated by this action reflect EPA's
consideration of the comments received on the proposal. EPA's responses
to the substantive public comments on the proposal are presented in a
comment summary and response document available in Docket ID No. EPA-
HQ-OAR-2005-0031.
The requirements in subpart Da for demonstrating continuous
compliance with the particulate matter (PM) emission limits for
affected electric utility steam generating units that commence
construction, reconstruction, or modification after February 28, 2005,
have been revised since proposal in response to comments. EPA is
retaining the provision, established in the February 27, 2006 final
rule, allowing the optional use of PM continuous emission monitoring
systems (CEMS) to steam generating units for demonstration of
compliance with rule requirements related to controlling PM emissions.
Owners and operators choosing to install and properly operate PM CEMS
must demonstrate compliance with the applicable PM emission limit on a
daily basis and are not required to install a continuous opacity
monitoring system (COMS) or to monitor PM control device performance.
We recognize that experience using PM CEMS at electric utility
power plants in the United States is limited, and not all affected
owners and operators will choose to use PM CEMS. Therefore, the final
amendments allow owners and operators of affected electric utility
steam generating units constructed, reconstructed, or modified after
February 28, 2005, to demonstrate compliance with the PM emissions
limit using periodic PM emissions performance testing and continuous
monitoring of the PM control device performance using one of two
alternatives. The first monitoring alternative is for an owner or
operator of an affected source to monitor PM control device performance
based on the opacity level measured during the stack performance test
conducted to demonstrate compliance with the applicable PM emissions
limit. The second alternative available to owners and operators depends
on the type of PM control device used for the electric utility steam
generating unit. The owner or operator of an affected source that uses
an electrostatic precipitator (ESP) can elect to monitor performance of
the control device using an ESP predictive emissions model. An owner or
operator of an affected source that uses a fabric filter can elect to
monitor control device performance using a bag leak detection system.
One significant change from the proposal is that owners or operators of
affected source that use parametric monitoring of PM emissions will
have a grace period to bring the monitoring parameters back into the
range established during the most recent PM emissions performance test
prior to the requirement to conduct a new PM emissions performance
test. The grace period does not apply to the 6-minute opacity standard
and owners and operators of affected sources must continue to report
excess 6-minute opacity measurements.
EPA has finalized several other alternatives to provide owners and
operators of affected electric utility steam generating units
additional flexibility in complying with the NSPS. EPA has finalized
the optional use of Part 75 NOX and SO2 CEMS
calibration procedures to satisfy Part 60 requirements as proposed, the
amendments to Sec. 60.13 providing a standard methodology for
validating partial operating hours, and the amendments to Appendix B of
Part 60 allowing the calibration drift test be
[[Page 32712]]
conducted over 7 consecutive operating days instead of 7 consecutive
calendar days and the relative accuracy test audit flexibility (as
described in docket entry EPA-HQ-OAR-2005-0031-0234). In addition, EPA
has finalized the option for steam generating units subject to subpart
D allowing affected owners and operators to choose as an alternative to
complying with the applicable NOX and SO2
emission limits in the rule to comply with the 30-day average
NOX and SO2 standards for modified sources in
subparts Da and Db, as applicable to the affected source.
For industrial/commercial/institutional steam generating units
subject to subpart Db and burning coke oven gas (COG), we have expanded
the applicability of the 30-day annual exemption from the
SO2 emissions limit to all units subject to subpart Db that
burn COG. The amendments to subpart Db promulgated in February 27,
2006, added this flexibility for those steam generating units
constructed, reconstructed, or modified after February 28, 2005, to
account for byproduct plant maintenance. Based on comments we received,
the amendments promulgated by this action provide the same compliance
flexibility to the owner or operator of any COG-fired steam generating
unit subject to subpart Db.
The final amendments add to subparts D, Da, Db, and Dc monitoring
alternatives to existing requirements to use COMS for owners and
operators of steam generating units burning gaseous fuels or low sulfur
fuel oils. Owners and operators of electric utility steam generating
units subject to subpart D or Da may elect to use a carbon monoxide
(CO) CEMS in place of the COMS. Owners and operators of industrial/
commercial/institutional steam generating units subject to subpart Db
or Dc may elect to either use a CO CEMS or to operate according to a
site-specific monitoring plan in place of using a COMS.
Finally, minor revisions to the proposed regulatory language were
made to clarify specific provisions or to correct unintentional
technical omissions and terminology, typographical, printing, and
grammatical errors that were identified in the proposed rule. These
changes include revising appropriate definitions and requirements in
subpart Da to clarify the applicability and implementation of the
subpart Da provisions to integrated coal gasification combined cycle
electric utility power plants.
IV. Statutory and Executive Order Reviews
A. Executive Order 12866: Regulatory Planning and Review
This action is not a ``significant regulatory action'' under the
terms of Executive Order 12866 (58 FR 51735, October 4, 1993) and is,
therefore, not subject to review under the Executive Order. EPA has
concluded that the amendments EPA is promulgating will not change the
costs or benefits of the rule.
B. Paperwork Reduction Act
This action does not impose any new information collection burden
under the provisions of the Paperwork Reduction Act, 44 U.S.C. 3501 et
seq. The final amendments result in no changes to the information
collection requirements of the existing standards of performance and
would have no impact on the information collection estimate of
projected cost and hour burden made and approved by the Office of
Management and Budget (OMB) during the development of the existing
standards of performance. Therefore, the information collection
requests have not been amended. OMB has previously approved the
information collection requirements contained in the existing standards
of performance (40 CFR part 60, subparts D, Da, Db, and Dc) under the
provisions of the Paperwork Reduction Act, 44 U.S.C. 3501 et seq., at
the time the standards were promulgated on June 11, 1979 (40 CFR part
60, subpart Da, 44 FR 33580), November 25, 1986 (40 CFR part 60,
subpart Db, 51 FR 42768), and September 12, 1990 (40 CFR part 60,
subpart Dc, 55 FR 37674). OMB assigned OMB control numbers 2060-0023
(ICR 1053.08) for 40 CFR part 60, subpart Da; 2060-0072 (ICR 1088.11)
for 40 CFR part 60, subpart Db; 2060-0202 (ICR 1564.06) for 40 CFR part
60, subpart Dc. Copies of the information collection request
document(s) may be obtained from Susan Auby, Collection Strategies
Division, U.S. EPA (2822T), 1200 Pennsylvania Ave., NW., Washington, DC
20460, by e-mail at [email protected], or by calling (202) 566-1672.
Burden means the total time, effort, or financial resources
expended by persons to generate, maintain, retain, or disclose or
provide information to or for a Federal agency. This includes the time
needed to review instructions; develop, acquire, install, and utilize
technology and systems for the purposes of collecting, validating, and
verifying information, processing and maintaining information, and
disclosing and providing information; adjust the existing ways to
comply with any previously applicable instructions and requirements;
train personnel to be able to respond to a collection of information;
search data sources; complete and review the collection of information;
and transmit or otherwise disclose the information.
An agency may not conduct or sponsor, and a person is not required
to respond to a collection of information unless it displays a
currently valid OMB control number. OMB control numbers for EPA's
regulations in 40 CFR are listed in 40 CFR part 9.
C. Regulatory Flexibility Act
The Regulatory Flexibility Act generally requires an agency to
prepare a regulatory flexibility analysis of any rule subject to notice
and comment rulemaking requirements under the Administrative Procedure
Act or any other statute unless the agency certifies that the rule will
not have a significant economic impact on a substantial number of small
entities. Small entities include small businesses, small organizations,
and small governmental jurisdictions.
For purposes of assessing the impacts of the final amendments on
small entities, small entity is defined as: (1) A small business as
defined by the Small Business Administration's regulations at 13 CFR
121.201; (2) a small governmental jurisdiction that is a government of
a city, county, town, school district or special district with a
population of less than 50,000; and (3) a small organization that is
any not-for-profit enterprise which is independently owned and operated
and is not dominant in its field.
After considering the economic impacts of this final rule on small
entities, I certify that this action will not have a significant
economic impact on a substantial number of small entities.
Although this action will not have a significant economic impact on
a substantial number of small entities, EPA nonetheless has tried to
reduce the impact of this rule on small entities. EPA is reducing the
fuel usage recordkeeping requirement for subpart Dc facilities. In
addition, EPA is minimizing the continuous opacity monitoring
requirements for certain oil-fired facilities. EPA has, therefore,
concluded that this action will relieve regulatory burden for the
majority of affected small entities. EPA continues to be interested in
the potential impacts of the rule on small entities and welcomes
comments on issues related to such impacts.
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D. Unfunded Mandates Reform Act
Title II of the Unfunded Mandates Reform Act of 1995 (UMRA), Public
Law 104-4, establishes requirements for Federal agencies to assess the
effects of their regulatory actions on State, local, and tribal
governments and the private sector. Under section 202 of the UMRA, EPA
generally must prepare a written statement, including a cost-benefit
analysis, for proposed and final rules with ``Federal mandates'' that
may result in expenditures to State, local, and tribal governments, in
the aggregate, or to the private sector, of $100 million or more in any
one year. Before promulgating an EPA rule for which a written statement
is needed, section 205 of the UMRA generally requires EPA to identify
and consider a reasonable number of regulatory alternatives and adopt
the least costly, most cost-effective or least burdensome alternative
that achieves the objectives of the rule. The provisions of section 205
do not apply when they are inconsistent with applicable law. Moreover,
section 205 allows EPA to adopt an alternative other than the least
costly, most cost-effective or least burdensome alternative if the
Administrator publishes with the final rule an explanation why that
alternative was not adopted. Before EPA establishes any regulatory
requirements that may significantly or uniquely affect small
governments, including tribal governments, it must have developed under
section 203 of the UMRA a small government agency plan. The plan must
provide for notifying potentially affected small governments, enabling
officials of affected small governments to have meaningful and timely
input in the development of EPA regulatory proposals with significant
Federal intergovernmental mandates, and informing, educating, and
advising small governments on compliance with the regulatory
requirements.
EPA has determined that the final amendments will contain no
Federal mandates that may result in expenditures of $100 million or
more for State, local, and tribal governments, in the aggregate, or the
private sector in any 1 year. Thus, the final amendments are not
subject to the requirements of section 202 and 205 of the UMRA. In
addition, EPA has determined that the final amendments contain no
regulatory requirements that might significantly or uniquely affect
small governments because the burden is small and the regulation does
not unfairly apply to small governments. Therefore, the final
amendments are not subject to the requirements of section 203 of the
UMRA.
E. Executive Order 13132: Federalism
Executive Order 13132, entitled ``Federalism'' (64 FR 43255, August
10, 1999), requires EPA to develop an accountable process to ensure
``meaningful and timely input by State and local officials in the
development of regulatory policies that have federalism implications.''
``Policies that have federalism implications'' is defined in the
Executive Order to include regulations that have ``substantial direct
effects on the States, on the relationship between the national
government and the States, or on the distribution of power and
responsibilities among the various levels of government.''
The final amendments do not have federalism implications. They will
not have substantial direct effects on the States, on the relationship
between the national government and the States, or on the distribution
of power and responsibilities among the various levels of government,
as specified in Executive Order 13132. The final amendments will not
impose substantial direct compliance costs on State or local
governments; it will not preempt State law. Thus, Executive Order 13132
does not apply to the final amendments.
F. Executive Order 13175: Consultation and Coordination With Indian
Tribal Governments
Executive Order 13175, entitled ``Consultation and Coordination
with Indian Tribal Governments'' (65 FR 67249, November 9, 2000),
requires EPA to develop an accountable process to ensure ``meaningful
and timely input by tribal officials in the development of regulatory
policies that have tribal implications.'' The final amendments do not
have tribal implications, as specified in Executive Order 13175. While
utility steam generating units are located on tribal lands EPA is not
aware of any that are tribally owned. To the extend that institutional
steam generating units are tribally owned the final amendments will not
have substantial direct effects on tribal governments, on the
relationship between the Federal government and Indian tribes, or on
the distribution of power and responsibilities between the Federal
government and Indian tribes. Thus, Executive Order 13175 does not
apply to the final amendments.
G. Executive Order 13045: Protection of Children From Environmental
Health and Safety Risks
Executive Order 13045 (62 FR 19885, April 23, 1997) applies to any
rule that: (1) Is determined to be ``economically significant'' as
defined under Executive Order 12866, and (2) concerns an environmental
health or safety risk that EPA has reason to believe may have a
disproportionate effect on children. If the regulatory action meets
both criteria, the Agency must evaluate the environmental health or
safety effects of the planned rule on children, and explain why the
planned regulation is preferable to other potentially effective and
reasonably feasible alternatives considered by the Agency.
This action is not subject to the Executive Order because it is not
economically significant as defined under Executive Order 12866, and
because EPA interprets Executive Order 13045 as applying only to those
regulatory actions that are based on health or safety risks, such that
the analysis required under section 5-501 of the Order has the
potential to influence the regulation. The final amendments are based
on technology performance and not on health or safety risks and,
therefore, are not subject to Executive Order 13045.
H. Executive Order 13211: Actions Concerning Regulations That
Significantly Affect Energy Supply, Distribution, or Use
The final amendments are not a ``significant energy action'': As
defined in Executive Order 13211, ``Actions Concerning Regulations That
Significantly Affect Energy Supply, Distribution, or Use'' (66 FR
28355, May 22, 2001) because it is not likely to have a significant
adverse effect on the supply, distribution, or use of energy because it
only clarifies our intent and corrects errors in the existing rule.
Further, we have concluded that the final amendments are not likely to
have any adverse energy effects.
I. National Technology Transfer Advancement Act
Section 12(d) of the National Technology Transfer and Advancement
Act of 1995 (NTTAA), Public Law 104-113, Section 12(d)(15 U.S.C. 272
note) directs us to use voluntary consensus standards in our regulatory
activities unless to do so would be inconsistent with applicable law or
otherwise impractical. Voluntary consensus standards are technical
standards (e.g., material specifications, test methods, sampling
procedures, business practices) developed or adopted by one or more
voluntary consensus bodies. The NTTAA directs us to provide Congress,
through OMB, explanations when we decide not use available and
applicable voluntary consensus standards.
[[Page 32714]]
This action does not involve any new technical standards or the
incorporation by reference of existing technical standards. Therefore,
the consideration of voluntary consensus standards is not relevant to
this action.
J. Congressional Review Act
The Congressional Review Act, 5 U.S.C. 801, et seq., as added by
the Small Business Regulatory Enforcement Fairness Act of 1996,
generally provides that before a rule may take effect, the agency
promulgating the rule must submit a rule report, which includes a copy
of the rule, to each House of Congress and to the Comptroller General
of the United States. EPA will submit a report containing these final
amendments and other required information to the U.S. Senate, the U.S.
House of Representatives, and the Comptroller General of the United
States prior to publication of the final rules in the Federal Register.
A major rule cannot take effect until 60 days after it is published in
the Federal Register. This action is not a ``major rule'' as defined by
5 U.S.C. 804(2). These final amendments will be effective on June 13,
2007.
List of Subjects in 40 CFR Part 60
Environmental protection, Administrative practice and procedure,
Air pollution control, Incorporation by reference, Intergovernmental
relations, Reporting and recordkeeping requirements.
Dated: April 13, 2007.
Stephen L. Johnson,
Administrator.
0
For the reasons stated in the preamble, title 40, chapter I, part 60,
of the Code of the Federal Regulations is amended as follows:
PART 60--[AMENDED]
0
1. The authority citation for part 60 continues to read as follows:
Authority: 42 U.S.C. 7401, et seq.
Subpart A--[Amended]
0
2. Section 60.13 is amended by revising paragraph (h) to read as
follows:
Sec. 60.13 Monitoring requirements.
* * * * *
(h)(1) Owners or operators of all continuous monitoring systems for
measurement of opacity shall reduce all data to 6-minute averages and
for continuous monitoring systems other than opacity to 1-hour averages
for time periods as defined in Sec. 60.2. Six-minute opacity averages
shall be calculated from 36 or more data points equally spaced over
each 6-minute period.
(2) For continuous monitoring systems other than opacity, 1-hour
averages shall be computed as follows, except that the provisions
pertaining to the validation of partial operating hours are only
applicable for affected facilities that are required by the applicable
subpart to include partial hours in the emission calculations:
(i) Except as provided under paragraph (h)(2)(iii) of this section,
for a full operating hour (any clock hour with 60 minutes of unit
operation), at least four valid data points are required to calculate
the hourly average, i.e., one data point in each of the 15-minute
quadrants of the hour.
(ii) Except as provided under paragraph (h)(2)(iii) of this
section, for a partial operating hour (any clock hour with less than 60
minutes of unit operation), at least one valid data point in each 15-
minute quadrant of the hour in which the unit operates is required to
calculate the hourly average.
(iii) For any operating hour in which required maintenance or
quality-assurance activities are performed:
(A) If the unit operates in two or more quadrants of the hour, a
minimum of two valid data points, separated by at least 15 minutes, is
required to calculate the hourly average; or
(B) If the unit operates in only one quadrant of the hour, at least
one valid data point is required to calculate the hourly average.
(iv) If a daily calibration error check is failed during any
operating hour, all data for that hour shall be invalidated, unless a
subsequent calibration error test is passed in the same hour and the
requirements of paragraph (h)(2)(iii) of this section are met, based
solely on valid data recorded after the successful calibration.
(v) For each full or partial operating hour, all valid data points
shall be used to calculate the hourly average.
(vi) Except as provided under paragraph (h)(2)(vii) of this
section, data recorded during periods of continuous monitoring system
breakdown, repair, calibration checks, and zero and span adjustments
shall not be included in the data averages computed under this
paragraph.
(vii) Owners and operators complying with the requirements of Sec.
60.7(f)(1) or (2) must include any data recorded during periods of
monitor breakdown or malfunction in the data averages.
(viii) When specified in an applicable subpart, hourly averages for
certain partial operating hours shall not be computed or included in
the emission averages (e.g. hours with < 30 minutes of unit operation
under Sec. 60.47b(d)).
(ix) Either arithmetic or integrated averaging of all data may be
used to calculate the hourly averages. The data may be recorded in
reduced or nonreduced form (e.g., ppm pollutant and percent
O2 or ng/J of pollutant).
(3) All excess emissions shall be converted into units of the
standard using the applicable conversion procedures specified in the
applicable subpart. After conversion into units of the standard, the
data may be rounded to the same number of significant digits used in
the applicable subpart to specify the emission limit.
* * * * *
Sec. 60.17 [Amended]
0
3. Section 60.17 is amended by revising paragraphs (a) and (h)(2) to
read as follows:
* * * * *
(a) The following materials are available for purchase from at
least one of the following addresses: American Society for Testing and
Materials (ASTM), 100 Barr Harbor Drive, Post Office Box C700, West
Conshohocken, PA 19428-2959; or ProQuest, 300 North Zeeb Road, Ann
Arbor, MI 48106.
(1) ASTM A99-76, 82 (Reapproved 1987), Standard Specification for
Ferromanganese, incorporation by reference (IBR) approved for Sec.
60.261.
(2) ASTM A100-69, 74, 93, Standard Specification for Ferrosilicon,
IBR approved for Sec. 60.261.
(3) ASTM A101-73, 93, Standard Specification for Ferrochromium, IBR
approved for Sec. 60.261.
(4) ASTM A482-76, 93, Standard Specification for
Ferrochromesilicon, IBR approved for Sec. 60.261.
(5) ASTM A483-64, 74 (Reapproved 1988), Standard Specification for
Silicomanganese, IBR approved for Sec. 60.261.
(6) ASTM A495-76, 94, Standard Specification for Calcium-Silicon
and Calcium Manganese-Silicon, IBR approved for Sec. 60.261.
(7) ASTM D86-78, 82, 90, 93, 95, 96, Distillation of Petroleum
Products, IBR approved for Sec. Sec. 60.562-2(d), 60.593(d), and
60.633(h).
(8) ASTM D129-64, 78, 95, 00, Standard Test Method for Sulfur in
Petroleum Products (General Bomb Method), IBR approved for Sec. Sec.
60.106(j)(2), 60.335(b)(10)(i), and Appendix A: Method 19, 12.5.2.2.3.
(9) ASTM D129-00 (Reapproved 2005), Standard Test Method for Sulfur
in Petroleum Products (General Bomb Method), IBR approved for Sec.
60.4415(a)(1)(i).
[[Page 32715]]
(10) ASTM D240-76, 92, Standard Test Method for Heat of Combustion
of Liquid Hydrocarbon Fuels by Bomb Calorimeter, IBR approved for
Sec. Sec. 60.46(c), 60.296(b), and Appendix A: Method 19, Section
12.5.2.2.3.
(11) ASTM D270-65, 75, Standard Method of Sampling Petroleum and
Petroleum Products, IBR approved for Appendix A: Method 19, Section
12.5.2.2.1.
(12) ASTM D323-82, 94, Test Method for Vapor Pressure of Petroleum
Products (Reid Method), IBR approved for Sec. Sec. 60.111(l),
60.111a(g), 60.111b(g), and 60.116b(f)(2)(ii).
(13) ASTM D388-77, 90, 91, 95, 98a, 99 (Reapproved 2004) [egr]\1\,
Standard Specification for Classification of Coals by Rank, IBR
approved for Sec. Sec. 60.24(h)(8), 60.41 of subpart D of this part,
60.45(f)(4)(i), 60.45(f)(4)(ii), 60.45(f)(4)(vi), 60.41Da of subpart Da
of this part, 60.41b of subpart Db of this part, 60.41c of subpart Dc
of this part, and 60.4102.
(14) ASTM D388-77, 90, 91, 95, 98a, Standard Specification for
Classification of Coals by Rank, IBR approved for Sec. Sec. 60.251(b)
and (c) of subpart Y of this part.
(15) ASTM D396-78, 89, 90, 92, 96, 98, Standard Specification for
Fuel Oils, IBR approved for Sec. Sec. 60.41b of subpart Db of this
part, 60.41c of subpart Dc of this part, 60.111(b) of subpart K of this
part, and 60.111a(b) of subpart Ka of this part.
(16) ASTM D975-78, 96, 98a, Standard Specification for Diesel Fuel
Oils, IBR approved for Sec. Sec. 60.111(b) of subpart K of this part
and 60.111a(b) of subpart Ka of this part.
(17) ASTM D1072-80, 90 (Reapproved 1994), Standard Test Method for
Total Sulfur in Fuel Gases, IBR approved for Sec. 60.335(b)(10)(ii).
(18) ASTM D1072-90 (Reapproved 1999), Standard Test Method for
Total Sulfur in Fuel Gases, IBR approved for Sec. 60.4415(a)(1)(ii).
(19) ASTM D1137-53, 75, Standard Method for Analysis of Natural
Gases and Related Types of Gaseous Mixtures by the Mass Spectrometer,
IBR approved for Sec. 60.45(f)(5)(i).
(20) ASTM D1193-77, 91, Standard Specification for Reagent Water,
IBR approved for Appendix A: Method 5, Section 7.1.3; Method 5E,
Section 7.2.1; Method 5F, Section 7.2.1; Method 6, Section 7.1.1;
Method 7, Section 7.1.1; Method 7C, Section 7.1.1; Method 7D, Section
7.1.1; Method 10A, Section 7.1.1; Method 11, Section 7.1.3; Method 12,
Section 7.1.3; Method 13A, Section 7.1.2; Method 26, Section 7.1.2;
Method 26A, Section 7.1.2; and Method 29, Section 7.2.2.
(21) ASTM D1266-87, 91, 98, Standard Test Method for Sulfur in
Petroleum Products (Lamp Method), IBR approved for Sec. Sec.
60.106(j)(2) and 60.335(b)(10)(i).
(22) ASTM D1266-98 (Reapproved 2003)e1, Standard Test Method for
Sulfur in Petroleum Products (Lamp Method), IBR approved for Sec.
60.4415(a)(1)(i).
(23) ASTM D1475-60 (Reapproved 1980), 90, Standard Test Method for
Density of Paint, Varnish Lacquer, and Related Products, IBR approved
for Sec. 60.435(d)(1), Appendix A: Method 24, Section 6.1; and Method
24A, Sections 6.5 and 7.1.
(24) ASTM D1552-83, 95, 01, Standard Test Method for Sulfur in
Petroleum Products (High-Temperature Method), IBR approved for
Sec. Sec. 60.106(j)(2), 60.335(b)(10)(i), and Appendix A: Method 19,
Section 12.5.2.2.3.
(25) ASTM D1552-03, Standard Test Method for Sulfur in Petroleum
Products (High-Temperature Method), IBR approved for Sec.
60.4415(a)(1)(i).
(26) ASTM D1826-77, 94, Standard Test Method for Calorific Value of
Gases in Natural Gas Range by Continuous Recording Calorimeter, IBR
approved for Sec. Sec. 60.45(f)(5)(ii), 60.46(c)(2), 60.296(b)(3), and
Appendix A: Method 19, Section 12.3.2.4.
(27) ASTM D1835-87, 91, 97, 03a, Standard Specification for
Liquefied Petroleum (LP) Gases, IBR approved for Sec. Sec. 60.41Da of
subpart Da of this part, 60.41b of subpart Db of this part, and 60.41c
of subpart Dc of this part.
(28) ASTM D1945-64, 76, 91, 96, Standard Method for Analysis of
Natural Gas by Gas Chromatography, IBR approved for Sec.
60.45(f)(5)(i).
(29) ASTM D1946-77, 90 (Reapproved 1994), Standard Method for
Analysis of Reformed Gas by Gas Chromatography, IBR approved for
Sec. Sec. 60.18(f)(3), 60.45(f)(5)(i), 60.564(f)(1), 60.614(e)(2)(ii),
60.614(e)(4), 60.664(e)(2)(ii), 60.664(e)(4), 60.704(d)(2)(ii), and
60.704(d)(4).
(30) ASTM D2013-72, 86, Standard Method of Preparing Coal Samples
for Analysis, IBR approved for Appendix A: Method 19, Section
12.5.2.1.3.
(31) ASTM D2015-77 (Reapproved 1978), 96, Standard Test Method for
Gross Calorific Value of Solid Fuel by the Adiabatic Bomb Calorimeter,
IBR approved for Sec. 60.45(f)(5)(ii), 60.46(c)(2), and Appendix A:
Method 19, Section 12.5.2.1.3.
(32) ASTM D2016-74, 83, Standard Test Methods for Moisture Content
of Wood, IBR approved for Appendix A: Method 28, Section 16.1.1.
(33) ASTM D2234-76, 96, 97b, 98, Standard Methods for Collection of
a Gross Sample of Coal, IBR approved for Appendix A: Method 19, Section
12.5.2.1.1.
(34) ASTM D2369-81, 87, 90, 92, 93, 95, Standard Test Method for
Volatile Content of Coatings, IBR approved for Appendix A: Method 24,
Section 6.2.
(35) ASTM D2382-76, 88, Heat of Combustion of Hydrocarbon Fuels by
Bomb Calorimeter (High-Precision Method), IBR approved for Sec. Sec.
60.18(f)(3), 60.485(g)(6), 60.564(f)(3), 60.614(e)(4), 60.664(e)(4),
and 60.704(d)(4).
(36) ASTM D2504-67, 77, 88 (Reapproved 1993), Noncondensable Gases
in C3 and Lighter Hydrocarbon Products by Gas Chromatography, IBR
approved for Sec. 60.485(g)(5).
(37) ASTM D2584-68 (Reapproved 1985), 94, Standard Test Method for
Ignition Loss of Cured Reinforced Resins, IBR approved for Sec.
60.685(c)(3)(i).
(38) ASTM D2597-94 (Reapproved 1999), Standard Test Method for
Analysis of Demethanized Hydrocarbon Liquid Mixtures Containing
Nitrogen and Carbon Dioxide by Gas Chromatography, IBR approved for
Sec. 60.335(b)(9)(i).
(39) ASTM D2622-87, 94, 98, Standard Test Method for Sulfur in
Petroleum Products by Wavelength Dispersive X-Ray Fluorescence
Spectrometry, IBR approved for Sec. Sec. 60.106(j)(2) and
60.335(b)(10)(i).
(40) ASTM D2622-05, Standard Test Method for Sulfur in Petroleum
Products by Wavelength Dispersive X-Ray Fluorescence Spectrometry, IBR
approved for Sec. 60.4415(a)(1)(i).
(41) ASTM D2879-83, 96, 97, Test Method for Vapor Pressure-
Temperature Relationship and Initial Decomposition Temperature of
Liquids by Isoteniscope, IBR approved for Sec. Sec. 60.111b(f)(3),
60.116b(e)(3)(ii), 60.116b(f)(2)(i), and 60.485(e)(1).
(42) ASTM D2880-78, 96, Standard Specification for Gas Turbine Fuel
Oils, IBR approved for Sec. Sec. 60.111(b), 60.111a(b), and 60.335(d).
(43) ASTM D2908-74, 91, Standard Practice for Measuring Volatile
Organic Matter in Water by Aqueous-Injection Gas Chromatography, IBR
approved for Sec. 60.564(j).
(44) ASTM D2986-71, 78, 95a, Standard Method for Evaluation of Air,
Assay Media by the Monodisperse DOP (Dioctyl Phthalate) Smoke Test, IBR
approved for Appendix A: Method 5, Section 7.1.1; Method 12, Section
7.1.1; and Method 13A, Section 7.1.1.2.
(45) ASTM D3173-73, 87, Standard Test Method for Moisture in the
[[Page 32716]]
Analysis Sample of Coal and Coke, IBR approved for Appendix A: Method
19, Section 12.5.2.1.3.
(46) ASTM D3176-74, 89, Standard Method for Ultimate Analysis of
Coal and Coke, IBR approved for Sec. 60.45(f)(5)(i) and Appendix A:
Method 19, Section 12.3.2.3.
(47) ASTM D3177-75, 89, Standard Test Method for Total Sulfur in
the Analysis Sample of Coal and Coke, IBR approved for Appendix A:
Method 19, Section 12.5.2.1.3.
(48) ASTM D3178-73 (Reapproved 1979), 89, Standard Test Methods for
Carbon and Hydrogen in the Analysis Sample of Coal and Coke, IBR
approved for Sec. 60.45(f)(5)(i).
(49) ASTM D3246-81, 92, 96, Standard Test Method for Sulfur in
Petroleum Gas by Oxidative Microcoulometry, IBR approved for Sec.
60.335(b)(10)(ii).
(50) ASTM D3246-05, Standard Test Method for Sulfur in Petroleum
Gas by Oxidative Microcoulometry, IBR approved for Sec.
60.4415(a)(1)(ii).
(51) ASTM D3270-73T, 80, 91, 95, Standard Test Methods for Analysis
for Fluoride Content of the Atmosphere and Plant Tissues (Semiautomated
Method), IBR approved for Appendix A: Method 13A, Section 16.1.
(52) ASTM D3286-85, 96, Standard Test Method for Gross Calorific
Value of Coal and Coke by the Isoperibol Bomb Calorimeter, IBR approved
for Appendix A: Method 19, Section 12.5.2.1.3.
(53) ASTM D3370-76, 95a, Standard Practices for Sampling Water, IBR
approved for Sec. 60.564(j).
(54) ASTM D3792-79, 91, Standard Test Method for Water Content of
Water-Reducible Paints by Direct Injection into a Gas Chromatograph,
IBR approved for Appendix A: Method 24, Section 6.3.
(55) ASTM D4017-81, 90, 96a, Standard Test Method for Water in
Paints and Paint Materials by the Karl Fischer Titration Method, IBR
approved for Appendix A: Method 24, Section 6.4.
(56) ASTM D4057-81, 95, Standard Practice for Manual Sampling of
Petroleum and Petroleum Products, IBR approved for Appendix A: Method
19, Section 12.5.2.2.3.
(57) ASTM D4057-95 (Reapproved 2000), Standard Practice for Manual
Sampling of Petroleum and Petroleum Products, IBR approved for Sec.
60.4415(a)(1).
(58) ASTM D4084-82, 94, Standard Test Method for Analysis of
Hydrogen Sulfide in Gaseous Fuels (Lead Acetate Reaction Rate Method),
IBR approved for Sec. 60.334(h)(1).
(59) ASTM D4084-05, Standard Test Method for Analysis of Hydrogen
Sulfide in Gaseous Fuels (Lead Acetate Reaction Rate Method), IBR
approved for Sec. Sec. 60.4360 and 60.4415(a)(1)(ii).
(60) ASTM D4177-95, Standard Practice for Automatic Sampling of
Petroleum and Petroleum Products, IBR approved for Appendix A: Method
19, Section 12.5.2.2.1.
(61) ASTM D4177-95 (Reapproved 2000), Standard Practice for
Automatic Sampling of Petroleum and Petroleum Products, IBR approved
for Sec. 60.4415(a)(1).
(62) ASTM D4239-85, 94, 97, Standard Test Methods for Sulfur in the
Analysis Sample of Coal and Coke Using High Temperature Tube Furnace
Combustion Methods, IBR approved for Appendix A: Method 19, Section
12.5.2.1.3.
(63) ASTM D4294-02, Standard Test Method for Sulfur in Petroleum
and Petroleum Products by Energy-Dispersive X-Ray Fluorescence
Spectrometry, IBR approved for Sec. 60.335(b)(10)(i).
(64) ASTM D4294-03, Standard Test Method for Sulfur in Petroleum
and Petroleum Products by Energy-Dispersive X-Ray Fluorescence
Spectrometry, IBR approved for Sec. 60.4415(a)(1)(i).
(65) ASTM D4442-84, 92, Standard Test Methods for Direct Moisture
Content Measurement in Wood and Wood-base Materials, IBR approved for
Appendix A: Method 28, Section 16.1.1.
(66) ASTM D4444-92, Standard Test Methods for Use and Calibration
of Hand-Held Moisture Meters, IBR approved for Appendix A: Method 28,
Section 16.1.1.
(67) ASTM D4457-85 (Reapproved 1991), Test Method for Determination
of Dichloromethane and 1, 1, 1-Trichloroethane in Paints and Coatings
by Direct Injection into a Gas Chromatograph, IBR approved for Appendix
A: Method 24, Section 6.5.
(68) ASTM D4468-85 (Reapproved 2000), Standard Test Method for
Total Sulfur in Gaseous Fuels by Hydrogenolysis and Rateometric
Colorimetry, IBR approved for Sec. Sec. 60.335(b)(10)(ii) and
60.4415(a)(1)(ii).
(69) ASTM D4629-02, Standard Test Method for Trace Nitrogen in
Liquid Petroleum Hydrocarbons by Syringe/Inlet Oxidative Combustion and
Chemiluminescence Detection, IBR approved for Sec. Sec. 60.49b(e) and
60.335(b)(9)(i).
(70) ASTM D4809-95, Standard Test Method for Heat of Combustion of
Liquid Hydrocarbon Fuels by Bomb Calorimeter (Precision Method), IBR
approved for Sec. Sec. 60.18(f)(3), 60.485(g)(6), 60.564(f)(3),
60.614(d)(4), 60.664(e)(4), and 60.704(d)(4).
(71) ASTM D4810-88 (Reapproved 1999), Standard Test Method for
Hydrogen Sulfide in Natural Gas Using Length of Stain Detector Tubes,
IBR approved for Sec. Sec. 60.4360 and 60.4415(a)(1)(ii).
(72) ASTM D5287-97 (Reapproved 2002), Standard Practice for
Automatic Sampling of Gaseous Fuels, IBR approved for Sec.
60.4415(a)(1).
(73) ASTM D5403-93, Standard Test Methods for Volatile Content of
Radiation Curable Materials, IBR approved for Appendix A: Method 24,
Section 6.6.
(74) ASTM D5453-00, Standard Test Method for Determination of Total
Sulfur in Light Hydrocarbons, Motor Fuels and Oils by Ultraviolet
Fluorescence, IBR approved for Sec. 60.335(b)(10)(i).
(75) ASTM D5453-05, Standard Test Method for Determination of Total
Sulfur in Light Hydrocarbons, Motor Fuels and Oils by Ultraviolet
Fluorescence, IBR approved for Sec. 60.4415(a)(1)(i).
(76) ASTM D5504-01, Standard Test Method for Determination of
Sulfur Compounds in Natural Gas and Gaseous Fuels by Gas Chromatography
and Chemiluminescence, IBR approved for Sec. Sec. 60.334(h)(1) and
60.4360.
(77) ASTM D5762-02, Standard Test Method for Nitrogen in Petroleum
and Petroleum Products by Boat-Inlet Chemiluminescence, IBR approved
for Sec. 60.335(b)(9)(i).
(78) ASTM D5865-98, Standard Test Method for Gross Calorific Value
of Coal and Coke, IBR approved for Sec. 60.45(f)(5)(ii), 60.46(c)(2),
and Appendix A: Method 19, Section 12.5.2.1.3.
(79) ASTM D6216-98, Standard Practice for Opacity Monitor
Manufacturers to Certify Conformance with Design and Performance
Specifications, IBR approved for Appendix B, Performance Specification
1.
(80) ASTM D6228-98, Standard Test Method for Determination of
Sulfur Compounds in Natural Gas and Gaseous Fuels by Gas Chromatography
and Flame Photometric Detection, IBR approved for Sec. 60.334(h)(1).
(81) ASTM D6228-98 (Reapproved 2003), Standard Test Method for
Determination of Sulfur Compounds in Natural Gas and Gaseous Fuels by
Gas Chromatography and Flame Photometric Detection, IBR approved for
Sec. Sec. 60.4360 and 60.4415.
(82) ASTM D6348-03, Standard Test Method for Determination of
Gaseous Compounds by Extractive Direct Interface Fourier Transform
Infrared
[[Page 32717]]
(FTIR) Spectroscopy, IBR approved for table 7 of Subpart IIII of this
part.
(83) ASTM D6366-99, Standard Test Method for Total Trace Nitrogen
and Its Derivatives in Liquid Aromatic Hydrocarbons by Oxidative
Combustion and Electrochemical Detection, IBR approved for Sec.
60.335(b)(9)(i).
(84) ASTM D6522-00, Standard Test Method for Determination of
Nitrogen Oxides, Carbon Monoxide, and Oxygen Concentrations in
Emissions from Natural Gas-Fired Reciprocating Engines, Combustion
Turbines, Boilers, and Process Heaters Using Portable Analyzers, IBR
approved for Sec. 60.335(a).
(85) ASTM D6667-01, Standard Test Method for Determination of Total
Volatile Sulfur in Gaseous Hydrocarbons and Liquefied Petroleum Gases
by Ultraviolet Fluorescence, IBR approved for Sec. 60.335(b)(10)(ii).
(86) ASTM D6667-04, Standard Test Method for Determination of Total
Volatile Sulfur in Gaseous Hydrocarbons and Liquefied Petroleum Gases
by Ultraviolet Fluorescence, IBR approved for Sec. 60.4415(a)(1)(ii).
(87) ASTM D6784-02, Standard Test Method for Elemental, Oxidized,
Particle-Bound and Total Mercury in Flue Gas Generated from Coal-Fired
Stationary Sources (Ontario Hydro Method), IBR approved for Appendix B
to part 60, Performance Specification 12A, Section 8.6.2.
(88) ASTM E168-67, 77, 92, General Techniques of Infrared
Quantitative Analysis, IBR approved for Sec. Sec. 60.593(b)(2) and
60.632(f).
(89) ASTM E169-63, 77, 93, General Techniques of Ultraviolet
Quantitative Analysis, IBR approved for Sec. Sec. 60.593(b)(2) and
60.632(f).
(90) ASTM E260-73, 91, 96, General Gas Chromatography Procedures,
IBR approved for Sec. Sec. 60.593(b)(2) and 60.632(f).
* * * * *
(h) * * *
(2) ASME PTC 4.1-1964 (Reaffirmed 1991), Power Test Codes: Test
Code for Steam Generating Units (with 1968 and 1969 Addenda), IBR
approved for Sec. Sec. 60.46b of subpart Db of this part,
60.58a(h)(6)(ii), 60.58b(i)(6)(ii), 60.1320(a)(3) and 60.1810(a)(3).
* * * * *
Subpart D--[Amended]
0
4. Part 60 is amended by revising subpart D to read as follows:
Subpart D--Standards of Performance for Fossil-Fuel-Fired Steam
Generators for Which Construction Is Commenced After August 17, 1971
Sec.
60.40 Applicability and designation of affected facility.
60.41 Definitions.
60.42 Standard for particulate matter (PM).
60.43 Standard for sulfur dioxide (SO2).
60.44 Standard for nitrogen oxides (NOX).
60.45 Emission and fuel monitoring.
60.46 Test methods and procedures.
Subpart D--Standards of Performance for Fossil-Fuel-Fired Steam
Generators for Which Construction Is Commenced After August 17,
1971
Sec. 60.40 Applicability and designation of affected facility.
(a) The affected facilities to which the provisions of this subpart
apply are:
(1) Each fossil-fuel-fired steam generating unit of more than 73
megawatts (MW) heat input rate (250 million British thermal units per
hour (MMBtu/hr)).
(2) Each fossil-fuel and wood-residue-fired steam generating unit
capable of firing fossil fuel at a heat input rate of more than 73 MW
(250 MMBtu/hr).
(b) Any change to an existing fossil-fuel-fired steam generating
unit to accommodate the use of combustible materials, other than fossil
fuels as defined in this subpart, shall not bring that unit under the
applicability of this subpart.
(c) Except as provided in paragraph (d) of this section, any
facility under paragraph (a) of this section that commenced
construction or modification after August 17, 1971, is subject to the
requirements of this subpart.
(d) The requirements of Sec. Sec. 60.44 (a)(4), (a)(5), (b) and
(d), and 60.45(f)(4)(vi) are applicable to lignite-fired steam
generating units that commenced construction or modification after
December 22, 1976.
(e) Any facility covered under subpart Da is not covered under this
subpart.
Sec. 60.41 Definitions.
As used in this subpart, all terms not defined herein shall have
the meaning given them in the Act, and in subpart A of this part.
Boiler operating day means a 24-hour period between 12 midnight and
the following midnight during which any fuel is combusted at any time
in the steam-generating unit. It is not necessary for fuel to be
combusted the entire 24-hour period.
Coal means all solid fuels classified as anthracite, bituminous,
subbituminous, or lignite by ASTM D388 (incorporated by reference, see
Sec. 60.17).
Coal refuse means waste-products of coal mining, cleaning, and coal
preparation operations (e.g. culm, gob, etc.) containing coal, matrix
material, clay, and other organic and inorganic material.
Fossil fuel means natural gas, petroleum, coal, and any form of
solid, liquid, or gaseous fuel derived from such materials for the
purpose of creating useful heat.
Fossil fuel and wood residue-fired steam generating unit means a
furnace or boiler used in the process of burning fossil fuel and wood
residue for the purpose of producing steam by heat transfer.
Fossil-fuel-fired steam generating unit means a furnace or boiler
used in the process of burning fossil fuel for the purpose of producing
steam by heat transfer.
Wood residue means bark, sawdust, slabs, chips, shavings, mill
trim, and other wood products derived from wood processing and forest
management operations.
Sec. 60.42 Standard for particulate matter (PM).
(a) On and after the date on which the performance test required to
be conducted by Sec. 60.8 is completed, no owner or operator subject
to the provisions of this subpart shall cause to be discharged into the
atmosphere from any affected facility any gases that:
(1) Contain PM in excess of 43 nanograms per joule (ng/J) heat
input (0.10 lb/MMBtu) derived from fossil fuel or fossil fuel and wood
residue.
(2) Exhibit greater than 20 percent opacity except for one six-
minute period per hour of not more than 27 percent opacity.
(b)(1) On or after December 28, 1979, no owner or operator shall
cause to be discharged into the atmosphere from the Southwestern Public
Service Company's Harrington Station 1, in Amarillo, TX, any
gases which exhibit greater than 35 percent opacity, except that a
maximum or 42 percent opacity shall be permitted for not more than 6
minutes in any hour.
(2) Interstate Power Company shall not cause to be discharged into
the atmosphere from its Lansing Station Unit No. 4 in Lansing, IA, any
gases which exhibit greater than 32 percent opacity, except that a
maximum of 39 percent opacity shall be permitted for not more than six
minutes in any hour.
Sec. 60.43 Standard for sulfur dioxide (SO2).
(a) Except as provided under paragraph (d) of this section, on and
after the date on which the performance test required to be conducted
by Sec. 60.8 is completed, no owner or operator subject to the
provisions of this subpart shall cause to be discharged into the
atmosphere from any affected facility any gases that contain
SO2 in excess of:
[[Page 32718]]
(1) 340 ng/J heat input (0.80 lb/MMBtu) derived from liquid fossil
fuel or liquid fossil fuel and wood residue.
(2) 520 ng/J heat input (1.2 lb/MMBtu) derived from solid fossil
fuel or solid fossil fuel and wood residue, except as provided in
paragraph (e) of this section.
(b) Except as provided under paragraph (d) of this section, when
different fossil fuels are burned simultaneously in any combination,
the applicable standard (in ng/J) shall be determined by proration
using the following formula:
[GRAPHIC] [TIFF OMITTED] TR13JN07.000
Where:
PSSO2 = Prorated standard for SO2 when burning
different fuels simultaneously, in ng/J heat input derived from all
fossil fuels or from all fossil fuels and wood residue fired;
y = Percentage of total heat input derived from liquid fossil fuel;
and
z = Percentage of total heat input derived from solid fossil fuel.
(c) Compliance shall be based on the total heat input from all
fossil fuels burned, including gaseous fuels.
(d) As an alternate to meeting the requirements of paragraphs (a)
and (b) of this section, an owner or operator can petition the
Administrator (in writing) to comply with Sec. 60.43Da(i)(3) of
subpart Da of this part or comply with Sec. 60.42b(k) of subpart Db of
this part, as applicable to the affected source. If the Administrator
grants the petition, the source will from then on (unless the unit is
modified or reconstructed in the future) have to comply with the
requirements in Sec. 60.43Da(i)(3) of subpart Da of this part or Sec.
60.42b(k) of subpart Db of this part, as applicable to the affected
source.
(e) Units 1 and 2 (as defined in appendix G of this part) at the
Newton Power Station owned or operated by the Central Illinois Public
Service Company will be in compliance with paragraph (a)(2) of this
section if Unit 1 and Unit 2 individually comply with paragraph (a)(2)
of this section or if the combined emission rate from Units 1 and 2
does not exceed 470 ng/J (1.1 lb/MMBtu) combined heat input to Units 1
and 2.
Sec. 60.44 Standard for nitrogen oxides (NOX).
(a) Except as provided under paragraph (e) of this section, on and
after the date on which the performance test required to be conducted
by Sec. 60.8 is completed, no owner or operator subject to the
provisions of this subpart shall cause to be discharged into the
atmosphere from any affected facility any gases that contain
NOX, expressed as NO2 in excess of:
(1) 86 ng/J heat input (0.20 lb/MMBtu) derived from gaseous fossil
fuel.
(2) 129 ng/J heat input (0.30 lb/MMBtu) derived from liquid fossil
fuel, liquid fossil fuel and wood residue, or gaseous fossil fuel and
wood residue.
(3) 300 ng/J heat input (0.70 lb/MMBtu) derived from solid fossil
fuel or solid fossil fuel and wood residue (except lignite or a solid
fossil fuel containing 25 percent, by weight, or more of coal refuse).
(4) 260 ng/J heat input (0.60 lb MMBtu) derived from lignite or
lignite and wood residue (except as provided under paragraph (a)(5) of
this section).
(5) 340 ng/J heat input (0.80 lb MMBtu) derived from lignite which
is mined in North Dakota, South Dakota, or Montana and which is burned
in a cyclone-fired unit.
(b) Except as provided under paragraphs (c), (d), and (e) of this
section, when different fossil fuels are burned simultaneously in any
combination, the applicable standard (in ng/J) is determined by
proration using the following formula:
[GRAPHIC] [TIFF OMITTED] TR13JN07.001
Where:
PSNOx = Prorated standard for NOX
when burning different fuels simultaneously, in ng/J heat input
derived from all fossil fuels fired or from all fossil fuels and
wood residue fired;
w = Percentage of total heat input derived from lignite;
x = Percentage of total heat input derived from gaseous fossil fuel;
y = Percentage of total heat input derived from liquid fossil fuel;
and
z = Percentage of total heat input derived from solid fossil fuel
(except lignite).
(c) When a fossil fuel containing at least 25 percent, by weight,
of coal refuse is burned in combination with gaseous, liquid, or other
solid fossil fuel or wood residue, the standard for NOX does
not apply.
(d) Except as provided under paragraph (e) of this section,
cyclone-fired units which burn fuels containing at least 25 percent of
lignite that is mined in North Dakota, South Dakota, or Montana remain
subject to paragraph (a)(5) of this section regardless of the types of
fuel combusted in combination with that lignite.
(e) As an alternate to meeting the requirements of paragraphs (a),
(b), and (d) of this section, an owner or operator can petition the
Administrator (in writing) to comply with Sec. 60.44Da(e)(3) of
subpart Da of this part. If the Administrator grants the petition, the
source will from then on (unless the unit is modified or reconstructed
in the future) have to comply with the requirements in Sec.
60.44Da(e)(3) of subpart Da of this part.
Sec. 60.45 Emissions and fuel monitoring.
(a) Each owner or operator shall install, calibrate, maintain, and
operate continuous emissions monitoring systems (CEMS) for measuring
the opacity of emissions, SO2 emissions, NOX
emissions, and either oxygen (O2) or carbon dioxide
(CO2) except as provided in paragraph (b) of this section.
(b) Certain of the CEMS requirements under paragraph (a) of this
section do not apply to owners or operators under the following
conditions:
(1) For a fossil-fuel-fired steam generator that burns only gaseous
fossil fuel and that does not use post-combustion technology to reduce
emissions of SO2 or PM, CEMS for measuring the opacity of
emissions and SO2 emissions are not required.
(2) For a fossil-fuel-fired steam generator that does not use a
flue gas desulfurization device, a CEMS for measuring SO2
emissions is not required if the owner or operator monitors
SO2 emissions by fuel sampling and analysis.
(3) Notwithstanding Sec. 60.13(b), installation of a CEMS for
NOX may be delayed until after the initial performance tests
under Sec. 60.8 have been conducted. If the owner or operator
demonstrates during the performance test that emissions of
NOX are less than 70 percent of the applicable standards in
Sec. 60.44, a CEMS for measuring NOX emissions is not
required. If the initial performance test results show that
NOX emissions are greater than 70 percent of the applicable
standard, the owner or operator shall install a CEMS for NOX
within one year after the date of the initial performance
[[Page 32719]]
tests under Sec. 60.8 and comply with all other applicable monitoring
requirements under this part.
(4) If an owner or operator does not install any CEMS for sulfur
oxides and NOX, as provided under paragraphs (b)(1) and
(b)(3) or paragraphs (b)(2) and (b)(3) of this section a CEMS for
measuring either O2 or CO2 is not required.
(5) An owner or operator may petition the Administrator (in
writing) to install a PM CEMS as an alternative to the CEMS for
monitoring opacity emissions.
(6) A CEMS for measuring the opacity of emissions is not required
for a fossil fuel-fired steam generator that does not use post-
combustion technology (except a wet scrubber) for reducing PM,
SO2, or carbon monoxide (CO) emissions, burns only gaseous
fuels or fuel oils that contain less than or equal to 0.30 weight
percent sulfur, and is operated such that emissions of CO to the
atmosphere from the affected source are maintained at levels less than
or equal to 0.15 lb/MMBtu on a boiler operating day average basis.
Owners and operators of affected sources electing to comply with this
paragraph must demonstrate compliance according to the procedures
specified in paragraphs (b)(6)(i) through (iv) of this section.
(i) You must monitor CO emissions using a CEMS according to the
procedures specified in paragraphs (b)(6)(i)(A) through (D) of this
section.
(A) The CO CEMS must be installed, certified, maintained, and
operated according to the provisions in Sec. 60.58b(i)(3) of subpart
Eb of this part.
(B) Each 1-hour CO emissions average is calculated using the data
points generated by the CO CEMS expressed in parts per million by
volume corrected to 3 percent oxygen (dry basis).
(C) At a minimum, valid 1-hour CO emissions averages must be
obtained for at least 90 percent of the operating hours on a 30-day
rolling average basis. At least two data points per hour must be used
to calculate each 1-hour average.
(D) Quarterly accuracy determinations and daily calibration drift
tests for the CO CEMS must be performed in accordance with procedure 1
in appendix F of this part.
(ii) You must calculate the 1-hour average CO emissions levels for
each boiler operating day by multiplying the average hourly CO output
concentration measured by the CO CEMS times the corresponding average
hourly flue gas flow rate and divided by the corresponding average
hourly heat input to the affected source. The 24-hour average CO
emission level is determined by calculating the arithmetic average of
the hourly CO emission levels computed for each boiler operating day.
(iii) You must evaluate the preceding 24-hour average CO emission
level each boiler operating day excluding periods of affected source
startup, shutdown, or malfunction. If the 24-hour average CO emission
level is greater than 0.15 lb/MMBtu, you must initiate investigation of
the relevant equipment and control systems within 24 hours of the first
discovery of the high emission incident and, take the appropriate
corrective action as soon as practicable to adjust control settings or
repair equipment to reduce the 24-hour average CO emission level to
0.15 lb/MMBtu or less.
(iv) You must record the CO measurements and calculations performed
according to paragraph (b)(6) of this section and any corrective
actions taken. The record of corrective action taken must include the
date and time during which the 24-hour average CO emission level was
greater than 0.15 lb/MMBtu, and the date, time, and description of the
corrective action.
(c) For performance evaluations under Sec. 60.13(c) and
calibration checks under Sec. 60.13(d), the following procedures shall
be used:
(1) Methods 6, 7, and 3B of appendix A of this part, as applicable,
shall be used for the performance evaluations of SO2 and
NOX continuous monitoring systems. Acceptable alternative
methods for Methods 6, 7, and 3B of appendix A of this part are given
in Sec. 60.46(d).
(2) Sulfur dioxide or nitric oxide, as applicable, shall be used
for preparing calibration gas mixtures under Performance Specification
2 of appendix B to this part.
(3) For affected facilities burning fossil fuel(s), the span value
for a continuous monitoring system measuring the opacity of emissions
shall be 80, 90, or 100 percent. For a continuous monitoring system
measuring sulfur oxides or NOX the span value shall be
determined using one of the following procedures:
(i) Except as provided under paragraph (c)(3)(ii) of this section,
SO2 and NOX span values shall be determined as
follows:
----------------------------------------------------------------------------------------------------------------
In parts per million
Fossil fuel ---------------------------------------------------------------------------
Span value for SO2 Span value for NOX
----------------------------------------------------------------------------------------------------------------
Gas................................. (\1\)............................... 500.
Liquid.............................. 1,000............................... 500.
Solid............................... 1,500............................... 1,000.
Combinations........................ 1,000y + 1,500z..................... 500 (x + y) + 1,000z.
----------------------------------------------------------------------------------------------------------------
\1\ Not applicable.
Where:
x = Fraction of total heat input derived from gaseous fossil fuel;
y = Fraction of total heat input derived from liquid fossil fuel;
and
z = Fraction of total heat input derived from solid fossil fuel.
(ii) As an alternative to meeting the requirements of paragraph
(c)(3)(i) of this section, the owner or operator of an affected
facility may elect to use the SO2 and NOX span
values determined according to sections 2.1.1 and 2.1.2 in appendix A
to part 75 of this chapter.
(4) All span values computed under paragraph (c)(3)(i) of this
section for burning combinations of fossil fuels shall be rounded to
the nearest 500 ppm. Span values that are computed under paragraph
(c)(3)(ii) of this section shall be rounded off according to the
applicable procedures in section 2 of appendix A to part 75 of this
chapter.
(5) For a fossil-fuel-fired steam generator that simultaneously
burns fossil fuel and nonfossil fuel, the span value of all CEMS shall
be subject to the Administrator's approval.
(d) [Reserved]
(e) For any CEMS installed under paragraph (a) of this section, the
following conversion procedures shall be used to convert the continuous
monitoring data into units of the applicable standards (ng/J, lb/
MMBtu):
(1) When a CEMS for measuring O2 is selected, the
measurement of the pollutant concentration and O2
concentration shall each be on a consistent basis (wet or dry).
Alternative procedures approved by the Administrator shall be used when
measurements are on a wet basis. When measurements are on a dry basis,
the
[[Page 32720]]
following conversion procedure shall be used:
[GRAPHIC] [TIFF OMITTED] TR13JN07.002
Where E, C, F, and %O2 are determined under paragraph (f)
of this section.
(2) When a CEMS for measuring CO2 is selected, the
measurement of the pollutant concentration and CO2
concentration shall each be on a consistent basis (wet or dry) and the
following conversion procedure shall be used:
[GRAPHIC] [TIFF OMITTED] TR13JN07.003
Where E, C, Fc and %CO2 are determined under
paragraph (f) of this section.
(f) The values used in the equations under paragraphs (e)(1) and
(2) of this section are derived as follows:
(1) E = pollutant emissions, ng/J (lb/MMBtu).
(2) C = pollutant concentration, ng/dscm (lb/dscf), determined by
multiplying the average concentration (ppm) for each one-hour period by
4.15 x 104 M ng/dscm per ppm (2.59 x 10-9 M lb/
dscf per ppm) where M = pollutant molecular weight, g/g-mole (lb/lb-
mole). M = 64.07 for SO2 and 46.01 for NOX.
(3) %O2, %CO2 = O2 or
CO2 volume (expressed as percent), determined with equipment
specified under paragraph (a) of this section.
(4) F, Fc = a factor representing a ratio of the volume
of dry flue gases generated to the calorific value of the fuel
combusted (F), and a factor representing a ratio of the volume of
CO2 generated to the calorific value of the fuel combusted
(Fc), respectively. Values of F and Fc are given
as follows:
(i) For anthracite coal as classified according to ASTM D388
(incorporated by reference, see Sec. 60.17), F = 2,723 x
10-17 dscm/J (10,140 dscf/MMBtu) and Fc = 0.532 x
10-17 scm CO2/J (1,980 scf CO2/MMBtu).
(ii) For subbituminous and bituminous coal as classified according
to ASTM D388 (incorporated by reference, see Sec. 60.17), F = 2.637 x
10-7 dscm/J (9,820 dscf/MMBtu) and Fc = 0.486 x
10-7 scm CO2/J (1,810 scf CO2/MMBtu).
(iii) For liquid fossil fuels including crude, residual, and
distillate oils, F = 2.476 x 10-7 dscm/J (9,220 dscf/MMBtu)
and Fc = 0.384 x 10-7 scm CO2/J (1,430
scf CO2/MMBtu).
(iv) For gaseous fossil fuels, F = 2.347 x 10-7 dscm/J
(8,740 dscf/MMBtu). For natural gas, propane, and butane fuels,
Fc = 0.279 x 10-7 scm CO2/J (1,040 scf
CO2/MMBtu) for natural gas, 0.322 x 10-7 scm
CO2/J (1,200 scf CO2/MMBtu) for propane, and
0.338 x 10-7 scm CO2/J (1,260 scf CO2/
MMBtu) for butane.
(v) For bark F = 2.589 x 10-7 dscm/J (9,640 dscf/MMBtu)
and Fc = 0.500 x 10-7 scm CO2/J (1,840
scf CO2/MMBtu). For wood residue other than bark F = 2.492 x
10-7 dscm/J (9,280 dscf/MMBtu) and Fc = 0.494 x
10-7 scm CO2/J (1,860 scf CO2/MMBtu).
(vi) For lignite coal as classified according to ASTM D388
(incorporated by reference, see Sec. 60.17), F = 2.659 x
10-7 dscm/J (9,900 dscf/MMBtu) and Fc = 0.516 x
10-7 scm CO2/J (1,920 scf CO2/MMBtu).
(5) The owner or operator may use the following equation to
determine an F factor (dscm/J or dscf/MMBtu) on a dry basis (if it is
desired to calculate F on a wet basis, consult the Administrator) or Fc
factor (scm CO2/J, or scf CO2/MMBtu) on either
basis in lieu of the F or Fc factors specified in paragraph
(f)(4) of this section:
[GRAPHIC] [TIFF OMITTED] TR13JN07.004
(i) %H, %C, %S, %N, and %O are content by weight of hydrogen,
carbon, sulfur, nitrogen, and O2 (expressed as percent),
respectively, as determined on the same basis as GCV by ultimate
analysis of the fuel fired, using ASTM D3178 or D3176 (solid fuels), or
computed from results using ASTM D1137, D1945, or D1946 (gaseous fuels)
as applicable. (These five methods are incorporated by reference, see
Sec. 60.17.)
(ii) GVC is the gross calorific value (kJ/kg, Btu/lb) of the fuel
combusted determined by the ASTM test methods D2015 or D5865 for solid
fuels and D1826 for gaseous fuels as applicable. (These three methods
are incorporated by reference, see Sec. 60.17.)
(iii) For affected facilities which fire both fossil fuels and
nonfossil fuels, the F or Fc value shall be subject to the
Administrator's approval.
(6) For affected facilities firing combinations of fossil fuels or
fossil fuels and wood residue, the F or Fc factors determined by
paragraphs (f)(4) or (f)(5) of this section shall be prorated in
accordance with the applicable formula as follows:
[GRAPHIC] [TIFF OMITTED] TR13JN07.005
Where:
[[Page 32721]]
Xi = Fraction of total heat input derived from each type
of fuel (e.g. natural gas, bituminous coal, wood residue, etc.);
Fi or (Fc)i = Applicable F or
Fc factor for each fuel type determined in accordance
with paragraphs (f)(4) and (f)(5) of this section; and
n = Number of fuels being burned in combination.
(g) Excess emission and monitoring system performance reports shall
be submitted to the Administrator semiannually for each six-month
period in the calendar year. All semiannual reports shall be postmarked
by the 30th day following the end of each six-month period. Each excess
emission and MSP report shall include the information required in Sec.
60.7(c). Periods of excess emissions and monitoring systems (MS)
downtime that shall be reported are defined as follows:
(1) Opacity. Excess emissions are defined as any six-minute period
during which the average opacity of emissions exceeds 20 percent
opacity, except that one six-minute average per hour of up to 27
percent opacity need not be reported.
(i) For sources subject to the opacity standard of Sec.
60.42(b)(1), excess emissions are defined as any six-minute period
during which the average opacity of emissions exceeds 35 percent
opacity, except that one six-minute average per hour of up to 42
percent opacity need not be reported.
(ii) For sources subject to the opacity standard of Sec.
60.42(b)(2), excess emissions are defined as any six-minute period
during which the average opacity of emissions exceeds 32 percent
opacity, except that one six-minute average per hour of up to 39
percent opacity need not be reported.
(2) Sulfur dioxide. Excess emissions for affected facilities are
defined as:
(i) Any three-hour period during which the average emissions
(arithmetic average of three contiguous one-hour periods) of
SO2 as measured by a CEMS exceed the applicable standard
under Sec. 60.43, or
(ii) Any 30 operating day period during which the average emissions
(arithmetic average of all one-hour periods during the 30 operating
days) of SO2 as measured by a CEMS exceed the applicable
standard under Sec. 60.43. Facilities complying with the 30-day
SO2 standard shall use the most current associated
SO2 compliance and monitoring requirements in Sec. Sec.
60.48Da and 60.49Da of subpart Da of this part.
(3) Nitrogen oxides. Excess emissions for affected facilities using
a CEMS for measuring NOX are defined as:
(i) Any three-hour period during which the average emissions
(arithmetic average of three contiguous one-hour periods) exceed the
applicable standards under Sec. 60.44, or
(ii) Any 30 operating day period during which the average emissions
(arithmetic average of all one-hour periods during the 30 operating
days) of NOX as measured by a CEMS exceed the applicable
standard under Sec. 60.43. Facilities complying with the 30-day
NOX standard shall use the most current associated
NOX compliance and monitoring requirements in Sec. Sec.
60.48Da and 60.49Da of subpart Da of this part.
(4) Particulate matter. Excess emissions for affected facilities
using a CEMS for measuring PM are defined as any boiler operating day
period during which the average emissions (arithmetic average of all
operating one-hour periods) exceed the applicable standards under Sec.
60.43. Affected facilities using PM CEMS in lieu of a CEMS for
monitoring opacity emissions must follow the most current applicable
compliance and monitoring provisions in Sec. Sec. 60.48Da and 60.49Da
of subpart Da of this part.
Sec. 60.46 Test methods and procedures.
(a) In conducting the performance tests required in Sec. 60.8, and
subsequent performance tests as requested by the EPA Administrator, the
owner or operator shall use as reference methods and procedures the
test methods in appendix A of this part or other methods and procedures
as specified in this section, except as provided in Sec. 60.8(b).
Acceptable alternative methods and procedures are given in paragraph
(d) of this section.
(b) The owner or operator shall determine compliance with the PM,
SO2, and NOX standards in Sec. Sec. 60.42,
60.43, and 60.44 as follows:
(1) The emission rate (E) of PM, SO2, or NOX
shall be computed for each run using the following equation:
[GRAPHIC] [TIFF OMITTED] TR13JN07.006
Where:
E = Emission rate of pollutant, ng/J (1b/million Btu);
C = Concentration of pollutant, ng/dscm (1b/dscf);
%O2 = O2 concentration, percent dry basis; and
Fd = Factor as determined from Method 19 of appendix A of
this part.
(2) Method 5 of appendix A of this part shall be used to determine
the PM concentration (C) at affected facilities without wet flue-gas-
desulfurization (FGD) systems and Method 5B of appendix A of this part
shall be used to determine the PM concentration (C) after FGD systems.
(i) The sampling time and sample volume for each run shall be at
least 60 minutes and 0.85 dscm (30 dscf). The probe and filter holder
heating systems in the sampling train shall be set to provide an
average gas temperature of 16014 [deg]C (32025
[deg]F).
(ii) The emission rate correction factor, integrated or grab
sampling and analysis procedure of Method 3B of appendix A of this part
shall be used to determine the O2 concentration
(%O2). The O2 sample shall be obtained
simultaneously with, and at the same traverse points as, the
particulate sample. If the grab sampling procedure is used, the
O2 concentration for the run shall be the arithmetic mean of
the sample O2 concentrations at all traverse points.
(iii) If the particulate run has more than 12 traverse points, the
O2 traverse points may be reduced to 12 provided that Method
1 of appendix A of this part is used to locate the 12 O2
traverse points.
(3) Method 9 of appendix A of this part and the procedures in Sec.
60.11 shall be used to determine opacity.
(4) Method 6 of appendix A of this part shall be used to determine
the SO2 concentration.
(i) The sampling site shall be the same as that selected for the
particulate sample. The sampling location in the duct shall be at the
centroid of the cross section or at a point no closer to the walls than
1 m (3.28 ft). The sampling time and sample volume for each sample run
shall be at least 20 minutes and 0.020 dscm (0.71 dscf). Two samples
shall be taken during a 1-hour period, with each sample taken within a
30-minute interval.
(ii) The emission rate correction factor, integrated sampling and
analysis procedure of Method 3B of appendix A of this part shall be
used to determine the O2 concentration (%O2). The
O2 sample shall be taken simultaneously with, and at the
same point as, the SO2 sample. The SO2 emission
rate shall be computed for each pair of SO2 and
O2 samples. The SO2 emission rate (E) for each
run shall be the arithmetic mean of the results of the two pairs of
samples.
(5) Method 7 of appendix A of this part shall be used to determine
the NOX concentration.
(i) The sampling site and location shall be the same as for the
SO2 sample. Each run shall consist of four grab samples,
with each sample taken at about 15-minute intervals.
(ii) For each NOX sample, the emission rate correction
factor, grab sampling and analysis procedure of
[[Page 32722]]
Method 3B of appendix A of this part shall be used to determine the
O2 concentration (%O2). The sample shall be taken
simultaneously with, and at the same point as, the NOX
sample.
(iii) The NOX emission rate shall be computed for each
pair of NOX and O2 samples. The NOX
emission rate (E) for each run shall be the arithmetic mean of the
results of the four pairs of samples.
(c) When combinations of fossil fuels or fossil fuel and wood
residue are fired, the owner or operator (in order to compute the
prorated standard as shown in Sec. Sec. 60.43(b) and 60.44(b)) shall
determine the percentage (w, x, y, or z) of the total heat input
derived from each type of fuel as follows:
(1) The heat input rate of each fuel shall be determined by
multiplying the gross calorific value of each fuel fired by the rate of
each fuel burned.
(2) ASTM Methods D2015, or D5865 (solid fuels), D240 (liquid
fuels), or D1826 (gaseous fuels) (all of these methods are incorporated
by reference, see Sec. 60.17) shall be used to determine the gross
calorific values of the fuels. The method used to determine the
calorific value of wood residue must be approved by the Administrator.
(3) Suitable methods shall be used to determine the rate of each
fuel burned during each test period, and a material balance over the
steam generating system shall be used to confirm the rate.
(d) The owner or operator may use the following as alternatives to
the reference methods and procedures in this section or in other
sections as specified:
(1) The emission rate (E) of PM, SO2 and NOX
may be determined by using the Fc factor, provided that the following
procedure is used:
(i) The emission rate (E) shall be computed using the following
equation:
[GRAPHIC] [TIFF OMITTED] TR13JN07.007
Where:
E = Emission rate of pollutant, ng/J (lb/MMBtu);
C = Concentration of pollutant, ng/dscm (lb/dscf);
%CO2 = CO2 concentration, percent dry basis;
and
Fc = Factor as determined in appropriate sections of
Method 19 of appendix A of this part.
(ii) If and only if the average Fc factor in Method 19 of appendix
A of this part is used to calculate E and either E is from 0.97 to 1.00
of the emission standard or the relative accuracy of a continuous
emission monitoring system is from 17 to 20 percent, then three runs of
Method 3B of appendix A of this part shall be used to determine the
O2 and CO2 concentration according to the
procedures in paragraph (b)(2)(ii), (4)(ii), or (5)(ii) of this
section. Then if Fo (average of three runs), as calculated
from the equation in Method 3B of appendix A of this part, is more than
3 percent than the average Fo value, as
determined from the average values of Fd and Fc
in Method 19 of appendix A of this part, i.e., Foa = 0.209
(Fda/Fca), then the following procedure shall be
followed:
(A) When Fo is less than 0.97 Foa, then E
shall be increased by that proportion under 0.97 Foa, e.g.,
if Fo is 0.95 Foa, E shall be increased by 2
percent. This recalculated value shall be used to determine compliance
with the emission standard.
(B) When Fo is less than 0.97 Foa and when
the average difference (d) between the continuous monitor minus the
reference methods is negative, then E shall be increased by that
proportion under 0.97 Foa, e.g., if Fo is 0.95
Foa, E shall be increased by 2 percent. This recalculated
value shall be used to determine compliance with the relative accuracy
specification.
(C) When Fo is greater than 1.03 Foa and when
the average difference d is positive, then E shall be decreased by that
proportion over 1.03 Foa, e.g., if Fo is 1.05
Foa, E shall be decreased by 2 percent. This recalculated
value shall be used to determine compliance with the relative accuracy
specification.
(2) For Method 5 or 5B of appendix A of this part, Method 17 of
appendix A of this part may be used at facilities with or without wet
FGD systems if the stack gas temperature at the sampling location does
not exceed an average temperature of 16 0[deg]C (320 [deg]F). The
procedures of sections 2.1 and 2.3 of Method 5B of appendix A of this
part may be used with Method 17 of appendix A of this part only if it
is used after wet FGD systems. Method 17 of appendix A of this part
shall not be used after wet FGD systems if the effluent gas is
saturated or laden with water droplets.
(3) Particulate matter and SO2 may be determined
simultaneously with the Method 5 of appendix A of this part train
provided that the following changes are made:
(i) The filter and impinger apparatus in sections 2.1.5 and 2.1.6
of Method 8 of appendix A of this part is used in place of the
condenser (section 2.1.7) of Method 5 of appendix A of this part.
(ii) All applicable procedures in Method 8 of appendix A of this
part for the determination of SO2 (including moisture) are
used:
(4) For Method 6 of appendix A of this part, Method 6C of appendix
A of this part may be used. Method 6A of appendix A of this part may
also be used whenever Methods 6 and 3B of appendix A of this part data
are specified to determine the SO2 emission rate, under the
conditions in paragraph (d)(1) of this section.
(5) For Method 7 of appendix A of this part, Method 7A, 7C, 7D, or
7E of appendix A of this part may be used. If Method 7C, 7D, or 7E of
appendix A of this part is used, the sampling time for each run shall
be at least 1 hour and the integrated sampling approach shall be used
to determine the O2 concentration (%O2) for the
emission rate correction factor.
(6) For Method 3 of appendix A of this part, Method 3A or 3B of
appendix A of this part may be used.
(7) For Method 3B of appendix A of this part, Method 3A of appendix
A of this part may be used.
Subpart Da--[Amended]
0
4a. Subpart Da is revised as follows:
Subpart Da--Standards of Performance for Electric Utility Steam
Generating Units for Which Construction is Commenced After September
18, 1978
Sec.
60.40Da Applicability and designation of affected facility.
60.41Da Definitions.
60.42Da Standard for particulate matter (PM).
60.43Da Standard for sulfur dioxide (SO2).
60.44Da Standard for nitrogen oxides (NOX).
60.45Da Standard for mercury (Hg).
60.46Da [Reserved]
60.47Da Commercial demonstration permit.
60.48Da Compliance provisions.
60.49Da Emission monitoring.
60.50Da Compliance determination procedures and methods.
60.51Da Reporting requirements.
60.52Da Recordkeeping requirements.
Subpart Da--Standards of Performance for Electric Utility Steam
Generating Units for Which Construction is Commenced After
September 18, 1978
Sec. 60.40Da Applicability and designation of affected facility.
(a) The affected facility to which this subpart applies is each
electric utility steam generating unit:
(1) That is capable of combusting more than 73 megawatts (MW) (250
million British thermal units per hour (MMBtu/hr) heat input of fossil
fuel (either alone or in combination with any other fuel); and
(2) For which construction, modification, or reconstruction is
commenced after September 18, 1978.
[[Page 32723]]
(b) Combined cycle gas turbines (both the stationary combustion
turbine and any associated duct burners) are subject to this part and
not subject to subpart GG or KKKK of this part if:
(1) The combined cycle gas turbine is capable of combusting more
than 73 MW (250 MMBtu/hr) heat input of fossil fuel (either alone or in
combination with any other fuel); and
(2) The combined cycle gas turbine is designed and intended to burn
fuels containing 50 percent (by heat input) or more solid-derived fuel
not meeting the definition of natural gas on a 12-month rolling average
basis; and
(3) The combined cycle gas turbine commenced construction,
modification, or reconstruction after February 28, 2005.
(4) This subpart will continue to apply to all other electric
utility combined cycle gas turbines that are capable of combusting more
than 73 MW (250 MMBtu/hr) heat input of fossil fuel in the heat
recovery steam generator. If the heat recovery steam generator is
subject to this subpart and the stationary combustion turbine is
subject to either subpart GG or KKKK of this part, only emissions
resulting from combustion of fuels in the steam-generating unit are
subject to this subpart. (The stationary combustion turbine emissions
are subject to subpart GG or KKKK, as applicable, of this part).
(c) Any change to an existing fossil-fuel-fired steam generating
unit to accommodate the use of combustible materials, other than fossil
fuels, shall not bring that unit under the applicability of this
subpart.
(d) Any change to an existing steam generating unit originally
designed to fire gaseous or liquid fossil fuels, to accommodate the use
of any other fuel (fossil or nonfossil) shall not bring that unit under
the applicability of this subpart.
Sec. 60.41Da Definitions.
As used in this subpart, all terms not defined herein shall have
the meaning given them in the Act and in subpart A of this part.
Anthracite means coal that is classified as anthracite according to
the American Society of Testing and Materials in ASTM D388
(incorporated by reference, see Sec. 60.17).
Available purchase power means the lesser of the following:
(a) The sum of available system capacity in all neighboring
companies.
(b) The sum of the rated capacities of the power interconnection
devices between the principal company and all neighboring companies,
minus the sum of the electric power load on these interconnections.
(c) The rated capacity of the power transmission lines between the
power interconnection devices and the electric generating units (the
unit in the principal company that has the malfunctioning flue gas
desulfurization system and the unit(s) in the neighboring company
supplying replacement electrical power) less the electric power load on
these transmission lines.
Available system capacity means the capacity determined by
subtracting the system load and the system emergency reserves from the
net system capacity.
Biomass means plant materials and animal waste.
Bituminous coal means coal that is classified as bituminous
according to the American Society of Testing and Materials in ASTM D388
(incorporated by reference, see Sec. 60.17).
Boiler operating day for units constructed, reconstructed, or
modified on or before February 28, 2005, means a 24-hour period during
which fossil fuel is combusted in a steam-generating unit for the
entire 24 hours. For units constructed, reconstructed, or modified
after February 28, 2005, boiler operating day means a 24-hour period
between 12 midnight and the following midnight during which any fuel is
combusted at any time in the steam-generating unit. It is not necessary
for fuel to be combusted the entire 24-hour period.
Coal means all solid fuels classified as anthracite, bituminous,
subbituminous, or lignite by the American Society of Testing and
Materials in ASTM D388 (incorporated by reference, see Sec. 60.17) and
coal refuse. Synthetic fuels derived from coal for the purpose of
creating useful heat, including but not limited to solvent-refined
coal, gasified coal (not meeting the definition of natural gas), coal-
oil mixtures, and coal-water mixtures are included in this definition
for the purposes of this subpart.
Coal-fired electric utility steam generating unit means an electric
utility steam generating unit that burns coal, coal refuse, or a
synthetic gas derived from coal either exclusively, in any combination
together, or in any combination with other fuels in any amount.
Coal refuse means waste products of coal mining, physical coal
cleaning, and coal preparation operations (e.g. culm, gob, etc.)
containing coal, matrix material, clay, and other organic and inorganic
material.
Cogeneration, also known as ``combined heat and power,'' means a
steam-generating unit that simultaneously produces both electric (or
mechanical) and useful thermal energy from the same primary energy
source.
Combined cycle gas turbine means a stationary turbine combustion
system where heat from the turbine exhaust gases is recovered by a
steam generating unit.
Dry flue gas desulfurization technology or dry FGD means a sulfur
dioxide control system that is located downstream of the steam
generating unit and removes sulfur oxides (SO2) from the
combustion gases of the steam generating unit by contacting the
combustion gases with an alkaline reagent and water, whether introduced
separately or as a premixed slurry or solution and forming a dry powder
material. This definition includes devices where the dry powder
material is subsequently converted to another form. Alkaline slurries
or solutions used in dry FGD technology include, but are not limited
to, lime and sodium.
Duct burner means a device that combusts fuel and that is placed in
the exhaust duct from another source, such as a stationary gas turbine,
internal combustion engine, kiln, etc., to allow the firing of
additional fuel to heat the exhaust gases before the exhaust gases
enter a heat recovery steam generating unit.
Electric utility combined cycle gas turbine means any combined
cycle gas turbine used for electric generation that is constructed for
the purpose of supplying more than one-third of its potential electric
output capacity and more than 25 MW net-electrical output to any
utility power distribution system for sale. Any steam distribution
system that is constructed for the purpose of providing steam to a
steam electric generator that would produce electrical power for sale
is also considered in determining the electrical energy output capacity
of the affected facility.
Electric utility company means the largest interconnected
organization, business, or governmental entity that generates electric
power for sale (e.g., a holding company with operating subsidiary
companies).
Electric utility steam-generating unit means any steam electric
generating unit that is constructed for the purpose of supplying more
than one-third of its potential electric output capacity and more than
25 MW net-electrical output to any utility power distribution system
for sale. Also, any steam supplied to a steam distribution system for
the purpose of providing steam to a steam-electric generator that would
produce electrical energy for sale is considered in determining the
electrical energy output capacity of the affected facility.
[[Page 32724]]
Electrostatic precipitator or ESP means an add-on air pollution
control device used to capture particulate matter (PM) by charging the
particles using an electrostatic field, collecting the particles using
a grounded collecting surface, and transporting the particles into a
hopper.
Emergency condition means that period of time when:
(1) The electric generation output of an affected facility with a
malfunctioning flue gas desulfurization system cannot be reduced or
electrical output must be increased because:
(i) All available system capacity in the principal company
interconnected with the affected facility is being operated, and
(ii) All available purchase power interconnected with the affected
facility is being obtained, or
(2) The electric generation demand is being shifted as quickly as
possible from an affected facility with a malfunctioning flue gas
desulfurization system to one or more electrical generating units held
in reserve by the principal company or by a neighboring company, or
(3) An affected facility with a malfunctioning flue gas
desulfurization system becomes the only available unit to maintain a
part or all of the principal company's system emergency reserves and
the unit is operated in spinning reserve at the lowest practical
electric generation load consistent with not causing significant
physical damage to the unit. If the unit is operated at a higher load
to meet load demand, an emergency condition would not exist unless the
conditions under paragraph (1) of this definition apply.
Emission limitation means any emissions limit or operating limit.
Emission rate period means any calendar month included in a 12-
month rolling average period.
Federally enforceable means all limitations and conditions that are
enforceable by the Administrator, including the requirements of 40 CFR
parts 60 and 61, requirements within any applicable State
implementation plan, and any permit requirements established under 40
CFR 52.21 or under 40 CFR 51.18 and 51.24.
Fossil fuel means natural gas, petroleum, coal, and any form of
solid, liquid, or gaseous fuel derived from such material for the
purpose of creating useful heat.
Gaseous fuel means any fuel derived from coal or petroleum that is
present as a gas at standard conditions and includes, but is not
limited to, refinery fuel gas, process gas, coke-oven gas, synthetic
gas, and gasified coal.
Gross output means the gross useful work performed by the steam
generated and, for an IGCC electric utility steam generating unit, the
fuel burned in stationary combustion turbines. For a unit generating
only electricity, the gross useful work performed is the gross
electrical output from the unit's turbine/generator sets. For a
cogeneration unit, the gross useful work performed is the gross
electrical or mechanical output plus 75 percent of the useful thermal
output measured relative to ISO conditions that is not used to generate
additional electrical or mechanical output (i.e., steam delivered to an
industrial process).
24-hour period means the period of time between 12:01 a.m. and
12:00 midnight.
Integrated gasification combined cycle electric utility steam
generating unit or IGCC electric utility steam generating unit means a
coal-fired electric utility steam generating unit that burns a
synthetic gas derived from coal in a combined-cycle gas turbine. No
coal is directly burned in the unit during operation.
Interconnected means that two or more electric generating units are
electrically tied together by a network of power transmission lines,
and other power transmission equipment.
ISO conditions means a temperature of 288 Kelvin, a relative
humidity of 60 percent, and a pressure of 101.3 kilopascals.
Lignite means coal that is classified as lignite A or B according
to the American Society of Testing and Materials in ASTM D388
(incorporated by reference, see Sec. 60.17).
Natural gas means:
(1) A naturally occurring mixture of hydrocarbon and nonhydrocarbon
gases found in geologic formations beneath the earth's surface, of
which the principal constituent is methane; or
(2) Liquid petroleum gas, as defined by the American Society of
Testing and Materials in ASTM D1835 (incorporated by reference, see
Sec. 60.17); or
(3) A mixture of hydrocarbons that maintains a gaseous state at ISO
conditions. Additionally, natural gas must either be composed of at
least 70 percent methane by volume or have a gross calorific value
between 34 and 43 megajoules (MJ) per standard cubic meter (910 and
1,150 Btu per standard cubic foot).
Neighboring company means any one of those electric utility
companies with one or more electric power interconnections to the
principal company and which have geographically adjoining service
areas.
Net-electric output means the gross electric sales to the utility
power distribution system minus purchased power on a calendar year
basis.
Net system capacity means the sum of the net electric generating
capability (not necessarily equal to rated capacity) of all electric
generating equipment owned by an electric utility company (including
steam generating units, internal combustion engines, gas turbines,
nuclear units, hydroelectric units, and all other electric generating
equipment) plus firm contractual purchases that are interconnected to
the affected facility that has the malfunctioning flue gas
desulfurization system. The electric generating capability of equipment
under multiple ownership is prorated based on ownership unless the
proportional entitlement to electric output is otherwise established by
contractual arrangement.
Noncontinental area means the State of Hawaii, the Virgin Islands,
Guam, American Samoa, the Commonwealth of Puerto Rico, or the Northern
Mariana Islands.
Petroleum means crude oil or petroleum or a fuel derived from crude
oil or petroleum, including, but not limited to, distillate oil,
residual oil, and petroleum coke.
Potential combustion concentration means the theoretical emissions
(nanograms per joule (ng/J), lb/MMBtu heat input) that would result
from combustion of a fuel in an uncleaned state without emission
control systems) and:
(1) For particulate matter (PM) is:
(i) 3,000 ng/J (7.0 lb/MMBtu) heat input for solid fuel; and
(ii) 73 ng/J (0.17 lb/MMBtu) heat input for liquid fuels.
(2) For sulfur dioxide (SO2) is determined under Sec.
60.50Da(c).
(3) For nitrogen oxides (NOX) is:
(i) 290 ng/J (0.67 lb/MMBtu) heat input for gaseous fuels;
(ii) 310 ng/J (0.72 lb/MMBtu) heat input for liquid fuels; and
(iii) 990 ng/J (2.30 lb/MMBtu) heat input for solid fuels.
Potential electrical output capacity means 33 percent of the
maximum design heat input capacity of the steam generating unit,
divided by 3,413 Btu/KWh, divided by 1,000 kWh/MWh, and multiplied by
8,760 hr/yr (e.g., a steam generating unit with a 100 MW (340 MMBtu/hr)
fossil-fuel heat input capacity would have a 289,080 MWh 12 month
potential electrical output capacity). For electric utility combined
cycle gas turbines the potential electrical output capacity is
determined on the basis of the fossil-fuel firing
[[Page 32725]]
capacity of the steam generator exclusive of the heat input and
electrical power contribution by the gas turbine.
Principal company means the electric utility company or companies
which own the affected facility.
Resource recovery unit means a facility that combusts more than 75
percent non-fossil fuel on a quarterly (calendar) heat input basis.
Responsible official means responsible official as defined in 40
CFR 70.2.
Solid-derived fuel means any solid, liquid, or gaseous fuel derived
from solid fuel for the purpose of creating useful heat and includes,
but is not limited to, solvent refined coal, liquified coal, synthetic
gas, gasified coal, gasified petroleum coke, gasified biomass, and
gasified tire derived fuel.
Spare flue gas desulfurization system module means a separate
system of SO2 emission control equipment capable of treating
an amount of flue gas equal to the total amount of flue gas generated
by an affected facility when operated at maximum capacity divided by
the total number of nonspare flue gas desulfurization modules in the
system.
Spinning reserve means the sum of the unutilized net generating
capability of all units of the electric utility company that are
synchronized to the power distribution system and that are capable of
immediately accepting additional load. The electric generating
capability of equipment under multiple ownership is prorated based on
ownership unless the proportional entitlement to electric output is
otherwise established by contractual arrangement.
Steam generating unit means any furnace, boiler, or other device
used for combusting fuel for the purpose of producing steam (including
fossil-fuel-fired steam generators associated with combined cycle gas
turbines; nuclear steam generators are not included).
Subbituminous coal means coal that is classified as subbituminous
A, B, or C according to the American Society of Testing and Materials
in ASTM D388 (incorporated by reference, see Sec. 60.17).
System emergency reserves means an amount of electric generating
capacity equivalent to the rated capacity of the single largest
electric generating unit in the electric utility company (including
steam generating units, internal combustion engines, gas turbines,
nuclear units, hydroelectric units, and all other electric generating
equipment) which is interconnected with the affected facility that has
the malfunctioning flue gas desulfurization system. The electric
generating capability of equipment under multiple ownership is prorated
based on ownership unless the proportional entitlement to electric
output is otherwise established by contractual arrangement.
System load means the entire electric demand of an electric utility
company's service area interconnected with the affected facility that
has the malfunctioning flue gas desulfurization system plus firm
contractual sales to other electric utility companies. Sales to other
electric utility companies (e.g., emergency power) not on a firm
contractual basis may also be included in the system load when no
available system capacity exists in the electric utility company to
which the power is supplied for sale.
Wet flue gas desulfurization technology or wet FGD means a
SO2 control system that is located downstream of the steam
generating unit and removes sulfur oxides from the combustion gases of
the steam generating unit by contacting the combustion gases with an
alkaline slurry or solution and forming a liquid material. This
definition applies to devices where the aqueous liquid material product
of this contact is subsequently converted to other forms. Alkaline
reagents used in wet FGD technology include, but are not limited to,
lime, limestone, and sodium.
Sec. 60.42Da Standard for particulate matter (PM).
(a) On and after the date on which the initial performance test is
completed or required to be completed under Sec. 60.8, whichever date
comes first, no owner or operator subject to the provisions of this
subpart shall cause to be discharged into the atmosphere from any
affected facility for which construction, reconstruction, or
modification commenced before or on February 28, 2005, any gases that
contain PM in excess of:
(1) 13 ng/J (0.03 lb/MMBtu) heat input derived from the combustion
of solid, liquid, or gaseous fuel;
(2) 1 percent of the potential combustion concentration (99 percent
reduction) when combusting solid fuel; and
(3) 30 percent of potential combustion concentration (70 percent
reduction) when combusting liquid fuel.
(b) On and after the date the initial PM performance test is
completed or required to be completed under Sec. 60.8, whichever date
comes first, no owner or operator subject to the provisions of this
subpart shall cause to be discharged into the atmosphere from any
affected facility any gases which exhibit greater than 20 percent
opacity (6-minute average), except for one 6-minute period per hour of
not more than 27 percent opacity.
(c) Except as provided in paragraph (d) of this section, on and
after the date on which the initial performance test is completed or
required to be completed under Sec. 60.8, whichever date comes first,
no owner or operator of an affected facility that commenced
construction, reconstruction, or modification after February 28, 2005
shall cause to be discharged into the atmosphere from that affected
facility any gases that contain PM in excess of either:
(1) 18 ng/J (0.14 lb/MWh) gross energy output; or
(2) 6.4 ng/J (0.015 lb/MMBtu) heat input derived from the
combustion of solid, liquid, or gaseous fuel.
(d) As an alternative to meeting the requirements of paragraph (c)
of this section, the owner or operator of an affected facility for
which construction, reconstruction, or modification commenced after
February 28, 2005, may elect to meet the requirements of this
paragraph. On and after the date on which the initial performance test
is completed or required to be completed under Sec. 60.8, whichever
date comes first, no owner or operator of an affected facility shall
cause to be discharged into the atmosphere from that affected facility
for which construction, reconstruction, or modification commenced after
February 28, 2005, any gases that contain PM in excess of:
(1) 13 ng/J (0.03 lb/MMBtu) heat input derived from the combustion
of solid, liquid, or gaseous fuel, and
(2) 0.1 percent of the combustion concentration determined
according to the procedure in Sec. 60.48Da(o)(5) (99.9 percent
reduction) for an affected facility for which construction or
reconstruction commenced after February 28, 2005 when combusting solid,
liquid, or gaseous fuel, or
(3) 0.2 percent of the combustion concentration determined
according to the procedure in Sec. 60.48Da(o)(5) (99.8 percent
reduction) for an affected facility for which modification commenced
after February 28, 2005 when combusting solid, liquid, or gaseous fuel.
Sec. 60.43Da Standard for sulfur dioxide (SO2).
(a) On and after the date on which the initial performance test is
completed or required to be completed under Sec. 60.8, whichever date
comes first, no owner or operator subject to the provisions of this
subpart shall cause to be discharged into the atmosphere from any
affected facility which combusts solid fuel or
[[Page 32726]]
solid-derived fuel and for which construction, reconstruction, or
modification commenced before or on February 28, 2005, except as
provided under paragraphs (c), (d), (f) or (h) of this section, any
gases that contain SO2 in excess of:
(1) 520 ng/J (1.20 lb/MMBtu) heat input and 10 percent of the
potential combustion concentration (90 percent reduction); or
(2) 30 percent of the potential combustion concentration (70
percent reduction), when emissions are less than 260 ng/J (0.60 lb/
MMBtu) heat input.
(b) On and after the date on which the initial performance test is
completed or required to be completed under Sec. 60.8, whichever date
comes first, no owner or operator subject to the provisions of this
subpart shall cause to be discharged into the atmosphere from any
affected facility which combusts liquid or gaseous fuels (except for
liquid or gaseous fuels derived from solid fuels and as provided under
paragraphs (e) or (h) of this section) and for which construction,
reconstruction, or modification commenced before or on February 28,
2005, any gases that contain SO2 in excess of:
(1) 340 ng/J (0.80 lb/MMBtu) heat input and 10 percent of the
potential combustion concentration (90 percent reduction); or
(2) 100 percent of the potential combustion concentration (zero
percent reduction) when emissions are less than 86 ng/J (0.20 lb/MMBtu)
heat input.
(c) On and after the date on which the initial performance test is
completed or required to be completed under Sec. 60.8, whichever date
comes first, no owner or operator subject to the provisions of this
subpart shall cause to be discharged into the atmosphere from any
affected facility which combusts solid solvent refined coal (SRC-I) any
gases that contain SO2 in excess of 520 ng/J (1.20 lb/MMBtu)
heat input and 15 percent of the potential combustion concentration (85
percent reduction) except as provided under paragraph (f) of this
section; compliance with the emission limitation is determined on a 30-
day rolling average basis and compliance with the percent reduction
requirement is determined on a 24-hour basis.
(d) Sulfur dioxide emissions are limited to 520 ng/J (1.20 lb/
MMBtu) heat input from any affected facility which:
(1) Combusts 100 percent anthracite;
(2) Is classified as a resource recovery unit; or
(3) Is located in a noncontinental area and combusts solid fuel or
solid-derived fuel.
(e) Sulfur dioxide emissions are limited to 340 ng/J (0.80 lb/
MMBtu) heat input from any affected facility which is located in a
noncontinental area and combusts liquid or gaseous fuels (excluding
solid-derived fuels).
(f) The emission reduction requirements under this section do not
apply to any affected facility that is operated under an SO2
commercial demonstration permit issued by the Administrator in
accordance with the provisions of Sec. 60.47Da.
(g) Compliance with the emission limitation and percent reduction
requirements under this section are both determined on a 30-day rolling
average basis except as provided under paragraph (c) of this section.
(h) When different fuels are combusted simultaneously, the
applicable standard is determined by proration using the following
formula:
(1) If emissions of SO2 to the atmosphere are greater
than 260 ng/J (0.60 lb/MMBtu) heat input
[GRAPHIC] [TIFF OMITTED] TR13JN07.008
(2) If emissions of SO2 to the atmosphere are equal to
or less than 260 ng/J (0.60 lb/MMBtu) heat input:
[GRAPHIC] [TIFF OMITTED] TR13JN07.009
Where:
Es = Prorated SO2 emission limit (ng/J heat
input);
%Ps = Percentage of potential SO2 emission
allowed;
x = Percentage of total heat input derived from the combustion of
liquid or gaseous fuels (excluding solid-derived fuels); and
y = Percentage of total heat input derived from the combustion of
solid fuel (including solid-derived fuels).
(i) Except as provided in paragraphs (j) and (k) of this section,
on and after the date on which the initial performance test is
completed or required to be completed under Sec. 60.8, whichever date
comes first, no owner or operator of an affected facility that
commenced construction, reconstruction, or modification commenced after
February 28, 2005 shall cause to be discharged into the atmosphere from
that affected facility, any gases that contain SO2 in excess
of the applicable emission limitation specified in paragraphs (i)(1)
through (3) of this section.
(1) For an affected facility for which construction commenced after
February 28, 2005, any gases that contain SO2 in excess of
either:
(i) 180 ng/J (1.4 lb/MWh) gross energy output on a 30-day rolling
average basis; or
(ii) 5 percent of the potential combustion concentration (95
percent reduction) on a 30-day rolling average basis.
(2) For an affected facility for which reconstruction commenced
after February 28, 2005, any gases that contain SO2 in
excess of either:
(i) 180 ng/J (1.4 lb/MWh) gross energy output on a 30-day rolling
average basis;
(ii) 65 ng/J (0.15 lb/MMBtu) heat input on a 30-day rolling average
basis; or
(iii) 5 percent of the potential combustion concentration (95
percent reduction) on a 30-day rolling average basis.
(3) For an affected facility for which modification commenced after
February 28, 2005, any gases that contain SO2 in excess of
either:
(i) 180 ng/J (1.4 lb/MWh) gross energy output on a 30-day rolling
average basis;
(ii) 65 ng/J (0.15 lb/MMBtu) heat input on a 30-day rolling average
basis; or
(iii) 10 percent of the potential combustion concentration (90
percent reduction) on a 30-day rolling average basis.
(j) On and after the date on which the initial performance test is
completed or required to be completed under Sec. 60.8, whichever date
comes first, no owner or operator of an affected facility that
commenced construction, reconstruction, or modification commenced after
February 28, 2005, and that burns 75 percent or more (by heat input)
coal refuse on a 12-month rolling average basis, shall caused to be
discharged into the atmosphere from that affected facility any gases
that contain SO2 in excess of the applicable emission
limitation specified in paragraphs (j)(1) through (3) of this section.
(1) For an affected facility for which construction commenced after
February
[[Page 32727]]
28, 2005, any gases that contain SO2 in excess of either:
(i) 180 ng/J (1.4 lb/MWh) gross energy output on a 30-day rolling
average basis; or
(ii) 6 percent of the potential combustion concentration (94
percent reduction) on a 30-day rolling average basis.
(2) For an affected facility for which reconstruction commenced
after February 28, 2005, any gases that contain SO2 in
excess of either:
(i) 180 ng/J (1.4 lb/MWh) gross energy output on a 30-day rolling
average basis;
(ii) 65 ng/J (0.15 lb/MMBtu) heat input on a 30-day rolling average
basis; or
(iii) 6 percent of the potential combustion concentration (94
percent reduction) on a 30-day rolling average basis.
(3) For an affected facility for which modification commenced after
February 28, 2005, any gases that contain SO2 in excess of
either:
(i) 180 ng/J (1.4 lb/MWh) gross energy output on a 30-day rolling
average basis;
(ii) 65 ng/J (0.15 lb/MMBtu) heat input on a 30-day rolling average
basis; or
(iii) 10 percent of the potential combustion concentration (90
percent reduction) on a 30-day rolling average basis.
(k) On and after the date on which the initial performance test is
completed or required to be completed under Sec. 60.8, whichever date
comes first, no owner or operator of an affected facility located in a
noncontinental area that commenced construction, reconstruction, or
modification commenced after February 28, 2005, shall cause to be
discharged into the atmosphere from that affected facility any gases
that contain SO2 in excess of the applicable emission
limitation specified in paragraphs (k)(1) and (2) of this section.
(1) For an affected facility that burns solid or solid-derived
fuel, the owner or operator shall not cause to be discharged into the
atmosphere any gases that contain SO2 in excess of 520 ng/J
(1.2 lb/MMBtu) heat input on a 30-day rolling average basis.
(2) For an affected facility that burns other than solid or solid-
derived fuel, the owner or operator shall not cause to be discharged
into the atmosphere any gases that contain SO2 in excess of
if the affected facility or 230 ng/J (0.54 lb/MMBtu) heat input on a
30-day rolling average basis.
Sec. 60.44Da Standard for nitrogen oxides (NOX).
(a) On and after the date on which the initial performance test is
completed or required to be completed under Sec. 60.8, whichever date
comes first, no owner or operator subject to the provisions of this
subpart shall cause to be discharged into the atmosphere from any
affected facility, except as provided under paragraphs (b), (d), (e),
and (f) of this section, any gases that contain NOX
(expressed as NO2) in excess of the following emission
limits, based on a 30-day rolling average basis, except as provided
under Sec. 60.48Da(j)(1):
(1) NOX emission limits.
------------------------------------------------------------------------
Emission limit for
heat input
Fuel type ---------------------
ng/J lb/MMBtu
------------------------------------------------------------------------
Gaseous fuels:
Coal-derived fuels............................ 210 0.50
All other fuels............................... 86 0.20
Liquid fuels:
Coal-derived fuels............................ 210 0.50
Shale oil..................................... 210 0.50
All other fuels............................... 130 0.30
Solid fuels:
Coal-derived fuels............................ 210 0.50
Any fuel containing more than 25%, by weight, \(1)\ \(1)\
coal refuse..................................
Any fuel containing more than 25%, by weight, 340 0.80
lignite if the lignite is mined in North
Dakota, South Dakota, or Montana, and is
combusted in a slag tap furnace \2\..........
Any fuel containing more than 25%, by weight, 260 0.60
lignite not subject to the 340 ng/J heat
input emission limit \2\.....................
Subbituminous coal............................ 210 0.50
Bituminous coal............................... 260 0.60
Anthracite coal............................... 260 0.60
All other fuels............................... 260 0.60
------------------------------------------------------------------------
\1\ Exempt from NOX standards and NOX monitoring requirements.
\2\ Any fuel containing less than 25%, by weight, lignite is not
prorated but its percentage is added to the percentage of the
predominant fuel.
(2) NOX reduction requirement.
------------------------------------------------------------------------
Percent
reduction of
Fuel type potential
combustion
concentration
------------------------------------------------------------------------
Gaseous fuels......................................... 25
Liquid fuels.......................................... 30
Solid fuels........................................... 65
------------------------------------------------------------------------
(b) The emission limitations under paragraph (a) of this section do
not apply to any affected facility which is combusting coal-derived
liquid fuel and is operating under a commercial demonstration permit
issued by the Administrator in accordance with the provisions of Sec.
60.47Da.
(c) Except as provided under paragraphs (d), (e), and (f) of this
section, when two or more fuels are combusted simultaneously, the
applicable standard is determined by proration using the following
formula:
[GRAPHIC] [TIFF OMITTED] TR13JN07.010
Where:
En = Applicable standard for NOX when multiple
fuels are combusted simultaneously (ng/J heat input);
w = Percentage of total heat input derived from the combustion of
fuels subject to the 86 ng/J heat input standard;
x = Percentage of total heat input derived from the combustion of
fuels subject to the 130 ng/J heat input standard;
y = Percentage of total heat input derived from the combustion of
fuels subject to the 210 ng/J heat input standard;
z = Percentage of total heat input derived from the combustion of
fuels subject to the 260 ng/J heat input standard; and
v = Percentage of total heat input delivered from the combustion of
fuels subject to the 340 ng/J heat input standard.
(d)(1) On and after the date on which the initial performance test
is completed
[[Page 32728]]
or required to be completed under Sec. 60.8, whichever date comes
first, no owner or operator of an affected facility that commenced
construction after July 9, 1997, but before or on February 28, 2005
shall cause to be discharged into the atmosphere any gases that contain
NOX (expressed as NO2) in excess of 200 ng/J (1.6
lb/MWh) gross energy output, based on a 30-day rolling average basis,
except as provided under Sec. 60.48Da(k).
(2) On and after the date on which the initial performance test is
completed or required to be completed under Sec. 60.8, whichever date
comes first, no owner or operator of affected facility for which
reconstruction commenced after July 9, 1997, but before or on February
28, 2005 shall cause to be discharged into the atmosphere any gases
that contain NOX (expressed as NO2) in excess of
65 ng/J (0.15 lb/MMBtu) heat input, based on a 30-day rolling average
basis.
(e) Except for an IGCC electric utility steam generating unit
meeting the requirements of paragraph (f) of this section, on and after
the date on which the initial performance test is completed or required
to be completed under Sec. 60.8, whichever date comes first, no owner
or operator of an affected facility that commenced construction,
reconstruction, or modification after February 28, 2005 shall cause to
be discharged into the atmosphere from that affected facility any gases
that contain NOX (expressed as NO2) in excess of
the applicable emission limitation specified in paragraphs (e)(1)
through (3) of this section.
(1) For an affected facility for which construction commenced after
February 28, 2005, the owner or operator shall not cause to be
discharged into the atmosphere any gases that contain NOX
(expressed as NO2) in excess of 130 ng/J (1.0 lb/MWh) gross
energy output on a 30-day rolling average basis, except as provided
under Sec. 60.48Da(k).
(2) For an affected facility for which reconstruction commenced
after February 28, 2005, the owner or operator shall not cause to be
discharged into the atmosphere any gases that contain NOX
(expressed as NO2) in excess of either:
(i) 130 ng/J (1.0 lb/MWh) gross energy output on a 30-day rolling
average basis; or
(ii) 47 ng/J (0.11 lb/MMBtu) heat input on a 30-day rolling average
basis.
(3) For an affected facility for which modification commenced after
February 28, 2005, the owner or operator shall not cause to be
discharged into the atmosphere any gases that contain NOX
(expressed as NO2) in excess of either:
(i) 180 ng/J (1.4 lb/MWh) gross energy output on a 30-day rolling
average basis; or
(ii) 65 ng/J (0.15 lb/MMBtu) heat input on a 30-day rolling average
basis.
(f) On and after the date on which the initial performance test is
completed or required to be completed under Sec. 60.8, whichever date
comes first, the owner or operator of an IGCC electric utility steam
generating unit subject to the provisions of this subpart and for which
construction, reconstruction, or modification commenced after February
28, 2005, shall meet the requirements specified in paragraphs (f)(1)
through (3) of this section.
(1) Except as provided for in paragraphs (f)(2) and (3) of this
section, the owner or operator shall not cause to be discharged into
the atmosphere any gases that contain NOX (expressed as
NO2) in excess of 130 ng/J (1.0 lb/MWh) gross energy output
on a 30-day rolling average basis.
(2) When burning liquid fuel exclusively or in combination with
solid-derived fuel such that the liquid fuel contributes 50 percent or
more of the total heat input to the combined cycle combustion turbine,
the owner or operator shall not cause to be discharged into the
atmosphere any gases that contain NOX (expressed as
NO2) in excess of 190 ng/J (1.5 lb/MWh) gross energy output
on a 30-day rolling average basis.
(3) In cases when during a 30-day rolling average compliance period
liquid fuel is burned in such a manner to meet the conditions in
paragraph (f)(2) of this section for only a portion of the clock hours
in the 30-day period, the owner or operator shall not cause to be
discharged into the atmosphere any gases that contain NOX
(expressed as NO2) in excess of the computed weighted-
average emissions limit based on the proportion of gross energy output
(in MWh) generated during the compliance period for each of emissions
limits in paragraphs (f)(1) and (2) of this section.
Sec. 60.45Da Standard for mercury (Hg).
(a) For each coal-fired electric utility steam generating unit
other than an IGCC electric utility steam generating unit, on and after
the date on which the initial performance test is completed or required
to be completed under Sec. 60.8, whichever date comes first, no owner
or operator subject to the provisions of this subpart shall cause to be
discharged into the atmosphere from any affected facility for which
construction, modification, or reconstruction commenced after January
30, 2004, any gases that contain mercury (Hg) emissions in excess of
each Hg emissions limit in paragraphs (a)(1) through (5) of this
section that applies to you. The Hg emissions limits in paragraphs
(a)(1) through (5) of this section are based on a 12-month rolling
average basis using the procedures in Sec. 60.50Da(h).
(1) For each coal-fired electric utility steam generating unit that
burns only bituminous coal, you must not discharge into the atmosphere
any gases from a new affected source that contain Hg in excess of 20 x
10-\6\ pound per megawatt hour (lb/MWh) or 0.020 lb/
gigawatt-hour (GWh) on an output basis. The International System of
Units (SI) equivalent is 0.0025 ng/J.
(2) For each coal-fired electric utility steam generating unit that
burns only subbituminous coal:
(i) If your unit is located in a county-level geographical area
receiving greater than 25 inches per year (in/yr) mean annual
precipitation, based on the most recent publicly available U.S.
Department of Agriculture 30-year data, you must not discharge into the
atmosphere any gases from a new affected source that contain Hg in
excess of 66 x 10-\6\ lb/MWh or 0.066 lb/GWh on an output
basis. The SI equivalent is 0.0083 ng/J.
(ii) If your unit is located in a county-level geographical area
receiving less than or equal to 25 in/yr mean annual precipitation,
based on the most recent publicly available U.S. Department of
Agriculture 30-year data, you must not discharge into the atmosphere
any gases from a new affected source that contain Hg in excess of 97 x
10-\6\ lb/MWh or 0.097 lb/GWh on an output basis. The SI
equivalent is 0.0122 ng/J.
(3) For each coal-fired electric utility steam generating unit that
burns only lignite, you must not discharge into the atmosphere any
gases from a new affected source that contain Hg in excess of 175 x
10-\6\ lb/MWh or 0.175 lb/GWh on an output basis. The SI
equivalent is 0.0221 ng/J.
(4) For each coal-burning electric utility steam generating unit
that burns only coal refuse, you must not discharge into the atmosphere
any gases from a new affected source that contain Hg in excess of 16 x
10-\6\ lb/MWh or 0.016 lb/GWh on an output basis. The SI
equivalent is 0.0020 ng/J.
(5) For each coal-fired electric utility steam generating unit that
burns a blend of coals from different coal ranks (i.e., bituminous
coal, subbituminous coal, lignite) or a blend of coal and coal refuse,
you must not discharge into the atmosphere any gases from a new
affected source that contain Hg in excess of the unit-specific Hg
emissions limit
[[Page 32729]]
established according to paragraph (a)(5)(i) or (ii) of this section,
as applicable to the affected unit.
(i) If you operate a coal-fired electric utility steam generating
unit that burns a blend of coals from different coal ranks or a blend
of coal and coal refuse, you must not discharge into the atmosphere any
gases from a new affected source that contain Hg in excess of the
computed weighted Hg emissions limit based on the Btu, MWh, or MJ)
contributed by each coal rank burned during the compliance period and
its applicable Hg emissions limit in paragraphs (a)(1) through (4) of
this section as determined using Equation 1 in this section. For each
affected source, you must comply with the weighted Hg emissions limit
calculated using Equation 1 in this section based on the total Hg
emissions from the unit and the total Btu, MWh, or MJ contributed by
all fuels burned during the compliance period.
[GRAPHIC] [TIFF OMITTED] TR13JN07.011
Where:
ELb = Total allowable Hg in lb/MWh that can be emitted to
the atmosphere from any affected source being averaged according to
this paragraph.
ELi = Hg emissions limit for the subcategory i (coal
rank) that applies to affected source, lb/MWh;
HHi = For each affected source, the Btu, MWh, or MJ
contributed by the corresponding subcategory i (coal rank) burned
during the compliance period; and
n = Number of subcategories (coal ranks) being averaged for an
affected source.
(ii) If you operate a coal-fired electric utility steam generating
unit that burns a blend of coals from different coal ranks or a blend
of coal and coal refuse together with one or more non-regulated,
supplementary fuels, you must not discharge into the atmosphere any
gases from a new affected source that contain Hg in excess of the
computed weighted Hg emission limit based on the Btu, MWh, or MJ
contributed by each coal rank burned during the compliance period and
its applicable Hg emissions limit in paragraphs (a)(1) through (4) of
this section as determined using Equation 1 in this section. For each
affected source. You must comply with the weighted Hg emissions limit
calculated using Equation 1 in this section based on the total Hg
emissions from the unit contributed by both regulated and nonregulated
fuels burned during the compliance period and the total Btu, MWh, or MJ
contributed by both regulated and nonregulated fuels burned during the
compliance period.
(b) For each IGCC electric utility steam generating unit, on and
after the date on which the initial performance test required to be
conducted under Sec. 60.8 is completed, no owner or operator subject
to the provisions of this subpart shall cause to be discharged into the
atmosphere from any affected facility for which construction,
modification, or reconstruction commenced after January 30, 2004, any
gases that contain Hg emissions in excess of 20 x 10-\6\ lb/
MWh or 0.020 lb/GWh on an output basis. The SI equivalent is 0.0025 ng/
J. This Hg emissions limit is based on a 12-month rolling average basis
using the procedures in Sec. 60.50Da(h).
Sec. 60.46Da [Reserved]
Sec. 60.47Da Commercial demonstration permit.
(a) An owner or operator of an affected facility proposing to
demonstrate an emerging technology may apply to the Administrator for a
commercial demonstration permit. The Administrator will issue a
commercial demonstration permit in accordance with paragraph (e) of
this section. Commercial demonstration permits may be issued only by
the Administrator, and this authority will not be delegated.
(b) An owner or operator of an affected facility that combusts
solid solvent refined coal (SRC-I) and who is issued a commercial
demonstration permit by the Administrator is not subject to the
SO2 emission reduction requirements under Sec. 60.43Da(c)
but must, as a minimum, reduce SO2 emissions to 20 percent
of the potential combustion concentration (80 percent reduction) for
each 24-hour period of steam generator operation and to less than 520
ng/J (1.20 lb/MMBtu) heat input on a 30-day rolling average basis.
(c) An owner or operator of a fluidized bed combustion electric
utility steam generator (atmospheric or pressurized) who is issued a
commercial demonstration permit by the Administrator is not subject to
the SO2 emission reduction requirements under Sec.
60.43Da(a) but must, as a minimum, reduce SO2 emissions to
15 percent of the potential combustion concentration (85 percent
reduction) on a 30-day rolling average basis and to less than 520 ng/J
(1.20 lb/MMBtu) heat input on a 30-day rolling average basis.
(d) The owner or operator of an affected facility that combusts
coal-derived liquid fuel and who is issued a commercial demonstration
permit by the Administrator is not subject to the applicable
NOX emission limitation and percent reduction under Sec.
60.44Da(a) but must, as a minimum, reduce emissions to less than 300
ng/J (0.70 lb/MMBtu) heat input on a 30-day rolling average basis.
(e) Commercial demonstration permits may not exceed the following
equivalent MW electrical generation capacity for any one technology
category, and the total equivalent MW electrical generation capacity
for all commercial demonstration plants may not exceed 15,000 MW.
------------------------------------------------------------------------
Equivalent
electrical
Technology Pollutant capacity (MW
electrical
output)
------------------------------------------------------------------------
Solid solvent refined coal (SCR I)....... SO2 6,000-10,000
Fluidized bed combustion (atmospheric)... SO2 400-3,000
Fluidized bed combustion (pressurized)... SO2 400-1,200
Coal liquification....................... NOX 750-10,000
------------------------------
Total allowable for all technologies. ........... 15,000
------------------------------------------------------------------------
Sec. 60.48Da Compliance provisions.
(a) Compliance with the PM emission limitation under Sec.
60.42Da(a)(1) constitutes compliance with the percent reduction
requirements for PM under Sec. 60.42Da(a)(2) and (3).
(b) Compliance with the NOX emission limitation under
Sec. 60.44Da(a)(1) constitutes compliance with the percent reduction
requirements under Sec. 60.44Da(a)(2).
[[Page 32730]]
(c) The PM emission standards under Sec. 60.42Da, the
NOX emission standards under Sec. 60.44Da, and the Hg
emission standards under Sec. 60.45Da apply at all times except during
periods of startup, shutdown, or malfunction.
(d) During emergency conditions in the principal company, an
affected facility with a malfunctioning flue gas desulfurization system
may be operated if SO2 emissions are minimized by:
(1) Operating all operable flue gas desulfurization system modules,
and bringing back into operation any malfunctioned module as soon as
repairs are completed,
(2) Bypassing flue gases around only those flue gas desulfurization
system modules that have been taken out of operation because they were
incapable of any SO2 emission reduction or which would have
suffered significant physical damage if they had remained in operation,
and
(3) Designing, constructing, and operating a spare flue gas
desulfurization system module for an affected facility larger than 365
MW (1,250 MMBtu/hr) heat input (approximately 125 MW electrical output
capacity). The Administrator may at his discretion require the owner or
operator within 60 days of notification to demonstrate spare module
capability. To demonstrate this capability, the owner or operator must
demonstrate compliance with the appropriate requirements under
paragraph under Sec. 60.43Da(a), (b), (d), (e), and (h) for any period
of operation lasting from 24 hours to 30 days when:
(i) Any one flue gas desulfurization module is not operated,
(ii) The affected facility is operating at the maximum heat input
rate,
(iii) The fuel fired during the 24-hour to 30-day period is
representative of the type and average sulfur content of fuel used over
a typical 30-day period, and
(iv) The owner or operator has given the Administrator at least 30
days notice of the date and period of time over which the demonstration
will be performed.
(e) After the initial performance test required under Sec. 60.8,
compliance with the SO2 emission limitations and percentage
reduction requirements under Sec. 60.43Da and the NOX
emission limitations under Sec. 60.44Da is based on the average
emission rate for 30 successive boiler operating days. A separate
performance test is completed at the end of each boiler operating day
after the initial performance test, and a new 30 day average emission
rate for both SO2 and NOX and a new percent
reduction for SO2 are calculated to show compliance with the
standards.
(f) For the initial performance test required under Sec. 60.8,
compliance with the SO2 emission limitations and percent
reduction requirements under Sec. 60.43Da and the NOX
emission limitation under Sec. 60.44Da is based on the average
emission rates for SO2, NOX, and percent
reduction for SO2 for the first 30 successive boiler
operating days. The initial performance test is the only test in which
at least 30 days prior notice is required unless otherwise specified by
the Administrator. The initial performance test is to be scheduled so
that the first boiler operating day of the 30 successive boiler
operating days is completed within 60 days after achieving the maximum
production rate at which the affected facility will be operated, but
not later than 180 days after initial startup of the facility.
(g) The owner or operator of an affected facility subject to
emission limitations in this subpart shall determine compliance as
follows:
(1) Compliance with applicable 30-day rolling average
SO2 and NOX emission limitations is determined by
calculating the arithmetic average of all hourly emission rates for
SO2 and NOX for the 30 successive boiler
operating days, except for data obtained during startup, shutdown,
malfunction (NOX only), or emergency conditions
(SO2 only).
(2) Compliance with applicable SO2 percentage reduction
requirements is determined based on the average inlet and outlet
SO2 emission rates for the 30 successive boiler operating
days.
(3) Compliance with applicable daily average PM emission
limitations is determined by calculating the arithmetic average of all
hourly emission rates for PM each boiler operating day, except for data
obtained during startup, shutdown, and malfunction. Averages are only
calculated for boiler operating days that have valid data for at least
18 hours of unit operation during which the standard applies. Instead,
the valid hourly emission rates are averaged with the next boiler
operating day with 18 hours or more of valid PM CEMS data to determine
compliance.
(h) If an owner or operator has not obtained the minimum quantity
of emission data as required under Sec. 60.49Da of this subpart,
compliance of the affected facility with the emission requirements
under Sec. Sec. 60.43Da and 60.44Da of this subpart for the day on
which the 30-day period ends may be determined by the Administrator by
following the applicable procedures in section 7 of Method 19 of
appendix A of this part.
(i) Compliance provisions for sources subject to Sec.
60.44Da(d)(1), (e)(1), (e)(2)(i), (e)(3)(i), or (f). The owner or
operator of an affected facility subject to Sec. 60.44Da(d)(1),
(e)(1), (e)(2)(i), (e)(3)(i), or (f) shall calculate NOX
emissions as 1.194 x 10-\7\ lb/scf-ppm times the average
hourly NOX output concentration in ppm (measured according
to the provisions of Sec. 60.49Da(c)), times the average hourly flow
rate (measured in scfh, according to the provisions of Sec. 60.49Da(l)
or Sec. 60.49Da(m)), divided by the average hourly gross energy output
(measured according to the provisions of Sec. 60.49Da(k)).
Alternatively, for oil-fired and gas-fired units, NOX
emissions may be calculated by multiplying the hourly NOX
emission rate in lb/MMBtu (measured by the CEMS required under
Sec. Sec. 60.49Da(c) and (d)), by the hourly heat input rate (measured
according to the provisions of Sec. 60.49Da(n)), and dividing the
result by the average gross energy output (measured according to the
provisions of Sec. 60.49Da(k)).
(j) Compliance provisions for duct burners subject to Sec.
60.44Da(a)(1). To determine compliance with the emissions limits for
NOX required by Sec. 60.44Da(a) for duct burners used in
combined cycle systems, either of the procedures described in paragraph
(j)(1) or (2) of this section may be used:
(1) The owner or operator of an affected duct burner shall conduct
the performance test required under Sec. 60.8 using the appropriate
methods in appendix A of this part. Compliance with the emissions
limits under Sec. 60.44Da(a)(1) is determined on the average of three
(nominal 1-hour) runs for the initial and subsequent performance tests.
During the performance test, one sampling site shall be located in the
exhaust of the turbine prior to the duct burner. A second sampling site
shall be located at the outlet from the heat recovery steam generating
unit. Measurements shall be taken at both sampling sites during the
performance test; or
(2) The owner or operator of an affected duct burner may elect to
determine compliance by using the continuous emission monitoring system
(CEMS) specified under Sec. 60.49Da for measuring NOX and
oxygen (O2) (or carbon dioxide (CO2)) and meet
the requirements of Sec. 60.49Da. Alternatively, data from a
NOX emission rate (i.e., NOX-diluent) CEMS
certified according to the provisions of Sec. 75.20(c) of this chapter
and appendix A to part 75 of this chapter, and meeting the quality
assurance requirements of Sec. 75.21 of this chapter and appendix B to
part 75 of this chapter, may be used,
[[Page 32731]]
with the following caveats. Data used to meet the requirements of Sec.
60.51Da shall not include substitute data values derived from the
missing data procedures in subpart D of part 75 of this chapter, nor
shall the data have been bias adjusted according to the procedures of
part 75 of this chapter. The sampling site shall be located at the
outlet from the steam generating unit. The NOX emission rate
at the outlet from the steam generating unit shall constitute the
NOX emission rate from the duct burner of the combined cycle
system.
(k) Compliance provisions for duct burners subject to Sec.
60.44Da(d)(1) or (e)(1). To determine compliance with the emission
limitation for NOX required by Sec. 60.44Da(d)(1) or (e)(1)
for duct burners used in combined cycle systems, either of the
procedures described in paragraphs (k)(1) and (2) of this section may
be used:
(1) The owner or operator of an affected duct burner used in
combined cycle systems shall determine compliance with the applicable
NOX emission limitation in Sec. 60.44Da(d)(1) or (e)(1) as
follows:
(i) The emission rate (E) of NOX shall be computed using
Equation 2 in this section:
[GRAPHIC] [TIFF OMITTED] TR13JN07.012
Where:
E = Emission rate of NOX from the duct burner, ng/J (lb/
MWh) gross output;
Csg = Average hourly concentration of NOX
exiting the steam generating unit, ng/dscm (lb/dscf);
Cte = Average hourly concentration of NOX in
the turbine exhaust upstream from duct burner, ng/dscm (lb/dscf);
Qsg = Average hourly volumetric flow rate of exhaust gas
from steam generating unit, dscm/hr (dscf/hr);
Qte = Average hourly volumetric flow rate of exhaust gas
from combustion turbine, dscm/hr (dscf/hr);
Osg = Average hourly gross energy output from steam
generating unit, J (MWh); and
h = Average hourly fraction of the total heat input to the steam
generating unit derived from the combustion of fuel in the affected
duct burner.
(ii) Method 7E of appendix A of this part shall be used to
determine the NOX concentrations (Csg and
Cte). Method 2, 2F or 2G of appendix A of this part, as
appropriate, shall be used to determine the volumetric flow rates
(Qsg and Qte) of the exhaust gases. The
volumetric flow rate measurements shall be taken at the same time as
the concentration measurements.
(iii) The owner or operator shall develop, demonstrate, and provide
information satisfactory to the Administrator to determine the average
hourly gross energy output from the steam generating unit, and the
average hourly percentage of the total heat input to the steam
generating unit derived from the combustion of fuel in the affected
duct burner.
(iv) Compliance with the applicable NOX emission
limitation in Sec. 60.44Da(d)(1) or (e)(1) is determined by the three-
run average (nominal 1-hour runs) for the initial and subsequent
performance tests.
(2) The owner or operator of an affected duct burner used in a
combined cycle system may elect to determine compliance with the
applicable NOX emission limitation in Sec. 60.44Da(d)(1) or
(e)(1) on a 30-day rolling average basis as indicated in paragraphs
(k)(2)(i) through (iv) of this section.
(i) The emission rate (E) of NOX shall be computed using
Equation 3 in this section:
[GRAPHIC] [TIFF OMITTED] TR13JN07.013
Where:
E = Emission rate of NOX from the duct burner, ng/J (lb/
MWh) gross output;
Csg = Average hourly concentration of NOX
exiting the steam generating unit, ng/dscm (lb/dscf);
Qsg = Average hourly volumetric flow rate of exhaust gas
from steam generating unit, dscm/hr (dscf/hr); and
Occ = Average hourly gross energy output from entire
combined cycle unit, J (MWh).
(ii) The CEMS specified under Sec. 60.49Da for measuring
NOX and O2 (or CO2) shall be used to
determine the average hourly NOX concentrations
(Csg). The continuous flow monitoring system specified in
Sec. 60.49Da(l) or Sec. 60.49Da(m) shall be used to determine the
volumetric flow rate (Qsg) of the exhaust gas. If the option
to use the flow monitoring system in Sec. 60.49Da(m) is selected, the
flow rate data used to meet the requirements of Sec. 60.51Da shall not
include substitute data values derived from the missing data procedures
in subpart D of part 75 of this chapter, nor shall the data have been
bias adjusted according to the procedures of part 75 of this chapter.
The sampling site shall be located at the outlet from the steam
generating unit.
(iii) The continuous monitoring system specified under Sec.
60.49Da(k) for measuring and determining gross energy output shall be
used to determine the average hourly gross energy output from the
entire combined cycle unit (Occ), which is the combined
output from the combustion turbine and the steam generating unit.
(iv) The owner or operator may, in lieu of installing, operating,
and recording data from the continuous flow monitoring system specified
in Sec. 60.49Da(l), determine the mass rate (lb/hr) of NOX
emissions by installing, operating, and maintaining continuous fuel
flowmeters following the appropriate measurements procedures specified
in appendix D of part 75 of this chapter. If this compliance option is
selected, the emission rate (E) of NOX shall be computed
using Equation 4 in this section:
[GRAPHIC] [TIFF OMITTED] TR13JN07.014
Where:
E = Emission rate of NOX from the duct burner, ng/J (lb/
MWh) gross output;
ERsg = Average hourly emission rate of NOX
exiting the steam generating unit heat input calculated using
appropriate F factor as described in Method 19 of appendix A of this
part, ng/J (lb/MMBtu);
Hcc = Average hourly heat input rate of entire combined
cycle unit, J/hr (MMBtu/hr); and
Occ = Average hourly gross energy output from entire
combined cycle unit, J (MWh).
(3) When an affected duct burner steam generating unit utilizes a
common steam turbine with one or more affected duct burner steam
generating units, the owner or operator shall either:
(i) Determine compliance with the applicable NOX
emissions limits by measuring the emissions combined with the emissions
from the other unit(s) utilizing the common steam turbine; or
(ii) Develop, demonstrate, and provide information satisfactory to
the Administrator on methods for apportioning the combined gross energy
output from the steam turbine for each of the affected duct burners.
The Administrator may approve such demonstrated substitute methods for
apportioning the combined gross energy output measured at the steam
turbine whenever the demonstration ensures accurate estimation of
emissions regulated under this part.
(l) Compliance provisions for sources subject to Sec. 60.45Da. The
owner or operator of an affected facility subject to Sec. 60.45Da (new
sources constructed or reconstructed after January 30, 2004) shall
calculate the Hg emission rate (lb/MWh) for each calendar month of the
year, using hourly Hg concentrations measured according to the
provisions of Sec. 60.49Da(p) in conjunction with hourly stack gas
volumetric flow rates
[[Page 32732]]
measured according to the provisions of Sec. 60.49Da(l) or (m), and
hourly gross electrical outputs, determined according to the provisions
in Sec. 60.49Da(k). Compliance with the applicable standard under
Sec. 60.45Da is determined on a 12-month rolling average basis.
(m) Compliance provisions for sources subject to Sec.
60.43Da(i)(1)(i), (i)(2)(i), (i)(3)(i), (j)(1)(i), (j)(2)(i), or
(j)(3)(i). The owner or operator of an affected facility subject to
Sec. 60.43Da(i)(1)(i), (i)(2)(i), (i)(3)(i), (j)(1)(i), (j)(2)(i), or
(j)(3)(i) shall calculate SO2 emissions as 1.660 x
10-7 lb/scf-ppm times the average hourly SO2
output concentration in ppm (measured according to the provisions of
Sec. 60.49Da(b)), times the average hourly flow rate (measured
according to the provisions of Sec. 60.49Da(l) or Sec. 60.49Da(m)),
divided by the average hourly gross energy output (measured according
to the provisions of Sec. 60.49Da(k)). Alternatively, for oil-fired
and gas-fired units, SO2 emissions may be calculated by
multiplying the hourly SO2 emission rate (in lb/MMBtu),
measured by the CEMS required under Sec. 60.49Da, by the hourly heat
input rate (measured according to the provisions of Sec. 60.49Da(n)),
and dividing the result by the average gross energy output (measured
according to the provisions of Sec. 60.49Da(k)).
(n) Compliance provisions for sources subject to Sec.
60.42Da(c)(1). The owner or operator of an affected facility subject to
Sec. 60.42Da(c)(1) shall calculate PM emissions by multiplying the
average hourly PM output concentration, measured according to the
provisions of Sec. 60.49Da(t), by the average hourly flow rate,
measured according to the provisions of Sec. 60.49Da(l), and divided
by the average hourly gross energy output, measured according to the
provisions of Sec. 60.49Da(k). Compliance with the emission limit is
determined by calculating the arithmetic average of the hourly emission
rates computed for each boiler operating day.
(o) Compliance provisions for sources subject to Sec.
60.42Da(c)(2) or (d). Except as provided for in paragraph (p) of this
section, the owner or operator of an affected facility for which
construction, reconstruction, or modification commenced after February
28, 2005, shall demonstrate compliance with each applicable emission
limit according to the requirements in paragraphs (o)(1) through (o)(5)
of this section and use a COMS to demonstrate compliance with Sec.
60.42Da(b).
(1) You must conduct a performance test to demonstrate initial
compliance with the applicable PM emissions limit in 60.42Da(c)(2) or
(d) by the applicable date specified in Sec. 60.8(a). Thereafter, you
must conduct each subsequent performance test within 12 calendar months
of the date of the prior performance test. You must conduct each
performance test according to the requirements in Sec. 60.8 using the
test methods and procedures in Sec. 60.50Da.
(2) You must monitor the performance of each electrostatic
precipitator or fabric filter (baghouse) operated to comply with the
applicable PM emissions limit in Sec. 60.42Da(c)(2) or (d) using a
continuous opacity monitoring system (COMS) according to the
requirements in paragraphs (o)(2)(i) through (vi) unless you elect to
comply with one of the alternatives provided in paragraphs (o)(3) and
(o)(4) of this section, as applicable to your control device.
(i) Each COMS must meet Performance Specification 1 in 40 CFR part
60, appendix B.
(ii) You must comply with the quality assurance requirements in
paragraphs (o)(4)(ii)(A) through (E) of this section.
(A) You must automatically (intrinsic to the opacity monitor) check
the zero and upscale (span) calibration drifts at least once daily. For
a particular COMS, the acceptable range of zero and upscale calibration
materials is as defined in the applicable version of Performance
Specification 1 in 40 CFR part 60, appendix B.
(B) You must adjust the zero and span whenever the 24-hour zero
drift or 24-hour span drift exceeds 4 percent opacity. The COMS must
allow for the amount of excess zero and span drift measured at the 24-
hour interval checks to be recorded and quantified. The optical
surfaces exposed to the effluent gases must be cleaned prior to
performing the zero and span drift adjustments, except for systems
using automatic zero adjustments. For systems using automatic zero
adjustments, the optical surfaces must be cleaned when the cumulative
automatic zero compensation exceeds 4 percent opacity.
(C) You must apply a method for producing a simulated zero opacity
condition and an upscale (span) opacity condition using a certified
neutral density filter or other related technique to produce a known
obscuration of the light beam. All procedures applied must provide a
system check of the analyzer internal optical surfaces and all
electronic circuitry including the lamp and photodetector assembly.
(D) Except during periods of system breakdowns, repairs,
calibration checks, and zero and span adjustments, the COMS must be in
continuous operation and must complete a minimum of one cycle of
sampling and analyzing for each successive 10 second period and one
cycle of data recording for each successive 6-minute period.
(E) You must reduce all data from the COMS to 6-minute averages.
Six-minute opacity averages must be calculated from 36 or more data
points equally spaced over each 6-minute period. Data recorded during
periods of system breakdowns, repairs, calibration checks, and zero and
span adjustments must not be included in the data averages. An
arithmetic or integrated average of all data may be used.
(iii) During each performance test conducted according to paragraph
(o)(1) of this section, you must establish an opacity baseline level.
The value of the opacity baseline level is determined by averaging all
of the 6-minute average opacity values (reported to the nearest 0.1
percent opacity) from the COMS measurements recorded during each of the
test run intervals conducted for the performance test, and then adding
2.5 percent opacity to your calculated average opacity value for all of
the test runs. If your calculated average opacity value for all of the
test runs is less than 5.0 percent, then the opacity baseline level is
set at 5.0 percent.
(iv) You must evaluate the preceding 24-hour average opacity level
measured by the COMS each boiler operating day excluding periods of
affected source startup, shutdown, or malfunction. If the measured 24-
hour average opacity emission level is greater than the baseline
opacity level determined in paragraph (o)(2)(iii) of this section, you
must initiate investigation of the relevant equipment and control
systems within 24 hours of the first discovery of the high opacity
incident and take the appropriate corrective action as soon as
practicable to adjust control settings or repair equipment to reduce
the measured 24-hour average opacity to a level below the baseline
opacity level.
(v) You must record the opacity measurements, calculations
performed, and any corrective actions taken. The record of corrective
action taken must include the date and time during which the measured
24-hour average opacity was greater than baseline opacity level, and
the date, time, and description of the corrective action.
(vi) If the measured 24-hour average opacity for your affected
source remains at a level greater than the opacity baseline level after
7 days, then you must conduct a new PM performance test according to
paragraph (o)(1) of this section and establish a new opacity baseline
value according to paragraph (o)(2) of this section. This new
performance test must be conducted within 60 days of the date that the
[[Page 32733]]
measured 24-hour average opacity was first determined to exceed the
baseline opacity level unless a wavier is granted by the appropriate
delegated permitting authority.
(3) As an alternative to complying with the requirements of
paragraph (o)(2) of this section, an owner or operator may elect to
monitor the performance of an electrostatic precipitator (ESP) operated
to comply with the applicable PM emissions limit in Sec. 60.42Da(c)(2)
or (d) using an ESP predictive model developed in accordance with the
requirements in paragraphs (o)(3)(i) through (v) of this section.
(i) You must calibrate the ESP predictive model with each PM
control device used to comply with the applicable PM emissions limit in
Sec. 60.42Da(c)(2) or (d) operating under normal conditions. In cases
when a wet scrubber is used in combination with an ESP to comply with
the PM emissions limit, the daily average liquid-to-gas flow rate for
the wet scrubber must be maintained at 90 percent of average ratio
measured during all test run intervals for the performance test
conducted according to paragraph (o)(1) of this section.
(ii) You must develop a site-specific monitoring plan that includes
a description of the ESP predictive model used, the model input
parameters, and the procedures and criteria for establishing monitoring
parameter baseline levels indicative of compliance with the PM
emissions limit. You must submit the site-specific monitoring plan for
approval by the appropriate delegated permitting authority. For
reference purposes in preparing the monitoring plan, see the OAQPS
``Compliance Assurance Monitoring (CAM) Protocol for an Electrostatic
Precipitator (ESP) Controlling Particulate Matter (PM) Emissions from a
Coal-Fired Boiler.'' This document is available from the U.S.
Environmental Protection Agency (U.S. EPA); Office of Air Quality
Planning and Standards; Sector Policies and Programs Division;
Measurement Policy Group (D243-02), Research Triangle Park, NC 27711.
This document is also available on the Technology Transfer Network
(TTN) under Emission Measurement Center Continuous Emission Monitoring
.
(iii) You must run the ESP predictive model using the applicable
input data each boiler operating day and evaluate the model output for
the preceding boiler operating day excluding periods of affected source
startup, shutdown, or malfunction. If the values for one or more of the
model parameters exceed the applicable baseline levels determined
according to your approved site-specific monitoring plan, you must
initiate investigation of the relevant equipment and control systems
within 24 hours of the first discovery of a model parameter deviation
and, take the appropriate corrective action as soon as practicable to
adjust control settings or repair equipment to return the model output
to within the applicable baseline levels.
(iv) You must record the ESP predictive model inputs and outputs
and any corrective actions taken. The record of corrective action taken
must include the date and time during which the model output values
exceeded the applicable baseline levels, and the date, time, and
description of the corrective action.
(v) If after 7 consecutive days a model parameter continues to
exceed the applicable baseline level, then you must conduct a new PM
performance test according to paragraph (o)(1) of this section. This
new performance test must be conducted within 60 days of the date that
the model parameter was first determined to exceed its baseline level
unless a wavier is granted by the appropriate delegated permitting
authority.
(4) As an alternative to complying with the requirements of
paragraph (o)(2) of this section, an owner or operator may elect to
monitor the performance of a fabric filter (baghouse) operated to
comply with the applicable PM emissions limit in Sec. 60.42Da(c)(2) or
(d) by using a bag leak detection system according to the requirements
in paragraphs (o)(4)(i) through (v) of this section.
(i) Each bag leak detection system must meet the specifications and
requirements in paragraphs (o)(4)(i)(A) through (H) of this section.
(A) The bag leak detection system must be certified by the
manufacturer to be capable of detecting PM emissions at concentrations
of 1 milligram per actual cubic meter (0.00044 grains per actual cubic
foot) or less.
(B) The bag leak detection system sensor must provide output of
relative PM loadings. The owner or operator must continuously record
the output from the bag leak detection system using electronic or other
means (e.g., using a strip chart recorder or a data logger.)
(C) The bag leak detection system must be equipped with an alarm
system that will react when the system detects an increase in relative
particulate loading over the alarm set point established according to
paragraph (o)(4)(i)(D) of this section, and the alarm must be located
such that it can be noticed by the appropriate plant personnel.
(D) In the initial adjustment of the bag leak detection system, you
must establish, at a minimum, the baseline output by adjusting the
sensitivity (range) and the averaging period of the device, the alarm
set points, and the alarm delay time.
(E) Following initial adjustment, you must not adjust the averaging
period, alarm set point, or alarm delay time without approval from the
appropriate delegated permitting authority except as provided in
paragraph (d)(1)(vi) of this section.
(F) Once per quarter, you may adjust the sensitivity of the bag
leak detection system to account for seasonal effects, including
temperature and humidity, according to the procedures identified in the
site-specific monitoring plan required by paragraph (o)(4)(ii) of this
section.
(G) You must install the bag leak detection sensor downstream of
the fabric filter and upstream of any wet scrubber.
(H) Where multiple detectors are required, the system's
instrumentation and alarm may be shared among detectors.
(ii) You must develop and submit to the appropriate delegated
permitting authority for approval a site-specific monitoring plan for
each bag leak detection system. You must operate and maintain the bag
leak detection system according to the site-specific monitoring plan at
all times. Each monitoring plan must describe the items in paragraphs
(o)(4)(ii)(A) through (F) of this section.
(A) Installation of the bag leak detection system;
(B) Initial and periodic adjustment of the bag leak detection
system, including how the alarm set-point will be established;
(C) Operation of the bag leak detection system, including quality
assurance procedures;
(D) How the bag leak detection system will be maintained, including
a routine maintenance schedule and spare parts inventory list;
(E) How the bag leak detection system output will be recorded and
stored; and
(F) Corrective action procedures as specified in paragraph
(o)(4)(iii) of this section. In approving the site-specific monitoring
plan, the appropriate delegated permitting authority may allow owners
and operators more than 3 hours to alleviate a specific condition that
causes an alarm if the owner or operator identifies in the monitoring
plan this specific condition as one that could lead to an alarm,
adequately explains why it is not feasible to
[[Page 32734]]
alleviate this condition within 3 hours of the time the alarm occurs,
and demonstrates that the requested time will ensure alleviation of
this condition as expeditiously as practicable.
(iii) For each bag leak detection system, you must initiate
procedures to determine the cause of every alarm within 1 hour of the
alarm. Except as provided in paragraph (o)(4)(ii)(F) of this section,
you must alleviate the cause of the alarm within 3 hours of the alarm
by taking whatever corrective action(s) are necessary. Corrective
actions may include, but are not limited to the following:
(A) Inspecting the fabric filter for air leaks, torn or broken bags
or filter media, or any other condition that may cause an increase in
particulate emissions;
(B) Sealing off defective bags or filter media;
(C) Replacing defective bags or filter media or otherwise repairing
the control device;
(D) Sealing off a defective fabric filter compartment;
(E) Cleaning the bag leak detection system probe or otherwise
repairing the bag leak detection system; or
(F) Shutting down the process producing the particulate emissions.
(iv) You must maintain records of the information specified in
paragraphs (o)(4)(iv)(A) through (C) of this section for each bag leak
detection system.
(A) Records of the bag leak detection system output;
(B) Records of bag leak detection system adjustments, including the
date and time of the adjustment, the initial bag leak detection system
settings, and the final bag leak detection system settings; and
(C) The date and time of all bag leak detection system alarms, the
time that procedures to determine the cause of the alarm were
initiated, if procedures were initiated within 1 hour of the alarm, the
cause of the alarm, an explanation of the actions taken, the date and
time the cause of the alarm was alleviated, and if the alarm was
alleviated within 3 hours of the alarm.
(v) If after any period of composed of 30 boiler operating days
during which the alarm rate exceeds 5 percent of the process operating
time (excluding control device or process startup, shutdown, and
malfunction), then you must conduct a new PM performance test according
to paragraph (o)(1) of this section. This new performance test must be
conducted within 60 days of the date that the alarm rate was first
determined to exceed 5 percent limit unless a wavier is granted by the
appropriate delegated permitting authority.
(5) An owner or operator of a modified affected source electing to
meet the emission limitations in Sec. .42Da(d) shall determine the
percent reduction in PM by using the emission rate for PM determined by
the performance test conducted according to the requirements in
paragraph (o)(1) of this section and the ash content on a mass basis of
the fuel burned during each performance test run as determined by
analysis of the fuel as fired.
(p) As an alternative to meeting the compliance provisions
specified in paragraph (o) of this section, an owner or operator may
elect to install, certify, maintain, and operate a CEMS measuring PM
emissions discharged from the affected facility to the atmosphere and
record the output of the system as specified in paragraphs (p)(1)
through (p)(8) of this section.
(1) The owner or operator shall submit a written notification to
the Administrator of intent to demonstrate compliance with this subpart
by using a CEMS measuring PM. This notification shall be sent at least
30 calendar days before the initial startup of the monitor for
compliance determination purposes. The owner or operator may
discontinue operation of the monitor and instead return to
demonstration of compliance with this subpart according to the
requirements in paragraph (o) of this section by submitting written
notification to the Administrator of such intent at least 30 calendar
days before shutdown of the monitor for compliance determination
purposes.
(2) Each CEMS shall be installed, certified, operated, and
maintained according to the requirements in Sec. 60.49Da(v).
(3) The initial performance evaluation shall be completed no later
than 180 days after the date of initial startup of the affected
facility, as specified under Sec. 60.8 of subpart A of this part or
within 180 days of the date of notification to the Administrator
required under paragraph (p)(1) of this section, whichever is later.
(4) Compliance with the applicable emissions limit shall be
determined based on the 24-hour daily (block) average of the hourly
arithmetic average emissions concentrations using the continuous
monitoring system outlet data. The 24-hour block arithmetic average
emission concentration shall be calculated using EPA Reference Method
19 of appendix A of this part, section 4.1.
(5) At a minimum, valid CEMS hourly averages shall be obtained for
75 percent of all operating hours on a 30-day rolling average basis.
Beginning on January 1, 2012, valid CEMS hourly averages shall be
obtained for 90 percent of all operating hours on a 30-day rolling
average basis.
(i) At least two data points per hour shall be used to calculate
each 1-hour arithmetic average.
(ii) [Reserved]
(6) The 1-hour arithmetic averages required shall be expressed in
ng/J, MMBtu/hr, or lb/MWh and shall be used to calculate the boiler
operating day daily arithmetic average emission concentrations. The 1-
hour arithmetic averages shall be calculated using the data points
required under Sec. 60.13(e)(2) of subpart A of this part.
(7) All valid CEMS data shall be used in calculating average
emission concentrations even if the minimum CEMS data requirements of
paragraph (j)(5) of this section are not met.
(8) When PM emissions data are not obtained because of CEMS
breakdowns, repairs, calibration checks, and zero and span adjustments,
emissions data shall be obtained by using other monitoring systems as
approved by the Administrator or EPA Reference Method 19 of appendix A
of this part to provide, as necessary, valid emissions data for a
minimum of 90 percent (only 75 percent is required prior to January 1,
2012) of all operating hours per 30-day rolling average.
Sec. 60.49Da Emission monitoring.
(a) Except as provided for in paragraphs (t) and (u) of this
section, the owner or operator of an affected facility, shall install,
calibrate, maintain, and operate a CEMS, and record the output of the
system, for measuring the opacity of emissions discharged to the
atmosphere. If opacity interference due to water droplets exists in the
stack (for example, from the use of an FGD system), the opacity is
monitored upstream of the interference (at the inlet to the FGD
system). If opacity interference is experienced at all locations (both
at the inlet and outlet of the SO2 control system),
alternate parameters indicative of the PM control system's performance
and/or good combustion are monitored (subject to the approval of the
Administrator).
(b) The owner or operator of an affected facility shall install,
calibrate, maintain, and operate a CEMS, and record the output of the
system, for measuring SO2 emissions, except where natural
gas is the only fuel combusted, as follows:
(1) Sulfur dioxide emissions are monitored at both the inlet and
outlet of the SO2 control device.
[[Page 32735]]
(2) For a facility that qualifies under the numerical limit
provisions of Sec. 60.43Da(d), (i), (j), or (k) SO2
emissions are only monitored as discharged to the atmosphere.
(3) An ``as fired'' fuel monitoring system (upstream of coal
pulverizers) meeting the requirements of Method 19 of appendix A of
this part may be used to determine potential SO2 emissions
in place of a continuous SO2 emission monitor at the inlet
to the SO2 control device as required under paragraph (b)(1)
of this section.
(4) If the owner or operator has installed and certified a
SO2 continuous emissions monitoring system (CEMS) according
to the requirements of Sec. 75.20(c)(1) of this chapter and appendix A
to part 75 of this chapter, and is continuing to meet the ongoing
quality assurance requirements of Sec. 75.21 of this chapter and
appendix B to part 75 of this chapter, that CEMS may be used to meet
the requirements of this section, provided that:
(i) A CO2 or O2 continuous monitoring system
is installed, calibrated, maintained and operated at the same location,
according to paragraph (d) of this section; and
(ii) For sources subject to an SO2 emission limit in lb/
MMBtu under Sec. 60.43Da:
(A) When relative accuracy testing is conducted, SO2
concentration data and CO2 (or O2) data are
collected simultaneously; and
(B) In addition to meeting the applicable SO2 and
CO2 (or O2) relative accuracy specifications in
Figure 2 of appendix B to part 75 of this chapter, the relative
accuracy (RA) standard in section 13.2 of Performance Specification 2
in appendix B to this part is met when the RA is calculated on a lb/
MMBtu basis; and
(iii) The reporting requirements of Sec. 60.51Da are met. The
SO2 and CO2 (or O2) data reported to
meet the requirements of Sec. 60.51Da shall not include substitute
data values derived from the missing data procedures in subpart D of
part 75 of this chapter, nor shall the SO2 data have been
bias adjusted according to the procedures of part 75 of this chapter.
(c)(1) The owner or operator of an affected facility shall install,
calibrate, maintain, and operate a CEMS, and record the output of the
system, for measuring NOX emissions discharged to the
atmosphere; or
(2) If the owner or operator has installed a NOX
emission rate CEMS to meet the requirements of part 75 of this chapter
and is continuing to meet the ongoing requirements of part 75 of this
chapter, that CEMS may be used to meet the requirements of this
section, except that the owner or operator shall also meet the
requirements of Sec. 60.51Da. Data reported to meet the requirements
of Sec. 60.51Da shall not include data substituted using the missing
data procedures in subpart D of part 75 of this chapter, nor shall the
data have been bias adjusted according to the procedures of part 75 of
this chapter.
(d) The owner or operator of an affected facility shall install,
calibrate, maintain, and operate a CEMS, and record the output of the
system, for measuring the O2 or carbon dioxide
(CO2) content of the flue gases at each location where
SO2 or NOX emissions are monitored. For affected
facilities subject to a lb/MMBtu SO2 emission limit under
Sec. 60.43Da, if the owner or operator has installed and certified a
CO2 or O2 monitoring system according to Sec.
75.20(c) of this chapter and Appendix A to part 75 of this chapter and
the monitoring system continues to meet the applicable quality-
assurance provisions of Sec. 75.21 of this chapter and appendix B to
part 75 of this chapter, that CEMS may be used together with the part
75 SO2 concentration monitoring system described in
paragraph (b) of this section, to determine the SO2 emission
rate in lb/MMBtu. SO2 data used to meet the requirements of
Sec. 60.51Da shall not include substitute data values derived from the
missing data procedures in subpart D of part 75 of this chapter, nor
shall the data have been bias adjusted according to the procedures of
part 75 of this chapter.
(e) The CEMS under paragraphs (b), (c), and (d) of this section are
operated and data recorded during all periods of operation of the
affected facility including periods of startup, shutdown, malfunction
or emergency conditions, except for CEMS breakdowns, repairs,
calibration checks, and zero and span adjustments.
(f)(1) For units that began construction, reconstruction, or
modification on or before February 28, 2005, the owner or operator
shall obtain emission data for at least 18 hours in at least 22 out of
30 successive boiler operating days. If this minimum data requirement
cannot be met with CEMS, the owner or operator shall supplement
emission data with other monitoring systems approved by the
Administrator or the reference methods and procedures as described in
paragraph (h) of this section.
(2) For units that began construction, reconstruction, or
modification after February 28, 2005, the owner or operator shall
obtain emission data for at least 90 percent of all operating hours for
each 30 successive boiler operating days. If this minimum data
requirement cannot be met with a CEMS, the owner or operator shall
supplement emission data with other monitoring systems approved by the
Administrator or the reference methods and procedures as described in
paragraph (h) of this section.
(g) The 1-hour averages required under paragraph Sec. 60.13(h) are
expressed in ng/J (lb/MMBtu) heat input and used to calculate the
average emission rates under Sec. 60.48Da. The 1-hour averages are
calculated using the data points required under Sec. 60.13(h)(2).
(h) When it becomes necessary to supplement CEMS data to meet the
minimum data requirements in paragraph (f) of this section, the owner
or operator shall use the reference methods and procedures as specified
in this paragraph. Acceptable alternative methods and procedures are
given in paragraph (j) of this section.
(1) Method 6 of appendix A of this part shall be used to determine
the SO2 concentration at the same location as the
SO2 monitor. Samples shall be taken at 60-minute intervals.
The sampling time and sample volume for each sample shall be at least
20 minutes and 0.020 dscm (0.71 dscf). Each sample represents a 1-hour
average.
(2) Method 7 of appendix A of this part shall be used to determine
the NOX concentration at the same location as the
NOX monitor. Samples shall be taken at 30-minute intervals.
The arithmetic average of two consecutive samples represents a 1-hour
average.
(3) The emission rate correction factor, integrated bag sampling
and analysis procedure of Method 3B of appendix A of this part shall be
used to determine the O2 or CO2 concentration at
the same location as the O2 or CO2 monitor.
Samples shall be taken for at least 30 minutes in each hour. Each
sample represents a 1-hour average.
(4) The procedures in Method 19 of appendix A of this part shall be
used to compute each 1-hour average concentration in ng/J (lb/MMBtu)
heat input.
(i) The owner or operator shall use methods and procedures in this
paragraph to conduct monitoring system performance evaluations under
Sec. 60.13(c) and calibration checks under Sec. 60.13(d). Acceptable
alternative methods and procedures are given in paragraph (j) of this
section.
(1) Methods 3B, 6, and 7 of appendix A of this part shall be used
to determine O2, SO2, and NOX
concentrations, respectively.
(2) SO2 or NOX (NO), as applicable, shall be
used for preparing the
[[Page 32736]]
calibration gas mixtures (in N2, as applicable) under
Performance Specification 2 of appendix B of this part.
(3) For affected facilities burning only fossil fuel, the span
value for a CEMS for measuring opacity is between 60 and 80 percent.
Span values for a CEMS measuring NOX shall be determined
using one of the following procedures:
(i) Except as provided under paragraph (i)(3)(ii) of this section,
NOX span values shall be determined as follows:
------------------------------------------------------------------------
Fossil fuel Span values for NOX (ppm)
------------------------------------------------------------------------
Gas................................. 500.
Liquid.............................. 500.
Solid............................... 1,000.
Combination......................... 500 (x + y) + 1,000z.
------------------------------------------------------------------------
Where:
x = Fraction of total heat input derived from gaseous fossil fuel,
y = Fraction of total heat input derived from liquid fossil fuel,
and
z = Fraction of total heat input derived from solid fossil fuel.
(ii) As an alternative to meeting the requirements of paragraph
(i)(3)(i) of this section, the owner or operator of an affected
facility may elect to use the NOX span values determined
according to section 2.1.2 in appendix A to part 75 of this chapter.
(4) All span values computed under paragraph (i)(3)(i) of this
section for burning combinations of fossil fuels are rounded to the
nearest 500 ppm. Span values computed under paragraph (i)(3)(ii) of
this section shall be rounded off according to section 2.1.2 in
appendix A to part 75 of this chapter.
(5) For affected facilities burning fossil fuel, alone or in
combination with non-fossil fuel and determining span values under
paragraph (i)(3)(i) of this section, the span value of the
SO2 CEMS at the inlet to the SO2 control device
is 125 percent of the maximum estimated hourly potential emissions of
the fuel fired, and the outlet of the SO2 control device is
50 percent of maximum estimated hourly potential emissions of the fuel
fired. For affected facilities determining span values under paragraph
(i)(3)(ii) of this section, SO2 span values shall be
determined according to section 2.1.1 in appendix A to part 75 of this
chapter.
(j) The owner or operator may use the following as alternatives to
the reference methods and procedures specified in this section:
(1) For Method 6 of appendix A of this part, Method 6A or 6B
(whenever Methods 6 and 3 or 3B of appendix A of this part data are
used) or 6C of appendix A of this part may be used. Each Method 6B of
appendix A of this part sample obtained over 24 hours represents 24 1-
hour averages. If Method 6A or 6B of appendix A of this part is used
under paragraph (i) of this section, the conditions under Sec.
60.48Da(d)(1) apply; these conditions do not apply under paragraph (h)
of this section.
(2) For Method 7 of appendix A of this part, Method 7A, 7C, 7D, or
7E of appendix A of this part may be used. If Method 7C, 7D, or 7E of
appendix A of this part is used, the sampling time for each run shall
be 1 hour.
(3) For Method 3 of appendix A of this part, Method 3A or 3B of
appendix A of this part may be used if the sampling time is 1 hour.
(4) For Method 3B of appendix A of this part, Method 3A of appendix
A of this part may be used.
(k) The procedures specified in paragraphs (k)(1) through (3) of
this section shall be used to determine gross output for sources
demonstrating compliance with the output-based standard under Sec.
60.44Da(d)(1).
(1) The owner or operator of an affected facility with electricity
generation shall install, calibrate, maintain, and operate a wattmeter;
measure gross electrical output in MWh on a continuous basis; and
record the output of the monitor.
(2) The owner or operator of an affected facility with process
steam generation shall install, calibrate, maintain, and operate meters
for steam flow, temperature, and pressure; measure gross process steam
output in joules per hour (or Btu per hour) on a continuous basis; and
record the output of the monitor.
(3) For affected facilities generating process steam in combination
with electrical generation, the gross energy output is determined from
the gross electrical output measured in accordance with paragraph
(k)(1) of this section plus 75 percent of the gross thermal output
(measured relative to ISO conditions) of the process steam measured in
accordance with paragraph (k)(2) of this section.
(l) The owner or operator of an affected facility demonstrating
compliance with an output-based standard under Sec. 60.42Da, Sec.
60.43Da, Sec. 60.44Da, or Sec. 60.45Da shall install, certify,
operate, and maintain a continuous flow monitoring system meeting the
requirements of Performance Specification 6 of appendix B of this part
and the CD assessment, RATA and reporting provisions of procedure 1 of
appendix F of this part, and record the output of the system, for
measuring the volumetric flow rate of exhaust gases discharged to the
atmosphere; or
(m) Alternatively, data from a continuous flow monitoring system
certified according to the requirements of Sec. 75.20(c) of this
chapter and appendix A to part 75 of this chapter, and continuing to
meet the applicable quality control and quality assurance requirements
of Sec. 75.21 of this chapter and appendix B to part 75 of this
chapter, may be used. Flow rate data reported to meet the requirements
of Sec. 60.51Da shall not include substitute data values derived from
the missing data procedures in subpart D of part 75 of this chapter,
nor shall the data have been bias adjusted according to the procedures
of part 75 of this chapter.
(n) Gas-fired and oil-fired units. The owner or operator of an
affected unit that qualifies as a gas-fired or oil-fired unit, as
defined in 40 CFR 72.2, may use, as an alternative to the requirements
specified in either paragraph (l) or (m) of this section, a fuel flow
monitoring system certified and operated according to the requirements
of appendix D of part 75 of this chapter.
(o) The owner or operator of a duct burner, as described in Sec.
60.41Da, which is subject to the NOX standards of Sec.
60.44Da(a)(1), (d)(1), or (e)(1) is not required to install or operate
a CEMS to measure NOX emissions; a wattmeter to measure
gross electrical output; meters to measure steam flow, temperature, and
pressure; and a continuous flow monitoring system to measure the flow
of exhaust gases discharged to the atmosphere.
(p) The owner or operator of an affected facility demonstrating
compliance with an Hg limit in Sec. 60.45Da shall install and operate
a CEMS to measure and record the concentration of Hg in the exhaust
gases from each stack according to the requirements in paragraphs
(p)(1) through (p)(3) of this section. Alternatively, for an affected
facility that is also subject to the requirements of subpart I of part
75 of this chapter, the owner or operator may install, certify,
maintain, operate and quality-assure the data from a Hg CEMS according
to Sec. 75.10 of this chapter and appendices A and B to part 75 of
this chapter, in lieu of following the procedures in paragraphs (p)(1)
through (p)(3) of this section.
(1) The owner or operator must install, operate, and maintain each
CEMS according to Performance Specification 12A in appendix B to this
part.
(2) The owner or operator must conduct a performance evaluation of
[[Page 32737]]
each CEMS according to the requirements of Sec. 60.13 and Performance
Specification 12A in appendix B to this part.
(3) The owner or operator must operate each CEMS according to the
requirements in paragraphs (p)(3)(i) through (iv) of this section.
(i) As specified in Sec. 60.13(e)(2), each CEMS must complete a
minimum of one cycle of operation (sampling, analyzing, and data
recording) for each successive 15-minute period.
(ii) The owner or operator must reduce CEMS data as specified in
Sec. 60.13(h).
(iii) The owner or operator shall use all valid data points
collected during the hour to calculate the hourly average Hg
concentration.
(iv) The owner or operator must record the results of each required
certification and quality assurance test of the CEMS.
(4) Mercury CEMS data collection must conform to paragraphs
(p)(4)(i) through (iv) of this section.
(i) For each calendar month in which the affected unit operates,
valid hourly Hg concentration data, stack gas volumetric flow rate
data, moisture data (if required), and electrical output data (i.e.,
valid data for all of these parameters) shall be obtained for at least
75 percent of the unit operating hours in the month.
(ii) Data reported to meet the requirements of this subpart shall
not include hours of unit startup, shutdown, or malfunction. In
addition, for an affected facility that is also subject to subpart I of
part 75 of this chapter, data reported to meet the requirements of this
subpart shall not include data substituted using the missing data
procedures in subpart D of part 75 of this chapter, nor shall the data
have been bias adjusted according to the procedures of part 75 of this
chapter.
(iii) If valid data are obtained for less than 75 percent of the
unit operating hours in a month, you must discard the data collected in
that month and replace the data with the mean of the individual monthly
emission rate values determined in the last 12 months. In the 12-month
rolling average calculation, this substitute Hg emission rate shall be
weighted according to the number of unit operating hours in the month
for which the data capture requirement of Sec. 60.49Da(p)(4)(i) was
not met.
(iv) Notwithstanding the requirements of paragraph (p)(4)(iii) of
this section, if valid data are obtained for less than 75 percent of
the unit operating hours in another month in that same 12-month rolling
average cycle, discard the data collected in that month and replace the
data with the highest individual monthly emission rate determined in
the last 12 months. In the 12-month rolling average calculation, this
substitute Hg emission rate shall be weighted according to the number
of unit operating hours in the month for which the data capture
requirement of Sec. 60.49Da(p)(4)(i) was not met.
(q) As an alternative to the CEMS required in paragraph (p) of this
section, the owner or operator may use a sorbent trap monitoring system
(as defined in Sec. 72.2 of this chapter) to monitor Hg concentration,
according to the procedures described in Sec. 75.15 of this chapter
and appendix K to part 75 of this chapter.
(r) For Hg CEMS that measure Hg concentration on a dry basis or for
sorbent trap monitoring systems, the emissions data must be corrected
for the stack gas moisture content. A certified continuous moisture
monitoring system that meets the requirements of Sec. 75.11(b) of this
chapter is acceptable for this purpose. Alternatively, the appropriate
default moisture value, as specified in Sec. 75.11(b) or Sec.
75.12(b) of this chapter, may be used.
(s) The owner or operator shall prepare and submit to the
Administrator for approval a unit-specific monitoring plan for each
monitoring system, at least 45 days before commencing certification
testing of the monitoring systems. The owner or operator shall comply
with the requirements in your plan. The plan must address the
requirements in paragraphs (s)(1) through (6) of this section.
(1) Installation of the CEMS sampling probe or other interface at a
measurement location relative to each affected process unit such that
the measurement is representative of the exhaust emissions (e.g., on or
downstream of the last control device);
(2) Performance and equipment specifications for the sample
interface, the pollutant concentration or parametric signal analyzer,
and the data collection and reduction systems;
(3) Performance evaluation procedures and acceptance criteria
(e.g., calibrations, relative accuracy test audits (RATA), etc.);
(4) Ongoing operation and maintenance procedures in accordance with
the general requirements of Sec. 60.13(d) or part 75 of this chapter
(as applicable);
(5) Ongoing data quality assurance procedures in accordance with
the general requirements of Sec. 60.13 or part 75 of this chapter (as
applicable); and
(6) Ongoing recordkeeping and reporting procedures in accordance
with the requirements of this subpart.
(t) The owner or operator of an affected facility demonstrating
compliance with the output-based emissions limitation under Sec.
60.42Da(c)(1) shall install, certify, operate, and maintain a CEMS for
measuring PM emissions according to the requirements of paragraph (v)
of this section. An owner or operator of an affected source
demonstrating compliance with the input-based emission limitation under
Sec. 60.42Da(c)(2) may install, certify, operate, and maintain a CEMS
for measuring PM emissions according to the requirements of paragraph
(v) of this section.
(u) An owner or operator of an affected source that meets the
conditions in either paragraph (u)(1), (2) or (3) of this section is
exempted from the continuous opacity monitoring system requirements in
paragraph (a) of this section and the monitoring requirements in Sec.
60.48Da(o).
(1) A CEMS for measuring PM emissions is used to demonstrate
continuous compliance on a boiler operating day average with the
emissions limitations under Sec. 60.42Da(a)(1) or Sec. 60.42Da(c)(2)
and is installed, certified, operated, and maintained on the affected
source according to the requirements of paragraph (v) of this section;
or
(2) The affected source burns only gaseous fuels and does not use a
post-combustion technology to reduce emissions of SO2 or PM;
or
(3) The affected source does not use post-combustion technology
(except a wet scrubber) for reducing PM, SO2, or carbon
monoxide (CO) emissions, burns only natural gas, gaseous fuels, or fuel
oils that contain less than or equal to 0.30 weight percent sulfur, and
is operated such that emissions of CO to the atmosphere from the
affected source are maintained at levels less than or equal to 1.4 lb/
MWh on a boiler operating day average basis. Owners and operators of
affected sources electing to comply with this paragraph must
demonstrate compliance according to the procedures specified in
paragraphs (u)(3)(i) through (iv) of this section.
(i) You must monitor CO emissions using a CEMS according to the
procedures specified in paragraphs (u)(3)(i)(A) through (D) of this
section.
(A) The CO CEMS must be installed, certified, maintained, and
operated according to the provisions in Sec. 60.58b(i)(3) of subpart
Eb of this part.
(B) Each 1-hour CO emissions average is calculated using the data
points generated by the CO CEMS expressed in parts per million by
volume corrected to 3 percent oxygen (dry basis).
[[Page 32738]]
(C) At a minimum, valid 1-hour CO emissions averages must be
obtained for at least 90 percent of the operating hours on a 30-day
rolling average basis. At least two data points per hour must be used
to calculate each 1-hour average.
(D) Quarterly accuracy determinations and daily calibration drift
tests for the CO CEMS must be performed in accordance with procedure 1
in appendix F of this part.
(ii) You must calculate the 1-hour average CO emissions levels for
each boiler operating day by multiplying the average hourly CO output
concentration measured by the CO CEMS times the corresponding average
hourly flue gas flow rate and divided by the corresponding average
hourly useful energy output from the affected source. The 24-hour
average CO emission level is determined by calculating the arithmetic
average of the hourly CO emission levels computed for each boiler
operating day.
(iii) You must evaluate the preceding 24-hour average CO emission
level each boiler operating day excluding periods of affected source
startup, shutdown, or malfunction. If the 24-hour average CO emission
level is greater than 1.4 lb/MWh, you must initiate investigation of
the relevant equipment and control systems within 24 hours of the first
discovery of the high emission incident and, take the appropriate
corrective action as soon as practicable to adjust control settings or
repair equipment to reduce the 24-hour average CO emission level to 1.4
lb/MWh or less.
(iv) You must record the CO measurements and calculations performed
according to paragraph (u)(3) of this section and any corrective
actions taken. The record of corrective action taken must include the
date and time during which the 24-hour average CO emission level was
greater than 1.4 lb/MWh, and the date, time, and description of the
corrective action.
(v) The owner or operator of an affected facility using a CEMS
measuring PM emissions to meet requirements of this subpart shall
install, certify, operate, and maintain the CEMS as specified in
paragraphs (v)(1) through (v)(3).
(1) The owner or operator shall conduct a performance evaluation of
the CEMS according to the applicable requirements of Sec. 60.13,
Performance Specification 11 in appendix B of this part, and procedure
2 in appendix F of this part.
(2) During each relative accuracy test run of the CEMS required by
Performance Specification 11 in appendix B of this part, PM and
O2 (or CO2) data shall be collected concurrently
(or within a 30-to 60-minute period) by both the CEMS and conducting
performance tests using the following test methods.
(i) For PM, EPA Reference Method 5, 5B, or 17 of appendix A of this
part shall be used.
(ii) For O2 (or CO2), EPA Reference Method 3,
3A, or 3B of appendix A of this part, as applicable shall be used.
(3) Quarterly accuracy determinations and daily calibration drift
tests shall be performed in accordance with procedure 2 in appendix F
of this part. Relative Response Audit's must be performed annually and
Response Correlation Audits must be performed every 3 years.
(w)(1) Except as provided for under paragraphs (w)(2), (w)(3), and
(w)(4) of this section, the SO2, NOX,
CO2, and O2 CEMS required under paragraphs (b)
through (d) of this section shall be installed, certified, and operated
in accordance with the applicable procedures in Performance
Specification 2 or 3 in appendix B to this part or according to the
procedures in appendices A and B to part 75 of this chapter. Daily
calibration drift assessments and quarterly accuracy determinations
shall be done in accordance with Procedure 1 in appendix F to this
part, and a data assessment report (DAR), prepared according to section
7 of Procedure 1 in appendix F to this part, shall be submitted with
each compliance report required under Sec. 60.51Da., the owner or
operator may elect to implement the following alternative data accuracy
assessment procedures:
(2) As an alternative to meeting the requirements of paragraph
(w)(1) of this section, an owner or operator may elect to may elect to
implement the following alternative data accuracy assessment
procedures. For all required CO2 and O2 CEMS and
for SO2 and NOX CEMS with span values greater
than 100 ppm, the daily calibration error test and calibration
adjustment procedures described in sections 2.1.1 and 2.1.3 of appendix
B to part 75 of this chapter may be followed instead of the CD
assessment procedures in Procedure 1, section 4.1 of appendix F of this
part. If this option is selected, the data validation and out-of-
control provisions in sections 2.1.4 and 2.1.5 of appendix B to part 75
of this chapter shall be followed instead of the excessive CD and out-
of-control criteria in Procedure 1, section 4.3 of appendix F to this
part. For the purposes of data validation under this subpart, the
excessive CD and out-of-control criteria in Procedure 1, section 4.3 of
appendix F to this part shall apply to SO2 and
NOX span values less than 100 ppm;
(3) As an alternative to meeting the requirements of paragraph
(w)(1) of this section, an owner or operator may elect to may elect to
implement the following alternative data accuracy assessment
procedures. For all required CO2 and O2 CEMS and
for SO2 and NOX CEMS with span values greater
than 30 ppm, quarterly linearity checks may be performed in accordance
with section 2.2.1 of appendix B to part 75 of this chapter, instead of
performing the cylinder gas audits (CGAs) described in Procedure 1,
section 5.1.2 of appendix F to this part. If this option is selected:
The frequency of the linearity checks shall be as specified in section
2.2.1 of appendix B to part 75 of this chapter; the applicable
linearity specifications in section 3.2 of appendix A to part 75 of
this chapter shall be met; the data validation and out-of-control
criteria in section 2.2.3 of appendix B to part 75 of this chapter
shall be followed instead of the excessive audit inaccuracy and out-of-
control criteria in Procedure 1, section 5.2 of appendix F to this
part; and the grace period provisions in section 2.2.4 of appendix B to
part 75 of this chapter shall apply. For the purposes of data
validation under this subpart, the cylinder gas audits described in
Procedure 1, section 5.1.2 of appendix F to this part shall be
performed for SO2 and NOX span values less than
or equal to 30 ppm;
(4) As an alternative to meeting the requirements of paragraph
(w)(1) of this section, an owner or operator may elect to may elect to
implement the following alternative data accuracy assessment
procedures. For SO2, CO2, and O2 CEMS
and for NOX CEMS, RATAs may be performed in accordance with
section 2.3 of appendix B to part 75 of this chapter instead of
following the procedures described in Procedure 1, section 5.1.1 of
appendix F to this part. If this option is selected: The frequency of
each RATA shall be as specified in section 2.3.1 of appendix B to part
75 of this chapter; the applicable relative accuracy specifications
shown in Figure 2 in appendix B to part 75 of this chapter shall be
met; the data validation and out-of-control criteria in section 2.3.2
of appendix B to part 75 of this chapter shall be followed instead of
the excessive audit inaccuracy and out-of-control criteria in Procedure
1, section 5.2 of appendix F to this part; and the grace period
provisions in section 2.3.3 of appendix B to part 75 of this chapter
shall apply. For the purposes of data validation under this subpart,
the relative accuracy specification in section 13.2 of Performance
[[Page 32739]]
Specification 2 in appendix B to this part shall be met on a lb/MMBtu
basis for SO2 (regardless of the SO2 emission
level during the RATA), and for NOX when the average
NOX emission rate measured by the reference method during
the RATA is less than 0.100 lb/MMBtu;
(5) If the owner or operator elects to implement the alternative
data assessment procedures described in paragraphs (w)(2) through
(w)(4) of this section, each data assessment report shall include a
summary of the results of all of the RATAs, linearity checks, CGAs, and
calibration error or drift assessments required by paragraphs (w)(2)
through (w)(4) of this section.
Sec. 60.50Da Compliance determination procedures and methods.
(a) In conducting the performance tests required in Sec. 60.8, the
owner or operator shall use as reference methods and procedures the
methods in appendix A of this part or the methods and procedures as
specified in this section, except as provided in Sec. 60.8(b). Section
60.8(f) does not apply to this section for SO2 and
NOX. Acceptable alternative methods are given in paragraph
(e) of this section.
(b) The owner or operator shall determine compliance with the PM
standards in Sec. 60.42Da as follows:
(1) The dry basis F factor (O2) procedures in Method 19
of appendix A of this part shall be used to compute the emission rate
of PM.
(2) For the particular matter concentration, Method 5 of appendix A
of this part shall be used at affected facilities without wet FGD
systems and Method 5B of appendix A of this part shall be used after
wet FGD systems.
(i) The sampling time and sample volume for each run shall be at
least 120 minutes and 1.70 dscm (60 dscf). The probe and filter holder
heating system in the sampling train may be set to provide an average
gas temperature of no greater than 16014 [deg]C (32025 [deg]F).
(ii) For each particulate run, the emission rate correction factor,
integrated or grab sampling and analysis procedures of Method 3B of
appendix A of this part shall be used to determine the O2
concentration. The O2 sample shall be obtained
simultaneously with, and at the same traverse points as, the
particulate run. If the particulate run has more than 12 traverse
points, the O2 traverse points may be reduced to 12 provided
that Method 1 of appendix A of this part is used to locate the 12
O2 traverse points. If the grab sampling procedure is used,
the O2 concentration for the run shall be the arithmetic
mean of the sample O2 concentrations at all traverse points.
(3) Method 9 of appendix A of this part and the procedures in Sec.
60.11 shall be used to determine opacity.
(c) The owner or operator shall determine compliance with the
SO2 standards in Sec. 60.43Da as follows:
(1) The percent of potential SO2 emissions (%Ps) to the
atmosphere shall be computed using the following equation:
[GRAPHIC] [TIFF OMITTED] TR13JN07.015
Where:
%Ps = Percent of potential SO2 emissions, percent;
%Rf = Percent reduction from fuel pretreatment, percent; and
%Rg = Percent reduction by SO2 control system, percent.
(2) The procedures in Method 19 of appendix A of this part may be
used to determine percent reduction (%Rf) of sulfur by such
processes as fuel pretreatment (physical coal cleaning,
hydrodesulfurization of fuel oil, etc.), coal pulverizers, and bottom
and fly ash interactions. This determination is optional.
(3) The procedures in Method 19 of appendix A of this part shall be
used to determine the percent SO2 reduction (%Rg)
of any SO2 control system. Alternatively, a combination of
an ``as fired'' fuel monitor and emission rates measured after the
control system, following the procedures in Method 19 of appendix A of
this part, may be used if the percent reduction is calculated using the
average emission rate from the SO2 control device and the
average SO2 input rate from the ``as fired'' fuel analysis
for 30 successive boiler operating days.
(4) The appropriate procedures in Method 19 of appendix A of this
part shall be used to determine the emission rate.
(5) The CEMS in Sec. 60.49Da(b) and (d) shall be used to determine
the concentrations of SO2 and CO2 or
O2.
(d) The owner or operator shall determine compliance with the
NOX standard in Sec. 60.44Da as follows:
(1) The appropriate procedures in Method 19 of appendix A of this
part shall be used to determine the emission rate of NOX.
(2) The continuous monitoring system in Sec. 60.49Da(c) and (d)
shall be used to determine the concentrations of NOX and
CO2 or O2.
(e) The owner or operator may use the following as alternatives to
the reference methods and procedures specified in this section:
(1) For Method 5 or 5B of appendix A of this part, Method 17 of
appendix A of this part may be used at facilities with or without wet
FGD systems if the stack temperature at the sampling location does not
exceed an average temperature of 160 [deg]C (320 [deg]F). The
procedures of Sec. Sec. 2.1 and 2.3 of Method 5B of appendix A of this
part may be used in Method 17 of appendix A of this part only if it is
used after wet FGD systems. Method 17 of appendix A of this part shall
not be used after wet FGD systems if the effluent is saturated or laden
with water droplets.
(2) The Fc factor (CO2) procedures in Method
19 of appendix A of this part may be used to compute the emission rate
of PM under the stipulations of Sec. 60.46(d)(1). The CO2
shall be determined in the same manner as the O2
concentration.
(f) Electric utility combined cycle gas turbines are performance
tested for PM, SO2, and NOX using the procedures
of Method 19 of appendix A of this part. The SO2 and
NOX emission rates from the gas turbine used in Method 19 of
appendix A of this part calculations are determined when the gas
turbine is performance tested under subpart GG of this part. The
potential uncontrolled PM emission rate from a gas turbine is defined
as 17 ng/J (0.04 lb/MMBtu) heat input.
(g) For the purposes of determining compliance with the emission
limits in Sec. 60.45Da, the owner or operator of an electric utility
steam generating unit which is also a cogeneration unit shall use the
procedures in paragraphs (g)(1) and (2) of this section to calculate
emission rates based on electrical output to the grid plus 75 percent
of the equivalent electrical energy (measured relative to ISO
conditions) in the unit's process stream.
(1) All conversions from Btu/hr unit input to MW unit output must
use equivalents found in 40 CFR 60.40(a)(1) for electric utilities
(i.e., 250 MMBtu/hr input to an electric utility steam generating unit
is equivalent to 73 MW input to the electric utility steam generating
unit); 73 MW input to the electric utility steam generating unit is
equivalent to 25 MW output from the boiler electric utility steam
generating unit; therefore, 250 MMBtu input to the electric utility
steam generating unit is equivalent to 25 MW output from the electric
utility steam generating unit).
(2) Use the Equation 5 in this section to determine the
cogeneration Hg emission rate over a specific compliance period.
[[Page 32740]]
[GRAPHIC] [TIFF OMITTED] TR13JN07.016
Where:
ERcogen = Cogeneration Hg emission rate over a compliance
period in lb/MWh;
E = Mass of Hg emitted from the stack over the same compliance
period (lb);
Vgrid = Amount of energy sent to the grid over the same
compliance period (MWh); and
Vprocess = Amount of energy converted to steam for
process use over the same compliance period (MWh).
(h) The owner or operator shall determine compliance with the Hg
limit in Sec. 60.45Da according to the procedures in paragraphs (h)(1)
through (3) of this section.
(1) The initial performance test shall be commenced by the
applicable date specified in Sec. 60.8(a). The required CEMS must be
certified prior to commencing the test. The performance test consists
of collecting hourly Hg emission data (lb/MWh) with the CEMS for 12
successive months of unit operation (excluding hours of unit startup,
shutdown and malfunction). The average Hg emission rate is calculated
for each month, and then the weighted, 12-month average Hg emission
rate is calculated according to paragraph (h)(2) or (h)(3) of this
section, as applicable. If, for any month in the initial performance
test, the minimum data capture requirement in Sec. 60.49Da(p)(4)(i) is
not met, the owner or operator shall report a substitute Hg emission
rate for that month, as follows. For the first such month, the
substitute monthly Hg emission rate shall be the arithmetic average of
all valid hourly Hg emission rates recorded to date. For any subsequent
month(s) with insufficient data capture, the substitute monthly Hg
emission rate shall be the highest valid hourly Hg emission rate
recorded to date. When the 12-month average Hg emission rate for the
initial performance test is calculated, for each month in which there
was insufficient data capture, the substitute monthly Hg emission rate
shall be weighted according to the number of unit operating hours in
that month. Following the initial performance test, the owner or
operator shall demonstrate compliance by calculating the weighted
average of all monthly Hg emission rates (in lb/MWh) for each 12
successive calendar months, excluding data obtained during startup,
shutdown, or malfunction.
(2) If a CEMS is used to demonstrate compliance, follow the
procedures in paragraphs (h)(2)(i) through (iii) of this section to
determine the 12-month rolling average.
(i) Calculate the total mass of Hg emissions over a month (M), in
lb, using either Equation 6 in paragraph (h)(2)(i)(A) of this section
or Equation 7 in paragraph (h)(2)(i)(B) of this section, in conjunction
with Equation 8 in paragraph (h)(2)(i)(C) of this section.
(A) If the Hg CEMS measures Hg concentration on a wet basis, use
Equation 6 below to calculate the Hg mass emissions for each valid
hour:
[GRAPHIC] [TIFF OMITTED] TR13JN07.017
Where:
Eh = Hg mass emissions for the hour, (lb);
K = Units conversion constant, 6.24 x 10-\11\ lb-scm/
[mu]gm-scf;
Ch = Hourly Hg concentration, wet basis,
([mu]gm/scm);
Qh = Hourly stack gas volumetric flow rate, (scfh); and
th = Unit operating time, i.e., the fraction of the hour
for which the unit operated. For example, th = 0.50 for a half-hour
of unit operation and 1.00 for a full hour of operation.
(B) If the Hg CEMS measures Hg concentration on a dry basis, use
Equation 7 below to calculate the Hg mass emissions for each valid
hour:
[GRAPHIC] [TIFF OMITTED] TR13JN07.018
Where:
Eh = Hg mass emissions for the hour, (lb);
K = Units conversion constant, 6.24 x 10-11 lb-scm/
[mu]gm-scf;
Ch = Hourly Hg concentration, dry basis, ([mu]gm/dscm);
Qh = Hourly stack gas volumetric flow rate, (scfh);
th = Unit operating time, i.e., the fraction of the hour
for which the unit operated; and
Bws = Stack gas moisture content, expressed as a decimal
fraction (e.g., for 8 percent H2O, Bws =
0.08).
(C) Use Equation 8, below, to calculate M, the total mass of Hg
emitted for the month, by summing the hourly masses derived from
Equation 6 or 7 (as applicable):
[GRAPHIC] [TIFF OMITTED] TR13JN07.019
Where:M = Total Hg mass emissions for the month, (lb);
Eh = Hg mass emissions for hour ``h'', from Equation 6 or
7 of this section, (lb); and
n = Number of unit operating hours in the month with valid CE and
electrical output data, excluding hours of unit startup, shutdown
and malfunction.
(ii) Calculate the monthly Hg emission rate on an output basis (lb/
MWh) using Equation 9, below. For a cogeneration unit, use Equation 5
in paragraph (g) of this section instead.
[GRAPHIC] [TIFF OMITTED] TR13JN07.020
Where:
ER = Monthly Hg emission rate, (lb/MWh);
M = Total mass of Hg emissions for the month, from Equation 8,
above, (lb); and
P = Total electrical output for the month, for the hours used to
calculate M, (MWh).
(iii) Until 12 monthly Hg emission rates have been accumulated,
calculate and report only the monthly averages. Then, for each
subsequent calendar month, use Equation 10 below to calculate the 12-
month rolling average as a weighted average of the Hg emission rate for
the current month and the Hg emission rates for the previous 11 months,
with one exception. Calendar months in which the unit does not operate
(zero unit operating hours) shall not be included in the 12-month
rolling average.
[GRAPHIC] [TIFF OMITTED] TR13JN07.021
Where:
Eavg = Weighted 12-month rolling average Hg emission
rate, (lb/MWh);
ERi = Monthly Hg emission rate, for month ``i'', (lb/
MWh); and
n = Number of unit operating hours in month ``i'' with valid CEM and
electrical output data, excluding hours of unit startup, shutdown,
and malfunction.
(3) If a sorbent trap monitoring system is used in lieu of a Hg
CEMS, as described in Sec. 75.15 of this chapter and in appendix K to
part 75 of this chapter, calculate the monthly Hg emission rates using
Equations 7 through 9 of this section, except that for a particular
pair of sorbent traps, Ch in Equation 7 shall be the flow-
proportional average Hg concentration measured over the data collection
period.
(i) Daily calibration drift (CD) tests and quarterly accuracy
determinations shall be performed for Hg CEMS in accordance with
Procedure 1 of appendix F to this part. For the CD assessments, you may
use either elemental mercury or mercuric chloride (Hg[deg]
HgCl2) standards. The four
[[Page 32741]]
quarterly accuracy determinations shall consist of one RATA and three
measurement error (ME) tests using HgCl2 standards, as
described in section 8.3 of Performance Specification 12-A in appendix
B to this part (note: Hg[deg] standards may be used if the Hg monitor
does not have a converter). Alternatively, the owner or operator may
implement the applicable daily, weekly, quarterly, and annual quality
assurance (QA) requirements for Hg CEMS in appendix B to part 75 of
this chapter, in lieu of the QA procedures in appendices B and F to
this part. Annual RATA of sorbent trap monitoring systems shall be
performed in accordance with appendices A and B to part 75 of this
chapter, and all other quality assurance requirements specified in
appendix K to part 75 of this chapter shall be met for sorbent trap
monitoring systems.
Sec. 60.51Da Reporting requirements.
(a) For SO2, NOX, PM, and Hg emissions, the
performance test data from the initial and subsequent performance test
and from the performance evaluation of the continuous monitors
(including the transmissometer) are submitted to the Administrator.
(b) For SO2 and NOX the following information
is reported to the Administrator for each 24-hour period.
(1) Calendar date.
(2) The average SO2 and NOX emission rates
(ng/J or lb/MMBtu) for each 30 successive boiler operating days, ending
with the last 30-day period in the quarter; reasons for non-compliance
with the emission standards; and, description of corrective actions
taken.
(3) Percent reduction of the potential combustion concentration of
SO2 for each 30 successive boiler operating days, ending
with the last 30-day period in the quarter; reasons for non-compliance
with the standard; and, description of corrective actions taken.
(4) Identification of the boiler operating days for which pollutant
or diluent data have not been obtained by an approved method for at
least 75 percent of the hours of operation of the facility;
justification for not obtaining sufficient data; and description of
corrective actions taken.
(5) Identification of the times when emissions data have been
excluded from the calculation of average emission rates because of
startup, shutdown, malfunction (NOX only), emergency
conditions (SO2 only), or other reasons, and justification
for excluding data for reasons other than startup, shutdown,
malfunction, or emergency conditions.
(6) Identification of ``F'' factor used for calculations, method of
determination, and type of fuel combusted.
(7) Identification of times when hourly averages have been obtained
based on manual sampling methods.
(8) Identification of the times when the pollutant concentration
exceeded full span of the CEMS.
(9) Description of any modifications to CEMS which could affect the
ability of the CEMS to comply with Performance Specifications 2 or 3.
(c) If the minimum quantity of emission data as required by Sec.
60.49Da is not obtained for any 30 successive boiler operating days,
the following information obtained under the requirements of Sec.
60.48Da(h) is reported to the Administrator for that 30-day period:
(1) The number of hourly averages available for outlet emission
rates (no) and inlet emission rates (ni) as applicable.
(2) The standard deviation of hourly averages for outlet emission
rates (so) and inlet emission rates (si) as
applicable.
(3) The lower confidence limit for the mean outlet emission rate
(Eo*) and the upper confidence limit for the mean inlet
emission rate (Ei*) as applicable.
(4) The applicable potential combustion concentration.
(5) The ratio of the upper confidence limit for the mean outlet
emission rate (Eo*) and the allowable emission rate
(Estd) as applicable.
(d) If any standards under Sec. 60.43Da are exceeded during
emergency conditions because of control system malfunction, the owner
or operator of the affected facility shall submit a signed statement:
(1) Indicating if emergency conditions existed and requirements
under Sec. 60.48Da(d) were met during each period, and
(2) Listing the following information:
(i) Time periods the emergency condition existed;
(ii) Electrical output and demand on the owner or operator's
electric utility system and the affected facility;
(iii) Amount of power purchased from interconnected neighboring
utility companies during the emergency period;
(iv) Percent reduction in emissions achieved;
(v) Atmospheric emission rate (ng/J) of the pollutant discharged;
and
(vi) Actions taken to correct control system malfunction.
(e) If fuel pretreatment credit toward the SO2 emission
standard under Sec. 60.43Da is claimed, the owner or operator of the
affected facility shall submit a signed statement:
(1) Indicating what percentage cleaning credit was taken for the
calendar quarter, and whether the credit was determined in accordance
with the provisions of Sec. 60.50Da and Method 19 of appendix A of
this part; and
(2) Listing the quantity, heat content, and date each pretreated
fuel shipment was received during the previous quarter; the name and
location of the fuel pretreatment facility; and the total quantity and
total heat content of all fuels received at the affected facility
during the previous quarter.
(f) For any periods for which opacity, SO2 or
NOX emissions data are not available, the owner or operator
of the affected facility shall submit a signed statement indicating if
any changes were made in operation of the emission control system
during the period of data unavailability. Operations of the control
system and affected facility during periods of data unavailability are
to be compared with operation of the control system and affected
facility before and following the period of data unavailability.
(g) For Hg, the following information shall be reported to the
Administrator:
(1) Company name and address;
(2) Date of report and beginning and ending dates of the reporting
period;
(3) The applicable Hg emission limit (lb/MWh); and
(4) For each month in the reporting period:
(i) The number of unit operating hours;
(ii) The number of unit operating hours with valid data for Hg
concentration, stack gas flow rate, moisture (if required), and
electrical output;
(iii) The monthly Hg emission rate (lb/MWh);
(iv) The number of hours of valid data excluded from the
calculation of the monthly Hg emission rate, due to unit startup,
shutdown and malfunction; and
(v) The 12-month rolling average Hg emission rate (lb/MWh); and
(5) The data assessment report (DAR) required by appendix F to this
part, or an equivalent summary of QA test results if the QA of part 75
of this chapter are implemented.
(h) The owner or operator of the affected facility shall submit a
signed statement indicating whether:
(1) The required CEMS calibration, span, and drift checks or other
periodic audits have or have not been performed as specified.
(2) The data used to show compliance was or was not obtained in
accordance with approved methods and procedures
[[Page 32742]]
of this part and is representative of plant performance.
(3) The minimum data requirements have or have not been met; or,
the minimum data requirements have not been met for errors that were
unavoidable.
(4) Compliance with the standards has or has not been achieved
during the reporting period.
(i) For the purposes of the reports required under Sec. 60.7,
periods of excess emissions are defined as all 6-minute periods during
which the average opacity exceeds the applicable opacity standards
under Sec. 60.42Da(b). Opacity levels in excess of the applicable
opacity standard and the date of such excesses are to be submitted to
the Administrator each calendar quarter.
(j) The owner or operator of an affected facility shall submit the
written reports required under this section and subpart A to the
Administrator semiannually for each six-month period. All semiannual
reports shall be postmarked by the 30th day following the end of each
six-month period.
(k) The owner or operator of an affected facility may submit
electronic quarterly reports for SO2 and/or NOX
and/or opacity and/or Hg in lieu of submitting the written reports
required under paragraphs (b), (g), and (i) of this section. The format
of each quarterly electronic report shall be coordinated with the
permitting authority. The electronic report(s) shall be submitted no
later than 30 days after the end of the calendar quarter and shall be
accompanied by a certification statement from the owner or operator,
indicating whether compliance with the applicable emission standards
and minimum data requirements of this subpart was achieved during the
reporting period. Before submitting reports in the electronic format,
the owner or operator shall coordinate with the permitting authority to
obtain their agreement to submit reports in this alternative format.
Sec. 60.52Da Recordkeeping requirements.
The owner or operator of an affected facility subject to the
emissions limitations in Sec. 60.45Da shall provide notifications in
accordance with Sec. 60.7(a) and shall maintain records of all
information needed to demonstrate compliance including performance
tests, monitoring data, fuel analyses, and calculations, consistent
with the requirements of Sec. 60.7(f).
Subpart Db--[Amended]
0
5. Subpart Db is revised to read as follows
Subpart Db--Standards of Performance for Industrial-Commercial-
Institutional Steam Generating Units
Sec.
60.40b Applicability and delegation of authority.
60.41b Definitions.
60.42b Standard for sulfur dioxide (SO2).
60.43b Standard for particulate matter (PM).
60.44b Standard for nitrogen oxides (NOX).
60.45b Compliance and performance test methods and procedures for
sulfur dioxide.
60.46b Compliance and performance test methods and procedures for
particulate matter and nitrogen oxides.
60.47b Emission monitoring for sulfur dioxide.
60.48b Emission monitoring for particulate matter and nitrogen
oxides.
60.49b Reporting and recordkeeping requirements.
Subpart Db--Standards of Performance for Industrial-Commercial-
Institutional Steam Generating Units
Sec. 60.40b Applicability and delegation of authority.
(a) The affected facility to which this subpart applies is each
steam generating unit that commences construction, modification, or
reconstruction after June 19, 1984, and that has a heat input capacity
from fuels combusted in the steam generating unit of greater than 29
megawatts (MW) (100 million British thermal units per hour (MMBtu/hr)).
(b) Any affected facility meeting the applicability requirements
under paragraph (a) of this section and commencing construction,
modification, or reconstruction after June 19, 1984, but on or before
June 19, 1986, is subject to the following standards:
(1) Coal-fired affected facilities having a heat input capacity
between 29 and 73 MW (100 and 250 MMBtu/hr), inclusive, are subject to
the particulate matter (PM) and nitrogen oxides (NOX)
standards under this subpart.
(2) Coal-fired affected facilities having a heat input capacity
greater than 73 MW (250 MMBtu/hr) and meeting the applicability
requirements under subpart D (Standards of performance for fossil-fuel-
fired steam generators; Sec. 60.40) are subject to the PM and
NOX standards under this subpart and to the sulfur dioxide
(SO2) standards under subpart D (Sec. 60.43).
(3) Oil-fired affected facilities having a heat input capacity
between 29 and 73 MW (100 and 250 MMBtu/hr), inclusive, are subject to
the NOX standards under this subpart.
(4) Oil-fired affected facilities having a heat input capacity
greater than 73 MW (250 MMBtu/hr) and meeting the applicability
requirements under subpart D (Standards of performance for fossil-fuel-
fired steam generators; Sec. 60.40) are also subject to the
NOX standards under this subpart and the PM and
SO2 standards under subpart D (Sec. 60.42 and Sec. 60.43).
(c) Affected facilities that also meet the applicability
requirements under subpart J (Standards of performance for petroleum
refineries; Sec. 60.104) are subject to the PM and NOX
standards under this subpart and the SO2 standards under
subpart J (Sec. 60.104).
(d) Affected facilities that also meet the applicability
requirements under subpart E (Standards of performance for
incinerators; Sec. 60.50) are subject to the NOX and PM
standards under this subpart.
(e) Steam generating units meeting the applicability requirements
under subpart Da (Standards of performance for electric utility steam
generating units; Sec. 60.40Da) are not subject to this subpart.
(f) Any change to an existing steam generating unit for the sole
purpose of combusting gases containing total reduced sulfur (TRS) as
defined under Sec. 60.281 is not considered a modification under Sec.
60.14 and the steam generating unit is not subject to this subpart.
(g) In delegating implementation and enforcement authority to a
State under section 111(c) of the Clean Air Act, the following
authorities shall be retained by the Administrator and not transferred
to a State.
(1) Section 60.44b(f).
(2) Section 60.44b(g).
(3) Section 60.49b(a)(4).
(h) Any affected facility that meets the applicability requirements
and is subject to subpart Ea, subpart Eb, or subpart AAAA of this part
is not covered by this subpart.
(i) Heat recovery steam generators that are associated with
combined cycle gas turbines and that meet the applicability
requirements of subpart GG or KKKK of this part are not subject to this
subpart. This subpart will continue to apply to all other heat recovery
steam generators that are capable of combusting more than 29 MW (100
MMBtu/hr) heat input of fossil fuel. If the heat recovery steam
generator is subject to this subpart, only emissions resulting from
combustion of fuels in the steam generating unit are subject to this
subpart. (The gas turbine emissions are subject to subpart GG or KKKK,
as applicable, of this part.)
(j) Any affected facility meeting the applicability requirements
under paragraph (a) of this section and commencing construction,
modification, or reconstruction after June 19, 1986 is not subject to
subpart D (Standards of
[[Page 32743]]
Performance for Fossil-Fuel-Fired Steam Generators, Sec. 60.40).
(k) Any affected facility that meets the applicability requirements
and is subject to an EPA approved State or Federal section 111(d)/129
plan implementing subpart Cb or subpart BBBB of this part is not
covered by this subpart.
Sec. 60.41b Definitions.
As used in this subpart, all terms not defined herein shall have
the meaning given them in the Clean Air Act and in subpart A of this
part.
Annual capacity factor means the ratio between the actual heat
input to a steam generating unit from the fuels listed in Sec.
60.42b(a), Sec. 60.43b(a), or Sec. 60.44b(a), as applicable, during a
calendar year and the potential heat input to the steam generating unit
had it been operated for 8,760 hours during a calendar year at the
maximum steady state design heat input capacity. In the case of steam
generating units that are rented or leased, the actual heat input shall
be determined based on the combined heat input from all operations of
the affected facility in a calendar year.
Byproduct/waste means any liquid or gaseous substance produced at
chemical manufacturing plants, petroleum refineries, or pulp and paper
mills (except natural gas, distillate oil, or residual oil) and
combusted in a steam generating unit for heat recovery or for disposal.
Gaseous substances with carbon dioxide (CO2) levels greater
than 50 percent or carbon monoxide levels greater than 10 percent are
not byproduct/waste for the purpose of this subpart.
Chemical manufacturing plants mean industrial plants that are
classified by the Department of Commerce under Standard Industrial
Classification (SIC) Code 28.
Coal means all solid fuels classified as anthracite, bituminous,
subbituminous, or lignite by the American Society of Testing and
Materials in ASTM D388 (incorporated by reference, see Sec. 60.17),
coal refuse, and petroleum coke. Coal-derived synthetic fuels,
including but not limited to solvent refined coal, gasified coal, coal-
oil mixtures, coke oven gas, and coal-water mixtures, are also included
in this definition for the purposes of this subpart.
Coal refuse means any byproduct of coal mining or coal cleaning
operations with an ash content greater than 50 percent, by weight, and
a heating value less than 13,900 kJ/kg (6,000 Btu/lb) on a dry basis.
Cogeneration, also known as combined heat and power, means a
facility that simultaneously produces both electric (or mechanical) and
useful thermal energy from the same primary energy source.
Coke oven gas means the volatile constituents generated in the
gaseous exhaust during the carbonization of bituminous coal to form
coke.
Combined cycle system means a system in which a separate source,
such as a gas turbine, internal combustion engine, kiln, etc., provides
exhaust gas to a steam generating unit.
Conventional technology means wet flue gas desulfurization (FGD)
technology, dry FGD technology, atmospheric fluidized bed combustion
technology, and oil hydrodesulfurization technology.
Distillate oil means fuel oils that contain 0.05 weight percent
nitrogen or less and comply with the specifications for fuel oil
numbers 1 and 2, as defined by the American Society of Testing and
Materials in ASTM D396 (incorporated by reference, see Sec. 60.17).
Dry flue gas desulfurization technology means a SO2
control system that is located downstream of the steam generating unit
and removes sulfur oxides from the combustion gases of the steam
generating unit by contacting the combustion gases with an alkaline
reagent and water, whether introduced separately or as a premixed
slurry or solution and forming a dry powder material. This definition
includes devices where the dry powder material is subsequently
converted to another form. Alkaline slurries or solutions used in dry
flue gas desulfurization technology include but are not limited to lime
and sodium.
Duct burner means a device that combusts fuel and that is placed in
the exhaust duct from another source, such as a stationary gas turbine,
internal combustion engine, kiln, etc., to allow the firing of
additional fuel to heat the exhaust gases before the exhaust gases
enter a steam generating unit.
Emerging technology means any SO2 control system that is
not defined as a conventional technology under this section, and for
which the owner or operator of the facility has applied to the
Administrator and received approval to operate as an emerging
technology under Sec. 60.49b(a)(4).
Federally enforceable means all limitations and conditions that are
enforceable by the Administrator, including the requirements of 40 CFR
parts 60 and 61, requirements within any applicable State
Implementation Plan, and any permit requirements established under 40
CFR 52.21 or under 40 CFR 51.18 and 51.24.
Fluidized bed combustion technology means combustion of fuel in a
bed or series of beds (including but not limited to bubbling bed units
and circulating bed units) of limestone aggregate (or other sorbent
materials) in which these materials are forced upward by the flow of
combustion air and the gaseous products of combustion.
Fuel pretreatment means a process that removes a portion of the
sulfur in a fuel before combustion of the fuel in a steam generating
unit.
Full capacity means operation of the steam generating unit at 90
percent or more of the maximum steady-state design heat input capacity.
Gaseous fuel means any fuel that is present as a gas at ISO
conditions.
Gross output means the gross useful work performed by the steam
generated. For units generating only electricity, the gross useful work
performed is the gross electrical output from the turbine/generator
set. For cogeneration units, the gross useful work performed is the
gross electrical or mechanical output plus 75 percent of the useful
thermal output measured relative to ISO conditions that is not used to
generate additional electrical or mechanical output (i.e., steam
delivered to an industrial process).
Heat input means heat derived from combustion of fuel in a steam
generating unit and does not include the heat derived from preheated
combustion air, recirculated flue gases, or exhaust gases from other
sources, such as gas turbines, internal combustion engines, kilns, etc.
Heat release rate means the steam generating unit design heat input
capacity (in MW or Btu/hr) divided by the furnace volume (in cubic
meters or cubic feet); the furnace volume is that volume bounded by the
front furnace wall where the burner is located, the furnace side
waterwall, and extending to the level just below or in front of the
first row of convection pass tubes.
Heat transfer medium means any material that is used to transfer
heat from one point to another point.
High heat release rate means a heat release rate greater than
730,000 J/sec-m3 (70,000 Btu/hr-ft3).
ISO Conditions means a temperature of 288 Kelvin, a relative
humidity of 60 percent, and a pressure of 101.3 kilopascals.
Lignite means a type of coal classified as lignite A or lignite B
by the American Society of Testing and Materials in ASTM D388
(incorporated by reference, see Sec. 60.17).
Low heat release rate means a heat release rate of 730,000 J/sec-
m3 (70,000 Btu/hr-ft3) or less.
[[Page 32744]]
Mass-feed stoker steam generating unit means a steam generating
unit where solid fuel is introduced directly into a retort or is fed
directly onto a grate where it is combusted.
Maximum heat input capacity means the ability of a steam generating
unit to combust a stated maximum amount of fuel on a steady state
basis, as determined by the physical design and characteristics of the
steam generating unit.
Municipal-type solid waste means refuse, more than 50 percent of
which is waste consisting of a mixture of paper, wood, yard wastes,
food wastes, plastics, leather, rubber, and other combustible
materials, and noncombustible materials such as glass and rock.
Natural gas means: (1) A naturally occurring mixture of hydrocarbon
and nonhydrocarbon gases found in geologic formations beneath the
earth's surface, of which the principal constituent is methane; or (2)
liquefied petroleum gas, as defined by the American Society for Testing
and Materials in ASTM D1835 (incorporated by reference, see Sec.
60.17).
Noncontinental area means the State of Hawaii, the Virgin Islands,
Guam, American Samoa, the Commonwealth of Puerto Rico, or the Northern
Mariana Islands.
Oil means crude oil or petroleum or a liquid fuel derived from
crude oil or petroleum, including distillate and residual oil.
Petroleum refinery means industrial plants as classified by the
Department of Commerce under Standard Industrial Classification (SIC)
Code 29.
Potential sulfur dioxide emission rate means the theoretical
SO2 emissions (nanograms per joule (ng/J) or lb/MMBtu heat
input) that would result from combusting fuel in an uncleaned state and
without using emission control systems.
Process heater means a device that is primarily used to heat a
material to initiate or promote a chemical reaction in which the
material participates as a reactant or catalyst.
Pulp and paper mills means industrial plants that are classified by
the Department of Commerce under North American Industry Classification
System (NAICS) Code 322 or Standard Industrial Classification (SIC)
Code 26.
Pulverized coal-fired steam generating unit means a steam
generating unit in which pulverized coal is introduced into an air
stream that carries the coal to the combustion chamber of the steam
generating unit where it is fired in suspension. This includes both
conventional pulverized coal-fired and micropulverized coal-fired steam
generating units. Residual oil means crude oil, fuel oil numbers 1 and
2 that have a nitrogen content greater than 0.05 weight percent, and
all fuel oil numbers 4, 5 and 6, as defined by the American Society of
Testing and Materials in ASTM D396 (incorporated by reference, see
Sec. 60.17).
Spreader stoker steam generating unit means a steam generating unit
in which solid fuel is introduced to the combustion zone by a mechanism
that throws the fuel onto a grate from above. Combustion takes place
both in suspension and on the grate.
Steam generating unit means a device that combusts any fuel or
byproduct/waste and produces steam or heats water or any other heat
transfer medium. This term includes any municipal-type solid waste
incinerator with a heat recovery steam generating unit or any steam
generating unit that combusts fuel and is part of a cogeneration system
or a combined cycle system. This term does not include process heaters
as they are defined in this subpart.
Steam generating unit operating day means a 24-hour period between
12:00 midnight and the following midnight during which any fuel is
combusted at any time in the steam generating unit. It is not necessary
for fuel to be combusted continuously for the entire 24-hour period.
Very low sulfur oil means for units constructed, reconstructed, or
modified on or before February 28, 2005, an oil that contains no more
than 0.5 weight percent sulfur or that, when combusted without
SO2 emission control, has a SO2 emission rate
equal to or less than 215 ng/J (0.5 lb/MMBtu) heat input. For units
constructed, reconstructed, or modified after February 28, 2005, very
low sulfur oil means an oil that contains no more than 0.3 weight
percent sulfur or that, when combusted without SO2 emission
control, has a SO2 emission rate equal to or less than 140
ng/J (0.32 lb/MMBtu) heat input.
Wet flue gas desulfurization technology means a SO2
control system that is located downstream of the steam generating unit
and removes sulfur oxides from the combustion gases of the steam
generating unit by contacting the combustion gas with an alkaline
slurry or solution and forming a liquid material. This definition
applies to devices where the aqueous liquid material product of this
contact is subsequently converted to other forms. Alkaline reagents
used in wet flue gas desulfurization technology include, but are not
limited to, lime, limestone, and sodium.
Wet scrubber system means any emission control device that mixes an
aqueous stream or slurry with the exhaust gases from a steam generating
unit to control emissions of PM or SO2.
Wood means wood, wood residue, bark, or any derivative fuel or
residue thereof, in any form, including, but not limited to, sawdust,
sanderdust, wood chips, scraps, slabs, millings, shavings, and
processed pellets made from wood or other forest residues.
Sec. 60.42b Standard for sulfur dioxide (SO2).
(a) Except as provided in paragraphs (b), (c), (d), or (k) of this
section, on and after the date on which the performance test is
completed or required to be completed under Sec. 60.8, whichever comes
first, no owner or operator of an affected facility that commenced
construction, reconstruction, or modification on or before February 28,
2005, that combusts coal or oil shall cause to be discharged into the
atmosphere any gases that contain SO2 in excess of 87 ng/J
(0.20 lb/MMBtu) or 10 percent (0.10) of the potential SO2
emission rate (90 percent reduction) and the emission limit determined
according to the following formula:
[GRAPHIC] [TIFF OMITTED] TR13JN07.022
Where:
Es = SO2 emission limit, in ng/J or lb/MMBtu
heat input;
Ka = 520 ng/J (or 1.2 lb/MMBtu);
Kb = 340 ng/J (or 0.80 lb/MMBtu);
Ha = Heat input from the combustion of coal, in J
(MMBtu); and
Hb = Heat input from the combustion of oil, in J (MMBtu).
Only the heat input supplied to the affected facility from the
combustion of coal and oil is counted under this section. No credit is
provided for the heat input to the affected facility from the
combustion of natural gas, wood, municipal-type solid waste, or other
fuels or heat derived from exhaust gases from other sources, such as
gas turbines, internal combustion engines, kilns, etc.
(b) On and after the date on which the performance test is
completed or required to be completed under Sec. 60.8, whichever date
comes first, no owner or operator of an affected facility that
commenced construction, reconstruction, or modification on or before
February 28, 2005, that combusts coal refuse alone in a fluidized bed
combustion steam generating unit shall cause to be discharged into the
atmosphere any gases that contain SO2 in excess of 87 ng/J
(0.20 lb/MMBtu) or 20 percent (0.20) of the potential SO2
emission rate (80 percent reduction) and
[[Page 32745]]
520 ng/J (1.2 lb/MMBtu) heat input. If coal or oil is fired with coal
refuse, the affected facility is subject to paragraph (a) or (d) of
this section, as applicable.
(c) On and after the date on which the performance test is
completed or is required to be completed under Sec. 60.8, whichever
comes first, no owner or operator of an affected facility that combusts
coal or oil, either alone or in combination with any other fuel, and
that uses an emerging technology for the control of SO2
emissions, shall cause to be discharged into the atmosphere any gases
that contain SO2 in excess of 50 percent of the potential
SO2 emission rate (50 percent reduction) and that contain
SO2 in excess of the emission limit determined according to
the following formula:
[GRAPHIC] [TIFF OMITTED] TR13JN07.023
Where:
Es = SO2 emission limit, in ng/J or lb/MM Btu
heat input;
Kc = 260 ng/J (or 0.60 lb/MMBtu);
Kd = 170 ng/J (or 0.40 lb/MMBtu);
Hc = Heat input from the combustion of coal, in J
(MMBtu); and
Hd = Heat input from the combustion of oil, in J (MMBtu).
Only the heat input supplied to the affected facility from the
combustion of coal and oil is counted under this section. No credit is
provided for the heat input to the affected facility from the
combustion of natural gas, wood, municipal-type solid waste, or other
fuels, or from the heat input derived from exhaust gases from other
sources, such as gas turbines, internal combustion engines, kilns, etc.
(d) On and after the date on which the performance test is
completed or required to be completed under Sec. 60.8, whichever comes
first, no owner or operator of an affected facility that commenced
construction, reconstruction, or modification on or before February 28,
2005 and listed in paragraphs (d)(1), (2), (3), or (4) of this section
shall cause to be discharged into the atmosphere any gases that contain
SO2 in excess of 520 ng/J (1.2 lb/MMBtu) heat input if the
affected facility combusts coal, or 215 ng/J (0.5 lb/MMBtu) heat input
if the affected facility combusts oil other than very low sulfur oil.
Percent reduction requirements are not applicable to affected
facilities under paragraphs (d)(1), (2), (3) or (4) of this section.
(1) Affected facilities that have an annual capacity factor for
coal and oil of 30 percent (0.30) or less and are subject to a
federally enforceable permit limiting the operation of the affected
facility to an annual capacity factor for coal and oil of 30 percent
(0.30) or less;
(2) Affected facilities located in a noncontinental area; or
(3) Affected facilities combusting coal or oil, alone or in
combination with any fuel, in a duct burner as part of a combined cycle
system where 30 percent (0.30) or less of the heat entering the steam
generating unit is from combustion of coal and oil in the duct burner
and 70 percent (0.70) or more of the heat entering the steam generating
unit is from the exhaust gases entering the duct burner; or
(4) The affected facility burns coke oven gas alone or in
combination with natural gas or very low sulfur distillate oil.
(e) Except as provided in paragraph (f) of this section, compliance
with the emission limits, fuel oil sulfur limits, and/or percent
reduction requirements under this section are determined on a 30-day
rolling average basis.
(f) Except as provided in paragraph (j)(2) of this section,
compliance with the emission limits or fuel oil sulfur limits under
this section is determined on a 24-hour average basis for affected
facilities that (1) have a federally enforceable permit limiting the
annual capacity factor for oil to 10 percent or less, (2) combust only
very low sulfur oil, and (3) do not combust any other fuel.
(g) Except as provided in paragraph (i) of this section and Sec.
60.45b(a), the SO2 emission limits and percent reduction
requirements under this section apply at all times, including periods
of startup, shutdown, and malfunction.
(h) Reductions in the potential SO2 emission rate
through fuel pretreatment are not credited toward the percent reduction
requirement under paragraph (c) of this section unless:
(1) Fuel pretreatment results in a 50 percent or greater reduction
in potential SO2 emissions and
(2) Emissions from the pretreated fuel (without combustion or post-
combustion SO2 control) are equal to or less than the
emission limits specified in paragraph (c) of this section.
(i) An affected facility subject to paragraph (a), (b), or (c) of
this section may combust very low sulfur oil or natural gas when the
SO2 control system is not being operated because of
malfunction or maintenance of the SO2 control system.
(j) Percent reduction requirements are not applicable to affected
facilities combusting only very low sulfur oil. The owner or operator
of an affected facility combusting very low sulfur oil shall
demonstrate that the oil meets the definition of very low sulfur oil
by: (1) Following the performance testing procedures as described in
Sec. 60.45b(c) or Sec. 60.45b(d), and following the monitoring
procedures as described in Sec. 60.47b(a) or Sec. 60.47b(b) to
determine SO2 emission rate or fuel oil sulfur content; or
(2) maintaining fuel records as described in Sec. 60.49b(r).
(k)(1) Except as provided in paragraphs (k)(2), (k)(3), and (k)(4)
of this section, on and after the date on which the initial performance
test is completed or is required to be completed under Sec. 60.8,
whichever date comes first, no owner or operator of an affected
facility that commences construction, reconstruction, or modification
after February 28, 2005, and that combusts coal, oil, natural gas, a
mixture of these fuels, or a mixture of these fuels with any other
fuels shall cause to be discharged into the atmosphere any gases that
contain SO2 in excess of 87 ng/J (0.20 lb/MMBtu) heat input
or 8 percent (0.08) of the potential SO2 emission rate (92
percent reduction) and 520 ng/J (1.2 lb/MMBtu) heat input.
(2) Units firing only very low sulfur oil and/or a mixture of
gaseous fuels with a potential SO2 emission rate of 140 ng/J
(0.32 lb/MMBtu) heat input or less are exempt from the SO2
emissions limit in paragraph 60.42b(k)(1).
(3) Units that are located in a noncontinental area and that
combust coal or oil shall not discharge any gases that contain
SO2 in excess of 520 ng/J (1.2 lb/MMBtu) heat input if the
affected facility combusts coal, or 215 ng/J (0.50 lb/MMBtu) heat input
if the affected facility combusts oil.
(4) As an alternative to meeting the requirements under paragraph
(k)(1) of this section, modified facilities that combust coal or a
mixture of coal with other fuels shall not cause to be discharged into
the atmosphere any gases that contain SO2 in excess of 87
ng/J (0.20 lb/MMBtu) heat input or 10 percent (0.10) of the potential
SO2 emission rate (90 percent reduction) and 520 ng/J (1.2
lb/MMBtu) heat input.
Sec. 60.43b Standard for particulate matter (PM).
(a) On and after the date on which the initial performance test is
completed or is required to be completed under Sec. 60.8, whichever
comes first, no owner or operator of an affected facility that
commenced construction, reconstruction, or modification on or before
February 28, 2005 that combusts coal or combusts mixtures of coal with
other fuels, shall cause to be discharged into the atmosphere from that
affected facility any gases that contain PM in excess of the following
emission limits:
[[Page 32746]]
(1) 22 ng/J (0.051 lb/MMBtu) heat input, (i) If the affected
facility combusts only coal, or
(ii) If the affected facility combusts coal and other fuels and has
an annual capacity factor for the other fuels of 10 percent (0.10) or
less.
(2) 43 ng/J (0.10 lb/MMBtu) heat input if the affected facility
combusts coal and other fuels and has an annual capacity factor for the
other fuels greater than 10 percent (0.10) and is subject to a
federally enforceable requirement limiting operation of the affected
facility to an annual capacity factor greater than 10 percent (0.10)
for fuels other than coal.
(3) 86 ng/J (0.20 lb/MMBtu) heat input if the affected facility
combusts coal or coal and other fuels and
(i) Has an annual capacity factor for coal or coal and other fuels
of 30 percent (0.30) or less,
(ii) Has a maximum heat input capacity of 73 MW (250 MMBtu/hr) or
less,
(iii) Has a federally enforceable requirement limiting operation of
the affected facility to an annual capacity factor of 30 percent (0.30)
or less for coal or coal and other solid fuels, and
(iv) Construction of the affected facility commenced after June 19,
1984, and before November 25, 1986.
(4) An affected facility burning coke oven gas alone or in
combination with other fuels not subject to a PM standard under Sec.
60.43b and not using a post-combustion technology (except a wet
scrubber) for reducing PM or SO2 emissions is not subject to
the PM limits under Sec. 60.43b(a).
(b) On and after the date on which the performance test is
completed or required to be completed under Sec. 60.8, whichever comes
first, no owner or operator of an affected facility that commenced
construction, reconstruction, or modification on or before February 28,
2005, and that combusts oil (or mixtures of oil with other fuels) and
uses a conventional or emerging technology to reduce SO2
emissions shall cause to be discharged into the atmosphere from that
affected facility any gases that contain PM in excess of 43 ng/J (0.10
lb/MMBtu) heat input.
(c) On and after the date on which the initial performance test is
completed or is required to be completed under Sec. 60.8, whichever
comes first, no owner or operator of an affected facility that
commenced construction, reconstruction, or modification on or before
February 28, 2005, and that combusts wood, or wood with other fuels,
except coal, shall cause to be discharged from that affected facility
any gases that contain PM in excess of the following emission limits:
(1) 43 ng/J (0.10 lb/MMBtu) heat input if the affected facility has
an annual capacity factor greater than 30 percent (0.30) for wood.
(2) 86 ng/J (0.20 lb/MMBtu) heat input if (i) The affected facility
has an annual capacity factor of 30 percent (0.30) or less for wood;
(ii) Is subject to a federally enforceable requirement limiting
operation of the affected facility to an annual capacity factor of 30
percent (0.30) or less for wood; and
(iii) Has a maximum heat input capacity of 73 MW (250 MMBtu/hr) or
less.
(d) On and after the date on which the initial performance test is
completed or is required to be completed under Sec. 60.8, whichever
date comes first, no owner or operator of an affected facility that
combusts municipal-type solid waste or mixtures of municipal-type solid
waste with other fuels, shall cause to be discharged into the
atmosphere from that affected facility any gases that contain PM in
excess of the following emission limits:
(1) 43 ng/J (0.10 lb/MMBtu) heat input;
(i) If the affected facility combusts only municipal-type solid
waste; or
(ii) If the affected facility combusts municipal-type solid waste
and other fuels and has an annual capacity factor for the other fuels
of 10 percent (0.10) or less.
(2) 86 ng/J (0.20 lb/MMBtu) heat input if the affected facility
combusts municipal-type solid waste or municipal-type solid waste and
other fuels; and
(i) Has an annual capacity factor for municipal-type solid waste
and other fuels of 30 percent (0.30) or less;
(ii) Has a maximum heat input capacity of 73 MW (250 MMBtu/hr) or
less;
(iii) Has a federally enforceable requirement limiting operation of
the affected facility to an annual capacity factor of 30 percent (0.30)
or less for municipal-type solid waste, or municipal-type solid waste
and other fuels; and
(iv) Construction of the affected facility commenced after June 19,
1984, but on or before November 25, 1986.
(e) For the purposes of this section, the annual capacity factor is
determined by dividing the actual heat input to the steam generating
unit during the calendar year from the combustion of coal, wood, or
municipal-type solid waste, and other fuels, as applicable, by the
potential heat input to the steam generating unit if the steam
generating unit had been operated for 8,760 hours at the maximum heat
input capacity.
(f) On and after the date on which the initial performance test is
completed or is required to be completed under Sec. 60.8, whichever
date comes first, no owner or operator of an affected facility that
combusts coal, oil, wood, or mixtures of these fuels with any other
fuels shall cause to be discharged into the atmosphere any gases that
exhibit greater than 20 percent opacity (6-minute average), except for
one 6-minute period per hour of not more than 27 percent opacity.
(g) The PM and opacity standards apply at all times, except during
periods of startup, shutdown or malfunction.
(h)(1) Except as provided in paragraphs (h)(2), (h)(3), (h)(4), and
(h)(5) of this section, on and after the date on which the initial
performance test is completed or is required to be completed under
Sec. 60.8, whichever date comes first, no owner or operator of an
affected facility that commenced construction, reconstruction, or
modification after February 28, 2005, and that combusts coal, oil,
wood, a mixture of these fuels, or a mixture of these fuels with any
other fuels shall cause to be discharged into the atmosphere from that
affected facility any gases that contain PM in excess of 13 ng/J (0.030
lb/MMBtu) heat input,
(2) As an alternative to meeting the requirements of paragraph
(h)(1) of this section, the owner or operator of an affected facility
for which modification commenced after February 28, 2005, may elect to
meet the requirements of this paragraph. On and after the date on which
the initial performance test is completed or required to be completed
under Sec. 60.8, no owner or operator of an affected facility that
commences modification after February 28, 2005 shall cause to be
discharged into the atmosphere from that affected facility any gases
that contain PM in excess of both:
(i) 22 ng/J (0.051 lb/MMBtu) heat input derived from the combustion
of coal, oil, wood, a mixture of these fuels, or a mixture of these
fuels with any other fuels; and
(ii) 0.2 percent of the combustion concentration (99.8 percent
reduction) when combusting coal, oil, wood, a mixture of these fuels,
or a mixture of these fuels with any other fuels.
(3) On and after the date on which the initial performance test is
completed or is required to be completed under Sec. 60.8, whichever
date comes first, no owner or operator of an affected facility that
commences modification after February 28, 2005, and that combusts over
30 percent wood (by heat input) on
[[Page 32747]]
an annual basis and has a maximum heat input capacity of 73 MW (250
MMBtu/h) or less shall cause to be discharged into the atmosphere from
that affected facility any gases that contain PM in excess of 43 ng/J
(0.10 lb/MMBtu) heat input.
(4) On and after the date on which the initial performance test is
completed or is required to be completed under Sec. 60.8, whichever
date comes first, no owner or operator of an affected facility that
commences modification after February 28, 2005, and that combusts over
30 percent wood (by heat input) on an annual basis and has a maximum
heat input capacity greater than 73 MW (250 MMBtu/h) shall cause to be
discharged into the atmosphere from that affected facility any gases
that contain PM in excess of 37 ng/J (0.085 lb/MMBtu) heat input.
(5) On and after the date on which the initial performance test is
completed or is required to be completed under Sec. 60.8, whichever
date comes first, an owner or operator of an affected facility that
commences construction, reconstruction, or modification after February
28, 2005, and that combusts only oil that contains no more than 0.3
weight percent sulfur, coke oven gas, a mixture of these fuels, or
either fuel (or a mixture of these fuels) in combination with other
fuels not subject to a PM standard under Sec. 60.43b and not using a
post-combustion technology (except a wet scrubber) to reduce
SO2 or PM emissions is not subject to the PM limits under
Sec. 60.43b(h)(1).
Sec. 60.44b Standard for nitrogen oxides (NOX).
(a) Except as provided under paragraphs (k) and (l) of this
section, on and after the date on which the initial performance test is
completed or is required to be completed under Sec. 60.8, whichever
date comes first, no owner or operator of an affected facility that is
subject to the provisions of this section and that combusts only coal,
oil, or natural gas shall cause to be discharged into the atmosphere
from that affected facility any gases that contain NOX
(expressed as NO2) in excess of the following emission
limits:
------------------------------------------------------------------------
Nitrogen oxide emission
limits (expressed as
Fuel/steam generating unit type NO2) heat input
-------------------------
ng/J lb/MMBTu
------------------------------------------------------------------------
(1) Natural gas and distillate oil, except
(4):
(i) Low heat release rate................. 43 0.10
(ii) High heat release rate............... 86 0.20
(2) Residual oil:
(i) Low heat release rate................. 130 0.30
(ii) High heat release rate............... 170 0.40
(3) Coal:
(i) Mass-feed stoker...................... 210 0.50
(ii) Spreader stoker and fluidized bed 260 0.60
combustion...............................
(iii) Pulverized coal..................... 300 0.70
(iv) Lignite, except (v).................. 260 0.60
(v) Lignite mined in North Dakota, South 340 0.80
Dakota, or Montana and combusted in a
slag tap furnace.........................
(vi) Coal-derived synthetic fuels......... 210 0.50
(4) Duct burner used in a combined cycle
system:
(i) Natural gas and distillate oil........ 86 0.20
(ii) Residual oil......................... 170 0.40
------------------------------------------------------------------------
(b) Except as provided under paragraphs (k) and (l) of this
section, on and after the date on which the initial performance test is
completed or is required to be completed under Sec. 60.8, whichever
date comes first, no owner or operator of an affected facility that
simultaneously combusts mixtures of coal, oil, or natural gas shall
cause to be discharged into the atmosphere from that affected facility
any gases that contain NOX in excess of a limit determined
by the use of the following formula:
[GRAPHIC] [TIFF OMITTED] TR13JN07.024
Where:
En = NOX emission limit (expressed as
NO2), ng/J (lb/MMBtu);
ELgo = Appropriate emission limit from paragraph (a)(1)
for combustion of natural gas or distillate oil, ng/J (lb/MMBtu);
Hgo = Heat input from combustion of natural gas or
distillate oil, J (MMBtu);
ELro = Appropriate emission limit from paragraph (a)(2)
for combustion of residual oil, ng/J (lb/MMBtu);
Hro = Heat input from combustion of residual oil, J
(MMBtu);
ELc = Appropriate emission limit from paragraph (a)(3)
for combustion of coal, ng/J (lb/MMBtu); and
Hc = Heat input from combustion of coal, J (MMBtu).
(c) Except as provided under paragraph (l) of this section, on and
after the date on which the initial performance test is completed or is
required to be completed under Sec. 60.8, whichever date comes first,
no owner or operator of an affected facility that simultaneously
combusts coal or oil, or a mixture of these fuels with natural gas, and
wood, municipal-type solid waste, or any other fuel shall cause to be
discharged into the atmosphere any gases that contain NOX in
excess of the emission limit for the coal or oil, or mixtures of these
fuels with natural gas combusted in the affected facility, as
determined pursuant to paragraph (a) or (b) of this section, unless the
affected facility has an annual capacity factor for coal or oil, or
mixture of these fuels with natural gas of 10 percent (0.10) or less
and is subject to a federally enforceable requirement that limits
operation of the affected facility to an annual capacity factor of 10
percent (0.10) or less for coal, oil, or a mixture of these fuels with
natural gas.
(d) On and after the date on which the initial performance test is
completed or is required to be completed under Sec. 60.8, whichever
date comes first, no owner or operator of an affected facility that
simultaneously combusts natural gas with wood, municipal-type solid
waste, or other solid fuel, except coal, shall cause to be discharged
into the atmosphere from that affected facility any gases that contain
NOX in excess of 130 ng/J (0.30 lb/MMBtu) heat input unless
the affected facility has an annual capacity factor for natural gas of
[[Page 32748]]
10 percent (0.10) or less and is subject to a federally enforceable
requirement that limits operation of the affected facility to an annual
capacity factor of 10 percent (0.10) or less for natural gas.
(e) Except as provided under paragraph (l) of this section, on and
after the date on which the initial performance test is completed or is
required to be completed under Sec. 60.8, whichever date comes first,
no owner or operator of an affected facility that simultaneously
combusts coal, oil, or natural gas with byproduct/waste shall cause to
be discharged into the atmosphere any gases that contain NOX
in excess of the emission limit determined by the following formula
unless the affected facility has an annual capacity factor for coal,
oil, and natural gas of 10 percent (0.10) or less and is subject to a
federally enforceable requirement that limits operation of the affected
facility to an annual capacity factor of 10 percent (0.10) or less:
[GRAPHIC] [TIFF OMITTED] TR13JN07.025
Where:
En = NOX emission limit (expressed as
NO2), ng/J (lb/MMBtu);
ELgo = Appropriate emission limit from paragraph (a)(1)
for combustion of natural gas or distillate oil, ng/J (lb/MMBtu);
Hgo = Heat input from combustion of natural gas,
distillate oil and gaseous byproduct/waste, J (MMBtu);
ELro = Appropriate emission limit from paragraph (a)(2)
for combustion of residual oil and/or byproduct/waste, ng/J (lb/
MMBtu);
Hro = Heat input from combustion of residual oil, J
(MMBtu);
ELc = Appropriate emission limit from paragraph (a)(3)
for combustion of coal, ng/J (lb/MMBtu); and
Hc = Heat input from combustion of coal, J (MMBtu).
(f) Any owner or operator of an affected facility that combusts
byproduct/waste with either natural gas or oil may petition the
Administrator within 180 days of the initial startup of the affected
facility to establish a NOX emission limit that shall apply
specifically to that affected facility when the byproduct/waste is
combusted. The petition shall include sufficient and appropriate data,
as determined by the Administrator, such as NOX emissions
from the affected facility, waste composition (including nitrogen
content), and combustion conditions to allow the Administrator to
confirm that the affected facility is unable to comply with the
emission limits in paragraph (e) of this section and to determine the
appropriate emission limit for the affected facility.
(1) Any owner or operator of an affected facility petitioning for a
facility-specific NOX emission limit under this section
shall:
(i) Demonstrate compliance with the emission limits for natural gas
and distillate oil in paragraph (a)(1) of this section or for residual
oil in paragraph (a)(2) or (l)(1) of this section, as appropriate, by
conducting a 30-day performance test as provided in Sec. 60.46b(e).
During the performance test only natural gas, distillate oil, or
residual oil shall be combusted in the affected facility; and
(ii) Demonstrate that the affected facility is unable to comply
with the emission limits for natural gas and distillate oil in
paragraph (a)(1) of this section or for residual oil in paragraph
(a)(2) or (l)(1) of this section, as appropriate, when gaseous or
liquid byproduct/waste is combusted in the affected facility under the
same conditions and using the same technological system of emission
reduction applied when demonstrating compliance under paragraph
(f)(1)(i) of this section.
(2) The NOX emission limits for natural gas or
distillate oil in paragraph (a)(1) of this section or for residual oil
in paragraph (a)(2) or (l)(1) of this section, as appropriate, shall be
applicable to the affected facility until and unless the petition is
approved by the Administrator. If the petition is approved by the
Administrator, a facility-specific NOX emission limit will
be established at the NOX emission level achievable when the
affected facility is combusting oil or natural gas and byproduct/waste
in a manner that the Administrator determines to be consistent with
minimizing NOX emissions. In lieu of amending this subpart,
a letter will be sent to the facility describing the facility-specific
NOX limit. The facility shall use the compliance procedures
detailed in the letter and make the letter available to the public. If
the Administrator determines it is appropriate, the conditions and
requirements of the letter can be reviewed and changed at any point.
(g) Any owner or operator of an affected facility that combusts
hazardous waste (as defined by 40 CFR part 261 or 40 CFR part 761) with
natural gas or oil may petition the Administrator within 180 days of
the initial startup of the affected facility for a waiver from
compliance with the NOX emission limit that applies
specifically to that affected facility. The petition must include
sufficient and appropriate data, as determined by the Administrator, on
NOX emissions from the affected facility, waste destruction
efficiencies, waste composition (including nitrogen content), the
quantity of specific wastes to be combusted and combustion conditions
to allow the Administrator to determine if the affected facility is
able to comply with the NOX emission limits required by this
section. The owner or operator of the affected facility shall
demonstrate that when hazardous waste is combusted in the affected
facility, thermal destruction efficiency requirements for hazardous
waste specified in an applicable federally enforceable requirement
preclude compliance with the NOX emission limits of this
section. The NOX emission limits for natural gas or
distillate oil in paragraph (a)(1) of this section or for residual oil
in paragraph (a)(2) or (l)(1) of this section, as appropriate, are
applicable to the affected facility until and unless the petition is
approved by the Administrator. (See 40 CFR 761.70 for regulations
applicable to the incineration of materials containing polychlorinated
biphenyls (PCB's).) In lieu of amending this subpart, a letter will be
sent to the facility describing the facility-specific NOX
limit. The facility shall use the compliance procedures detailed in the
letter and make the letter available to the public. If the
Administrator determines it is appropriate, the conditions and
requirements of the letter can be reviewed and changed at any point.
(h) For purposes of paragraph (i) of this section, the
NOX standards under this section apply at all times
including periods of startup, shutdown, or malfunction.
(i) Except as provided under paragraph (j) of this section,
compliance with the emission limits under this section is determined on
a 30-day rolling average basis.
(j) Compliance with the emission limits under this section is
determined on a 24-hour average basis for the initial performance test
and on a 3-hour average basis for subsequent performance tests for any
affected facilities that:
(1) Combust, alone or in combination, only natural gas, distillate
oil, or residual oil with a nitrogen content of 0.30 weight percent or
less;
(2) Have a combined annual capacity factor of 10 percent or less
for natural gas, distillate oil, and residual oil with a nitrogen
content of 0.30 weight percent or less; and
(3) Are subject to a federally enforceable requirement limiting
operation of the affected facility to the
[[Page 32749]]
firing of natural gas, distillate oil, and/or residual oil with a
nitrogen content of 0.30 weight percent or less and limiting operation
of the affected facility to a combined annual capacity factor of 10
percent or less for natural gas, distillate oil, and residual oil with
a nitrogen content of 0.30 weight percent or less.
(k) Affected facilities that meet the criteria described in
paragraphs (j)(1), (2), and (3) of this section, and that have a heat
input capacity of 73 MW (250 MMBtu/hr) or less, are not subject to the
NOX emission limits under this section.
(l) On and after the date on which the initial performance test is
completed or is required to be completed under Sec. 60.8, whichever
date comes first, no owner or operator of an affected facility that
commenced construction or reconstruction after July 9, 1997 shall cause
to be discharged into the atmosphere from that affected facility any
gases that contain NOX (expressed as NO2) in
excess of the following limits:
(1) If the affected facility combusts coal, oil, or natural gas, or
a mixture of these fuels, or with any other fuels: A limit of 86 ng/J
(0.20 lb/MMBtu) heat input unless the affected facility has an annual
capacity factor for coal, oil, and natural gas of 10 percent (0.10) or
less and is subject to a federally enforceable requirement that limits
operation of the facility to an annual capacity factor of 10 percent
(0.10) or less for coal, oil, and natural gas; or
(2) If the affected facility has a low heat release rate and
combusts natural gas or distillate oil in excess of 30 percent of the
heat input on a 30-day rolling average from the combustion of all
fuels, a limit determined by use of the following formula:
[GRAPHIC] [TIFF OMITTED] TR13JN07.026
Where:
En = NOX emission limit, (lb/MMBtu);
Hgo = 30-day heat input from combustion of natural gas or
distillate oil; and
Hr = 30-day heat input from combustion of any other fuel.
(3) After February 27, 2006, units where more than 10 percent of
total annual output is electrical or mechanical may comply with an
optional limit of 270 ng/J (2.1 lb/MWh) gross energy output, based on a
30-day rolling average. Units complying with this output-based limit
must demonstrate compliance according to the procedures of Sec.
60.48Da(i) of subpart Da of this part, and must monitor emissions
according to Sec. 60.49Da(c), (k), through (n) of subpart Da of this
part.
Sec. 60.45b Compliance and performance test methods and procedures
for sulfur dioxide.
(a) The SO2 emission standards under Sec. 60.42b apply
at all times. Facilities burning coke oven gas alone or in combination
with any other gaseous fuels or distillate oil and complying with the
fuel based limit under Sec. 60.42b(d) or Sec. 60.42b(k)(2) are
allowed to exceed the limit 30 operating days per calendar year for by-
product plant maintenance.
(b) In conducting the performance tests required under Sec. 60.8,
the owner or operator shall use the methods and procedures in appendix
A (including fuel certification and sampling) of this part or the
methods and procedures as specified in this section, except as provided
in Sec. 60.8(b). Section 60.8(f) does not apply to this section. The
30-day notice required in Sec. 60.8(d) applies only to the initial
performance test unless otherwise specified by the Administrator.
(c) The owner or operator of an affected facility shall conduct
performance tests to determine compliance with the percent of potential
SO2 emission rate (% Ps) and the SO2
emission rate (Es) pursuant to Sec. 60.42b following the
procedures listed below, except as provided under paragraph (d) and (k)
of this section.
(1) The initial performance test shall be conducted over 30
consecutive operating days of the steam generating unit. Compliance
with the SO2 standards shall be determined using a 30-day
average. The first operating day included in the initial performance
test shall be scheduled within 30 days after achieving the maximum
production rate at which the affected facility will be operated, but
not later than 180 days after initial startup of the facility.
(2) If only coal, only oil, or a mixture of coal and oil is
combusted, the following procedures are used:
(i) The procedures in Method 19 of appendix A of this part are used
to determine the hourly SO2 emission rate (Eho)
and the 30-day average emission rate (Eao). The hourly
averages used to compute the 30-day averages are obtained from the
continuous emission monitoring system (CEMS) of Sec. 60.47b (a) or
(b).
(ii) The percent of potential SO2 emission rate
(%Ps) emitted to the atmosphere is computed using the
following formula:
[GRAPHIC] [TIFF OMITTED] TR13JN07.027
Where:
%Ps = Potential SO2 emission rate, percent;
%Rg = SO2 removal efficiency of the control
device as determined by Method 19 of appendix A of this part, in
percent; and
%Rf = SO2 removal efficiency of fuel
pretreatment as determined by Method 19 of appendix A of this part,
in percent.
(3) If coal or oil is combusted with other fuels, the same
procedures required in paragraph (c)(2) of this section are used,
except as provided in the following:
(i) An adjusted hourly SO2 emission rate
(Eho\o\) is used in Equation 19-19 of Method 19 of appendix
A of this part to compute an adjusted 30-day average emission rate
(Eao\o\). The Eho[deg] is computed using the following
formula:
[GRAPHIC] [TIFF OMITTED] TR13JN07.028
Where:
Eho\o\ = Adjusted hourly SO2 emission rate,
ng/J (lb/MMBtu);
Eho = Hourly SO2 emission rate, ng/J (lb/
MMBtu);
Ew = SO2 concentration in fuels other than
coal and oil combusted in the affected facility, as determined by
the fuel sampling and analysis procedures in Method 19 of appendix A
of this part, ng/J (lb/MMBtu). The value Ew for each fuel
lot is used for each hourly average during the time that the lot is
being combusted; and
Xk = Fraction of total heat input from fuel combustion
derived from coal, oil, or coal and oil, as determined by applicable
procedures in Method 19 of appendix A of this part.
(ii) To compute the percent of potential SO2 emission
rate (%Ps), an adjusted %Rg (%Rg\o\)
is computed from the adjusted Eao\o\ from paragraph
(b)(3)(i) of this section and an adjusted average SO2 inlet
rate (Eai\o\) using the following formula:
[GRAPHIC] [TIFF OMITTED] TR13JN07.029
To compute Eai\o\, an adjusted hourly SO2
inlet rate (Ehi\o\) is used. The Ehi\o\ is
computed using the following formula:
[GRAPHIC] [TIFF OMITTED] TR13JN07.030
Where:
Ehi\o\ = Adjusted hourly SO2 inlet rate, ng/J
(lb/MMBtu); and
Ehi = Hourly SO2 inlet rate, ng/J (lb/MMBtu).
(4) The owner or operator of an affected facility subject to
paragraph (b)(3) of this section does not have to measure parameters
Ew or Xk if the owner or operator elects to
assume that
[[Page 32750]]
Xk = 1.0. Owners or operators of affected facilities who
assume Xk = 1.0 shall:
(i) Determine %Ps following the procedures in paragraph
(c)(2) of this section; and
(ii) Sulfur dioxide emissions (Es) are considered to be
in compliance with SO2 emission limits under Sec. 60.42b.
(5) The owner or operator of an affected facility that qualifies
under the provisions of Sec. 60.42b(d) does not have to measure
parameters Ew or Xk under paragraph (b)(3) of
this section if the owner or operator of the affected facility elects
to measure SO2 emission rates of the coal or oil following
the fuel sampling and analysis procedures under Method 19 of appendix A
of this part.
(d) Except as provided in paragraph (j) of this section, the owner
or operator of an affected facility that combusts only very low sulfur
oil, has an annual capacity factor for oil of 10 percent (0.10) or
less, and is subject to a federally enforceable requirement limiting
operation of the affected facility to an annual capacity factor for oil
of 10 percent (0.10) or less shall:
(1) Conduct the initial performance test over 24 consecutive steam
generating unit operating hours at full load;
(2) Determine compliance with the standards after the initial
performance test based on the arithmetic average of the hourly
emissions data during each steam generating unit operating day if a
CEMS is used, or based on a daily average if Method 6B of appendix A of
this part or fuel sampling and analysis procedures under Method 19 of
appendix A of this part are used.
(e) The owner or operator of an affected facility subject to Sec.
60.42b(d)(1) shall demonstrate the maximum design capacity of the steam
generating unit by operating the facility at maximum capacity for 24
hours. This demonstration will be made during the initial performance
test and a subsequent demonstration may be requested at any other time.
If the 24-hour average firing rate for the affected facility is less
than the maximum design capacity provided by the manufacturer of the
affected facility, the 24-hour average firing rate shall be used to
determine the capacity utilization rate for the affected facility,
otherwise the maximum design capacity provided by the manufacturer is
used.
(f) For the initial performance test required under Sec. 60.8,
compliance with the SO2 emission limits and percent
reduction requirements under Sec. 60.42b is based on the average
emission rates and the average percent reduction for SO2 for
the first 30 consecutive steam generating unit operating days, except
as provided under paragraph (d) of this section. The initial
performance test is the only test for which at least 30 days prior
notice is required unless otherwise specified by the Administrator. The
initial performance test is to be scheduled so that the first steam
generating unit operating day of the 30 successive steam generating
unit operating days is completed within 30 days after achieving the
maximum production rate at which the affected facility will be
operated, but not later than 180 days after initial startup of the
facility. The boiler load during the 30-day period does not have to be
the maximum design load, but must be representative of future operating
conditions and include at least one 24-hour period at full load.
(g) After the initial performance test required under Sec. 60.8,
compliance with the SO2 emission limits and percent
reduction requirements under Sec. 60.42b is based on the average
emission rates and the average percent reduction for SO2 for
30 successive steam generating unit operating days, except as provided
under paragraph (d). A separate performance test is completed at the
end of each steam generating unit operating day after the initial
performance test, and a new 30-day average emission rate and percent
reduction for SO2 are calculated to show compliance with the
standard.
(h) Except as provided under paragraph (i) of this section, the
owner or operator of an affected facility shall use all valid
SO2 emissions data in calculating %Ps and
Eho under paragraph (c), of this section whether or not the
minimum emissions data requirements under Sec. 60.46b are achieved.
All valid emissions data, including valid SO2 emission data
collected during periods of startup, shutdown and malfunction, shall be
used in calculating %Ps and Eho pursuant to
paragraph (c) of this section.
(i) During periods of malfunction or maintenance of the
SO2 control systems when oil is combusted as provided under
Sec. 60.42b(i), emission data are not used to calculate %Ps
or Es under Sec. 60.42b(a), (b) or (c), however, the
emissions data are used to determine compliance with the emission limit
under Sec. 60.42b(i).
(j) The owner or operator of an affected facility that combusts
very low sulfur oil is not subject to the compliance and performance
testing requirements of this section if the owner or operator obtains
fuel receipts as described in Sec. 60.49b(r).
(k) The owner or operator of an affected facility seeking to
demonstrate compliance under Sec. Sec. 60.42b(d)(4), 60.42b(j), and
60.42b(k)(2) shall follow the applicable procedures under Sec.
60.49b(r).
Sec. 60.46b Compliance and performance test methods and procedures
for particulate matter and nitrogen oxides.
(a) The PM emission standards and opacity limits under Sec. 60.43b
apply at all times except during periods of startup, shutdown, or
malfunction. The NOX emission standards under Sec. 60.44b
apply at all times.
(b) Compliance with the PM emission standards under Sec. 60.43b
shall be determined through performance testing as described in
paragraph (d) of this section, except as provided in paragraph (i) of
this section.
(c) Compliance with the NOX emission standards under
Sec. 60.44b shall be determined through performance testing under
paragraph (e) or (f), or under paragraphs (g) and (h) of this section,
as applicable.
(d) To determine compliance with the PM emission limits and opacity
limits under Sec. 60.43b, the owner or operator of an affected
facility shall conduct an initial performance test as required under
Sec. 60.8, and shall conduct subsequent performance tests as requested
by the Administrator, using the following procedures and reference
methods:
(1) Method 3B of appendix A of this part is used for gas analysis
when applying Method 5 or 17 of appendix A of this part.
(2) Method 5, 5B, or 17 of appendix A of this part shall be used to
measure the concentration of PM as follows:
(i) Method 5 of appendix A of this part shall be used at affected
facilities without wet flue gas desulfurization (FGD) systems; and
(ii) Method 17 of appendix A of this part may be used at facilities
with or without wet scrubber systems provided the stack gas temperature
does not exceed a temperature of 160 [deg]C (32 [deg]F). The procedures
of sections 2.1 and 2.3 of Method 5B of appendix A of this part may be
used in Method 17 of appendix A of this part only if it is used after a
wet FGD system. Do not use Method 17 of appendix A of this part after
wet FGD systems if the effluent is saturated or laden with water
droplets.
(iii) Method 5B of appendix A of this part is to be used only after
wet FGD systems.
(3) Method 1 of appendix A of this part is used to select the
sampling site and the number of traverse sampling points. The sampling
time for each run is at least 120 minutes and the minimum sampling
volume is 1.7 dscm (60 dscf) except that smaller sampling
[[Page 32751]]
times or volumes may be approved by the Administrator when necessitated
by process variables or other factors.
(4) For Method 5 of appendix A of this part, the temperature of the
sample gas in the probe and filter holder is monitored and is
maintained at 16014 [deg]C (32025 [deg]F).
(5) For determination of PM emissions, the oxygen (O2)
or CO2 sample is obtained simultaneously with each run of
Method 5, 5B, or 17 of appendix A of this part by traversing the duct
at the same sampling location.
(6) For each run using Method 5, 5B, or 17 of appendix A of this
part, the emission rate expressed in ng/J heat input is determined
using:
(i) The O2 or CO2 measurements and PM
measurements obtained under this section;
(ii) The dry basis F factor; and
(iii) The dry basis emission rate calculation procedure contained
in Method 19 of appendix A of this part.
(7) Method 9 of appendix A of this part is used for determining the
opacity of stack emissions.
(e) To determine compliance with the emission limits for
NOX required under Sec. 60.44b, the owner or operator of an
affected facility shall conduct the performance test as required under
Sec. 60.8 using the continuous system for monitoring NOX
under Sec. 60.48(b).
(1) For the initial compliance test, NOX from the steam
generating unit are monitored for 30 successive steam generating unit
operating days and the 30-day average emission rate is used to
determine compliance with the NOX emission standards under
Sec. 60.44b. The 30-day average emission rate is calculated as the
average of all hourly emissions data recorded by the monitoring system
during the 30-day test period.
(2) Following the date on which the initial performance test is
completed or is required to be completed under Sec. 60.8, whichever
date comes first, the owner or operator of an affected facility which
combusts coal or which combusts residual oil having a nitrogen content
greater than 0.30 weight percent shall determine compliance with the
NOX emission standards under Sec. 60.44b on a continuous
basis through the use of a 30-day rolling average emission rate. A new
30-day rolling average emission rate is calculated each steam
generating unit operating day as the average of all of the hourly
NOX emission data for the preceding 30 steam generating unit
operating days.
(3) Following the date on which the initial performance test is
completed or is required to be completed under Sec. 60.8, whichever
date comes first, the owner or operator of an affected facility that
has a heat input capacity greater than 73 MW (250 MMBtu/hr) and that
combusts natural gas, distillate oil, or residual oil having a nitrogen
content of 0.30 weight percent or less shall determine compliance with
the NOX standards under Sec. 60.44b on a continuous basis
through the use of a 30-day rolling average emission rate. A new 30-day
rolling average emission rate is calculated each steam generating unit
operating day as the average of all of the hourly NOX
emission data for the preceding 30 steam generating unit operating
days.
(4) Following the date on which the initial performance test is
completed or required to be completed under Sec. 60.8, whichever date
comes first, the owner or operator of an affected facility that has a
heat input capacity of 73 MW (250 MMBtu/hr) or less and that combusts
natural gas, distillate oil, or residual oil having a nitrogen content
of 0.30 weight percent or less shall upon request determine compliance
with the NOX standards under Sec. 60.44b through the use of
a 30-day performance test. During periods when performance tests are
not requested, NOX emissions data collected pursuant to
Sec. 60.48b(g)(1) or Sec. 60.48b(g)(2) are used to calculate a 30-day
rolling average emission rate on a daily basis and used to prepare
excess emission reports, but will not be used to determine compliance
with the NOX emission standards. A new 30-day rolling
average emission rate is calculated each steam generating unit
operating day as the average of all of the hourly NOX
emission data for the preceding 30 steam generating unit operating
days.
(5) If the owner or operator of an affected facility that combusts
residual oil does not sample and analyze the residual oil for nitrogen
content, as specified in Sec. 60.49b(e), the requirements of Sec.
60.48b(g)(1) apply and the provisions of Sec. 60.48b(g)(2) are
inapplicable.
(f) To determine compliance with the emissions limits for
NOX required by Sec. 60.44b(a)(4) or Sec. 60.44b(l) for
duct burners used in combined cycle systems, either of the procedures
described in paragraph (f)(1) or (2) of this section may be used:
(1) The owner or operator of an affected facility shall conduct the
performance test required under Sec. 60.8 as follows:
(i) The emissions rate (E) of NOX shall be computed
using Equation 1 in this section:
[GRAPHIC] [TIFF OMITTED] TR13JN07.031
Where:
E = Emissions rate of NOX from the duct burner, ng/J (lb/
MMBtu) heat input;
Esg = Combined effluent emissions rate, in ng/J (lb/
MMBtu) heat input using appropriate F factor as described in Method
19 of appendix A of this part;
Hg = Heat input rate to the combustion turbine, in J/hr
(MMBtu/hr);
Hb = Heat input rate to the duct burner, in J/hr (MMBtu/
hr); and
Eg = Emissions rate from the combustion turbine, in ng/J
(lb/MMBtu) heat input calculated using appropriate F factor as
described in Method 19 of appendix A of this part.
(ii) Method 7E of appendix A of this part shall be used to
determine the NOX concentrations. Method 3A or 3B of
appendix A of this part shall be used to determine O2
concentration.
(iii) The owner or operator shall identify and demonstrate to the
Administrator's satisfaction suitable methods to determine the average
hourly heat input rate to the combustion turbine and the average hourly
heat input rate to the affected duct burner.
(iv) Compliance with the emissions limits under Sec. 60.44b(a)(4)
or Sec. 60.44b(l) is determined by the three-run average (nominal 1-
hour runs) for the initial and subsequent performance tests; or
(2) The owner or operator of an affected facility may elect to
determine compliance on a 30-day rolling average basis by using the
CEMS specified under Sec. 60.48b for measuring NOX and
O2 and meet the requirements of Sec. 60.48b. The sampling
site shall be located at the outlet from the steam generating unit. The
NOX emissions rate at the outlet from the steam generating
unit shall constitute the NOX emissions rate from the duct
burner of the combined cycle system.
(g) The owner or operator of an affected facility described in
Sec. 60.44b(j) or Sec. 60.44b(k) shall demonstrate the maximum heat
input capacity of the steam generating unit by operating the facility
at maximum capacity for 24 hours. The owner or operator of an affected
facility shall determine the maximum heat input capacity using the heat
loss method described in sections 5 and 7.3 of the ASME Power Test
Codes 4.1 (incorporated by reference, see Sec. 60.17). This
demonstration of maximum heat input capacity shall be made during the
initial performance test for affected facilities that meet the criteria
of Sec. 60.44b(j). It shall be made within 60 days after achieving the
maximum production rate at which the affected facility will be
operated, but not
[[Page 32752]]
later than 180 days after initial start-up of each facility, for
affected facilities meeting the criteria of Sec. 60.44b(k). Subsequent
demonstrations may be required by the Administrator at any other time.
If this demonstration indicates that the maximum heat input capacity of
the affected facility is less than that stated by the manufacturer of
the affected facility, the maximum heat input capacity determined
during this demonstration shall be used to determine the capacity
utilization rate for the affected facility. Otherwise, the maximum heat
input capacity provided by the manufacturer is used.
(h) The owner or operator of an affected facility described in
Sec. 60.44b(j) that has a heat input capacity greater than 73 MW (250
MMBtu/hr) shall:
(1) Conduct an initial performance test as required under Sec.
60.8 over a minimum of 24 consecutive steam generating unit operating
hours at maximum heat input capacity to demonstrate compliance with the
NOX emission standards under Sec. 60.44b using Method 7,
7A, 7E of appendix A of this part, or other approved reference methods;
and
(2) Conduct subsequent performance tests once per calendar year or
every 400 hours of operation (whichever comes first) to demonstrate
compliance with the NOX emission standards under Sec.
60.44b over a minimum of 3 consecutive steam generating unit operating
hours at maximum heat input capacity using Method 7, 7A, 7E of appendix
A of this part, or other approved reference methods.
(i) The owner or operator of an affected facility seeking to
demonstrate compliance under paragraph Sec. 60.43b(h)(5) shall follow
the applicable procedures under Sec. 60.49b(r).
(j) In place of PM testing with EPA Reference Method 5, 5B, or 17
of appendix A of this part, an owner or operator may elect to install,
calibrate, maintain, and operate a CEMS for monitoring PM emissions
discharged to the atmosphere and record the output of the system. The
owner or operator of an affected facility who elects to continuously
monitor PM emissions instead of conducting performance testing using
EPA Method 5, 5B, or 17 of appendix A of this part shall comply with
the requirements specified in paragraphs (j)(1) through (j)(13) of this
section.
(1) Notify the Administrator one month before starting use of the
system.
(2) Notify the Administrator one month before stopping use of the
system.
(3) The monitor shall be installed, evaluated, and operated in
accordance with Sec. 60.13 of subpart A of this part.
(4) The initial performance evaluation shall be completed no later
than 180 days after the date of initial startup of the affected
facility, as specified under Sec. 60.8 of subpart A of this part or
within 180 days of notification to the Administrator of use of the CEMS
if the owner or operator was previously determining compliance by
Method 5, 5B, or 17 of appendix A of this part performance tests,
whichever is later.
(5) The owner or operator of an affected facility shall conduct an
initial performance test for PM emissions as required under Sec. 60.8
of subpart A of this part. Compliance with the PM emission limit shall
be determined by using the CEMS specified in paragraph (j) of this
section to measure PM and calculating a 24-hour block arithmetic
average emission concentration using EPA Reference Method 19 of
appendix A of this part, section 4.1.
(6) Compliance with the PM emission limit shall be determined based
on the 24-hour daily (block) average of the hourly arithmetic average
emission concentrations using CEMS outlet data.
(7) At a minimum, valid CEMS hourly averages shall be obtained as
specified in paragraphs (j)(7)(i) of this section for 75 percent of the
total operating hours per 30-day rolling average.
(i) At least two data points per hour shall be used to calculate
each 1-hour arithmetic average.
(ii) [Reserved]
(8) The 1-hour arithmetic averages required under paragraph (j)(7)
of this section shall be expressed in ng/J or lb/MMBtu heat input and
shall be used to calculate the boiler operating day daily arithmetic
average emission concentrations. The 1-hour arithmetic averages shall
be calculated using the data points required under Sec. 60.13(e)(2) of
subpart A of this part.
(9) All valid CEMS data shall be used in calculating average
emission concentrations even if the minimum CEMS data requirements of
paragraph (j)(7) of this section are not met.
(10) The CEMS shall be operated according to Performance
Specification 11 in appendix B of this part.
(11) During the correlation testing runs of the CEMS required by
Performance Specification 11 in appendix B of this part, PM and
O2 (or CO2) data shall be collected concurrently
(or within a 30-to 60-minute period) by both the continuous emission
monitors and the test methods specified in paragraphs (j)(7)(i) of this
section.
(i) For PM, EPA Reference Method 5, 5B, or 17 of appendix A of this
part shall be used.
(ii) For O2 (or CO2), EPA reference Method 3,
3A, or 3B of appendix A of this part, as applicable shall be used.
(12) Quarterly accuracy determinations and daily calibration drift
tests shall be performed in accordance with procedure 2 in appendix F
of this part. Relative Response Audit's must be performed annually and
Response Correlation Audits must be performed every 3 years.
(13) When PM emissions data are not obtained because of CEMS
breakdowns, repairs, calibration checks, and zero and span adjustments,
emissions data shall be obtained by using other monitoring systems as
approved by the Administrator or EPA Reference Method 19 of appendix A
of this part to provide, as necessary, valid emissions data for a
minimum of 75 percent of total operating hours per 30-day rolling
average.
Sec. 60.47b Emission monitoring for sulfur dioxide.
(a) Except as provided in paragraphs (b), (f), and (h) of this
section, the owner or operator of an affected facility subject to the
SO2 standards under Sec. 60.42b shall install, calibrate,
maintain, and operate CEMS for measuring SO2 concentrations
and either O2 or CO2 concentrations and shall
record the output of the systems. For units complying with the percent
reduction standard, the SO2 and either O2 or
CO2 concentrations shall both be monitored at the inlet and
outlet of the SO2 control device. If the owner or operator
has installed and certified SO2 and O2 or
CO2 CEMS according to the requirements of Sec. 75.20(c)(1)
of this chapter and appendix A to part 75 of this chapter, and is
continuing to meet the ongoing quality assurance requirements of Sec.
75.21 of this chapter and appendix B to part 75 of this chapter, those
CEMS may be used to meet the requirements of this section, provided
that:
(1) When relative accuracy testing is conducted, SO2
concentration data and CO2 (or O2) data are
collected simultaneously; and
(2) In addition to meeting the applicable SO2 and
CO2 (or O2) relative accuracy specifications in
Figure 2 of appendix B to part 75 of this chapter, the relative
accuracy (RA) standard in section 13.2 of Performance Specification 2
in appendix B to this part is met when the RA is calculated on a lb/
MMBtu basis; and
(3) The reporting requirements of Sec. 60.49b are met.
SO2 and CO2 (or O2)
[[Page 32753]]
data used to meet the requirements of Sec. 60.49b shall not include
substitute data values derived from the missing data procedures in
subpart D of part 75 of this chapter, nor shall the SO2 data
have been bias adjusted according to the procedures of part 75 of this
chapter.
(b) As an alternative to operating CEMS as required under paragraph
(a) of this section, an owner or operator may elect to determine the
average SO2 emissions and percent reduction by:
(1) Collecting coal or oil samples in an as-fired condition at the
inlet to the steam generating unit and analyzing them for sulfur and
heat content according to Method 19 of appendix A of this part. Method
19 of appendix A of this part provides procedures for converting these
measurements into the format to be used in calculating the average
SO2 input rate, or
(2) Measuring SO2 according to Method 6B of appendix A
of this part at the inlet or outlet to the SO2 control
system. An initial stratification test is required to verify the
adequacy of the Method 6B of appendix A of this part sampling location.
The stratification test shall consist of three paired runs of a
suitable SO2 and CO2 measurement train operated
at the candidate location and a second similar train operated according
to the procedures in section 3.2 and the applicable procedures in
section 7 of Performance Specification 2. Method 6B of appendix A of
this part, Method 6A of appendix A of this part, or a combination of
Methods 6 and 3 or 3B of appendix A of this part or Methods 6C and 3A
of appendix A of this part are suitable measurement techniques. If
Method 6B of appendix A of this part is used for the second train,
sampling time and timer operation may be adjusted for the
stratification test as long as an adequate sample volume is collected;
however, both sampling trains are to be operated similarly. For the
location to be adequate for Method 6B of appendix A of this part 24-
hour tests, the mean of the absolute difference between the three
paired runs must be less than 10 percent.
(3) A daily SO2 emission rate, ED, shall be
determined using the procedure described in Method 6A of appendix A of
this part, section 7.6.2 (Equation 6A-8) and stated in ng/J (lb/MMBtu)
heat input.
(4) The mean 30-day emission rate is calculated using the daily
measured values in ng/J (lb/MMBtu) for 30 successive steam generating
unit operating days using equation 19-20 of Method 19 of appendix A of
this part.
(c) The owner or operator of an affected facility shall obtain
emission data for at least 75 percent of the operating hours in at
least 22 out of 30 successive boiler operating days. If this minimum
data requirement is not met with a single monitoring system, the owner
or operator of the affected facility shall supplement the emission data
with data collected with other monitoring systems as approved by the
Administrator or the reference methods and procedures as described in
paragraph (b) of this section.
(d) The 1-hour average SO2 emission rates measured by
the CEMS required by paragraph (a) of this section and required under
Sec. 60.13(h) is expressed in ng/J or lb/MMBtu heat input and is used
to calculate the average emission rates under Sec. 60.42(b). Each 1-
hour average SO2 emission rate must be based on 30 or more
minutes of steam generating unit operation. The hourly averages shall
be calculated according to Sec. 60.13(h)(2). Hourly SO2
emission rates are not calculated if the affected facility is operated
less than 30 minutes in a given clock hour and are not counted toward
determination of a steam generating unit operating day.
(e) The procedures under Sec. 60.13 shall be followed for
installation, evaluation, and operation of the CEMS.
(1) Except as provided for in paragraph (e)(4) of this section, all
CEMS shall be operated in accordance with the applicable procedures
under Performance Specifications 1, 2, and 3 of appendix B of this
part.
(2) Except as provided for in paragraph (e)(4) of this section,
quarterly accuracy determinations and daily calibration drift tests
shall be performed in accordance with Procedure 1 of appendix F of this
part.
(3) For affected facilities combusting coal or oil, alone or in
combination with other fuels, the span value of the SO2 CEMS
at the inlet to the SO2 control device is 125 percent of the
maximum estimated hourly potential SO2 emissions of the fuel
combusted, and the span value of the CEMS at the outlet to the
SO2 control device is 50 percent of the maximum estimated
hourly potential SO2 emissions of the fuel combusted.
Alternatively, SO2 span values determined according to
section 2.1.1 in appendix A to part 75 of this chapter may be used.
(4) As an alternative to meeting the requirements of requirements
of paragraphs (e)(1) and (e)(2) of this section, the owner or operator
may elect to implement the following alternative data accuracy
assessment procedures:
(i) For all required CO2 and O2 monitors and
for SO2 and NOX monitors with span values less
than 100 ppm, the daily calibration error test and calibration
adjustment procedures described in sections 2.1.1 and 2.1.3 of appendix
B to part 75 of this chapter may be followed instead of the CD
assessment procedures in Procedure 1, section 4.1 of appendix F to this
part. If this option is selected, the data validation and out-of-
control provisions in sections 2.1.4 and 2.1.5 of appendix B to part 75
of this chapter shall be followed instead of the excessive CD and out-
of-control criteria in Procedure 1, section 4.3 of appendix F to this
part. For the purposes of data validation under this subpart, the
excessive CD and out-of-control criteria in Procedure 1, section 4.3 of
appendix F to this part shall apply to SO2 and
NOX span values less than 100 ppm;
(ii) For all required CO2 and O2 monitors and
for SO2 and NOX monitors with span values greater
than 30 ppm, quarterly linearity checks may be performed in accordance
with section 2.2.1 of appendix B to part 75 of this chapter, instead of
performing the cylinder gas audits (CGAs) described in Procedure 1,
section 5.1.2 of appendix F to this part. If this option is selected:
The frequency of the linearity checks shall be as specified in section
2.2.1 of appendix B to part 75 of this chapter; the applicable
linearity specifications in section 3.2 of appendix A to part 75 of
this chapter shall be met; the data validation and out-of-control
criteria in section 2.2.3 of appendix B to part 75 of this chapter
shall be followed instead of the excessive audit inaccuracy and out-of-
control criteria in Procedure 1, section 5.2 of appendix F to this
part; and the grace period provisions in section 2.2.4 of appendix B to
part 75 of this chapter shall apply. For the purposes of data
validation under this subpart, the cylinder gas audits described in
Procedure 1, section 5.1.2 of appendix F to this part shall be
performed for SO2 and NOX span values less than
or equal to 30 ppm; and
(iii) For SO2, CO2, and O2
monitoring systems and for NOX emission rate monitoring
systems, RATAs may be performed in accordance with section 2.3 of
appendix B to part 75 of this chapter instead of following the
procedures described in Procedure 1, section 5.1.1 of appendix F to
this part. If this option is selected: The frequency of each RATA shall
be as specified in section 2.3.1 of appendix B to part 75 of this
chapter; the applicable relative accuracy specifications shown in
Figure 2 in appendix B to part 75 of this chapter shall be met; the
data validation and out-of-control criteria in section 2.3.2 of
appendix B to part 75 of this chapter shall be followed instead of the
excessive audit inaccuracy and out-of-control criteria in Procedure 1,
section
[[Page 32754]]
5.2 of appendix F to this part; and the grace period provisions in
section 2.3.3 of appendix B to part 75 of this chapter shall apply. For
the purposes of data validation under this subpart, the relative
accuracy specification in section 13.2 of Performance Specification 2
in appendix B to this part shall be met on a lb/MMBtu basis for
SO2 (regardless of the SO2 emission level during
the RATA), and for NOX when the average NOX
emission rate measured by the reference method during the RATA is less
than 0.100 lb/MMBtu.
(f) The owner or operator of an affected facility that combusts
very low sulfur oil or is demonstrating compliance under Sec.
60.45b(k) is not subject to the emission monitoring requirements under
paragraph (a) of this section if the owner or operator maintains fuel
records as described in Sec. 60.49b(r).
Sec. 60.48b Emission monitoring for particulate matter and nitrogen
oxides.
(a) Except as provided in paragraph (j) of this section, the owner
or operator of an affected facility subject to the opacity standard
under Sec. 60.43b shall install, calibrate, maintain, and operate a
CEMS for measuring the opacity of emissions discharged to the
atmosphere and record the output of the system.
(b) Except as provided under paragraphs (g), (h), and (i) of this
section, the owner or operator of an affected facility subject to a
NOX standard under Sec. 60.44b shall comply with either
paragraphs (b)(1) or (b)(2) of this section.
(1) Install, calibrate, maintain, and operate CEMS for measuring
NOX and O2 (or CO2) emissions
discharged to the atmosphere, and shall record the output of the
system; or
(2) If the owner or operator has installed a NOX
emission rate CEMS to meet the requirements of part 75 of this chapter
and is continuing to meet the ongoing requirements of part 75 of this
chapter, that CEMS may be used to meet the requirements of this
section, except that the owner or operator shall also meet the
requirements of Sec. 60.49b. Data reported to meet the requirements of
Sec. 60.49b shall not include data substituted using the missing data
procedures in subpart D of part 75 of this chapter, nor shall the data
have been bias adjusted according to the procedures of part 75 of this
chapter.
(c) The CEMS required under paragraph (b) of this section shall be
operated and data recorded during all periods of operation of the
affected facility except for CEMS breakdowns and repairs. Data is
recorded during calibration checks, and zero and span adjustments.
(d) The 1-hour average NOX emission rates measured by
the continuous NOX monitor required by paragraph (b) of this
section and required under Sec. 60.13(h) shall be expressed in ng/J or
lb/MMBtu heat input and shall be used to calculate the average emission
rates under Sec. 60.44b. The 1-hour averages shall be calculated using
the data points required under Sec. 60.13(h)(2).
(e) The procedures under Sec. 60.13 shall be followed for
installation, evaluation, and operation of the continuous monitoring
systems.
(1) For affected facilities combusting coal, wood or municipal-type
solid waste, the span value for a continuous monitoring system for
measuring opacity shall be between 60 and 80 percent.
(2) For affected facilities combusting coal, oil, or natural gas,
the span value for NOX is determined using one of the
following procedures:
(i) Except as provided under paragraph (e)(2)(ii) of this section,
NOX span values shall be determined as follows:
------------------------------------------------------------------------
Fuel Span values for NOX (ppm)
------------------------------------------------------------------------
Natural gas......................... 500.
Oil................................. 500.
Coal................................ 1,000.
Mixtures............................ 500 (x + y) + 1,000z.
------------------------------------------------------------------------
Where:
x = Fraction of total heat input derived from natural gas;
y = Fraction of total heat input derived from oil; and
z = Fraction of total heat input derived from coal.
(ii) As an alternative to meeting the requirements of paragraph
(e)(2)(i) of this section, the owner or operator of an affected
facility may elect to use the NOX span values determined
according to section 2.1.2 in appendix A to part 75 of this chapter.
(3) All span values computed under paragraph (e)(2)(i) of this
section for combusting mixtures of regulated fuels are rounded to the
nearest 500 ppm. Span values computed under paragraph (e)(2)(ii) of
this section shall be rounded off according to section 2.1.2 in
appendix A to part 75 of this chapter.
(f) When NOX emission data are not obtained because of
CEMS breakdowns, repairs, calibration checks and zero and span
adjustments, emission data will be obtained by using standby monitoring
systems, Method 7 of appendix A of this part, Method 7A of appendix A
of this part, or other approved reference methods to provide emission
data for a minimum of 75 percent of the operating hours in each steam
generating unit operating day, in at least 22 out of 30 successive
steam generating unit operating days.
(g) The owner or operator of an affected facility that has a heat
input capacity of 73 MW (250 MMBtu/hr) or less, and that has an annual
capacity factor for residual oil having a nitrogen content of 0.30
weight percent or less, natural gas, distillate oil, or any mixture of
these fuels, greater than 10 percent (0.10) shall:
(1) Comply with the provisions of paragraphs (b), (c), (d), (e)(2),
(e)(3), and (f) of this section; or
(2) Monitor steam generating unit operating conditions and predict
NOX emission rates as specified in a plan submitted pursuant
to Sec. 60.49b(c).
(h) The owner or operator of a duct burner, as described in Sec.
60.41b, that is subject to the NOX standards of Sec.
60.44b(a)(4) or Sec. 60.44b(l) is not required to install or operate a
continuous emissions monitoring system to measure NOX
emissions.
(i) The owner or operator of an affected facility described in
Sec. 60.44b(j) or Sec. 60.44b(k) is not required to install or
operate a CEMS for measuring NOX emissions.
(j) The owner or operator of an affected facility that meets the
conditions in either paragraph (j)(1), (2), (3), (4), or (5) of this
section is not required to install or operate a COMS for measuring
opacity if:
(1) The affected facility uses a PM CEMS to monitor PM emissions;
or
(2) The affected facility burns only liquid (excluding residual
oil) or gaseous fuels with potential SO2 emissions rates of
26 ng/J (0.060 lb/MMBtu) or less and does not use a post-combustion
technology to reduce SO2 or PM emissions. The owner or
operator must maintain fuel records of the sulfur content of the fuels
burned, as described under Sec. 60.49b(r); or
(3) The affected facility burns coke oven gas alone or in
combination with fuels meeting the criteria in paragraph (j)(2) of this
section and does not use a post-combustion technology to reduce
SO2 or PM emissions; or
(4) The affected facility does not use post-combustion technology
(except a wet scrubber) for reducing PM, SO2, or carbon
monoxide (CO) emissions, burns only gaseous fuels or fuel oils that
contain less than or equal to 0.30 weight percent sulfur, and is
operated such that emissions of CO to the atmosphere from the affected
facility are maintained at levels less than or equal to 0.15 lb/MMBtu
on a steam generating unit operating day average basis. Owners and
[[Page 32755]]
operators of affected facilities electing to comply with this paragraph
must demonstrate compliance according to the procedures specified in
paragraphs (j)(4)(i) through (iv) of this section.
(i) You must monitor CO emissions using a CEMS according to the
procedures specified in paragraphs (j)(4)(i)(A) through (D) of this
section.
(A) The CO CEMS must be installed, certified, maintained, and
operated according to the provisions in Sec. 60.58b(i)(3) of subpart
Eb of this part.
(B) Each 1-hour CO emissions average is calculated using the data
points generated by the CO CEMS expressed in parts per million by
volume corrected to 3 percent oxygen (dry basis).
(C) At a minimum, valid 1-hour CO emissions averages must be
obtained for at least 90 percent of the operating hours on a 30-day
rolling average basis. At least two data points per hour must be used
to calculate each 1-hour average.
(D) Quarterly accuracy determinations and daily calibration drift
tests for the CO CEMS must be performed in accordance with procedure 1
in appendix F of this part.
(ii) You must calculate the 1-hour average CO emissions levels for
each steam generating unit operating day by multiplying the average
hourly CO output concentration measured by the CO CEMS times the
corresponding average hourly flue gas flow rate and divided by the
corresponding average hourly heat input to the affected source. The 24-
hour average CO emission level is determined by calculating the
arithmetic average of the hourly CO emission levels computed for each
steam generating unit operating day.
(iii) You must evaluate the preceding 24-hour average CO emission
level each steam generating unit operating day excluding periods of
affected source startup, shutdown, or malfunction. If the 24-hour
average CO emission level is greater than 0.15 lb/MMBtu, you must
initiate investigation of the relevant equipment and control systems
within 24 hours of the first discovery of the high emission incident
and, take the appropriate corrective action as soon as practicable to
adjust control settings or repair equipment to reduce the 24-hour
average CO emission level to 0.15 lb/MMBtu or less.
(iv) You must record the CO measurements and calculations performed
according to paragraph (j)(4) of this section and any corrective
actions taken. The record of corrective action taken must include the
date and time during which the 24-hour average CO emission level was
greater than 0.15 lb/MMBtu, and the date, time, and description of the
corrective action.
(5) The affected facility burns only gaseous fuels or fuel oils
that contain less than or equal to 0.30 weight percent sulfur and
operates according to a written site-specific monitoring plan approved
by the appropriate delegated permitting authority. This monitoring plan
must include procedures and criteria for establishing and monitoring
specific parameters for the affected facility indicative of compliance
with the opacity standard.
(k) Owners or operators complying with the PM emission limit by
using a PM CEMS monitor instead of monitoring opacity must calibrate,
maintain, and operate a CEMS, and record the output of the system, for
PM emissions discharged to the atmosphere as specified in Sec.
60.46b(j). The CEMS specified in paragraph Sec. 60.46b(j) shall be
operated and data recorded during all periods of operation of the
affected facility except for CEMS breakdowns and repairs. Data is
recorded during calibration checks, and zero and span adjustments.
Sec. 60.49b Reporting and recordkeeping requirements.
(a) The owner or operator of each affected facility shall submit
notification of the date of initial startup, as provided by Sec. 60.7.
This notification shall include:
(1) The design heat input capacity of the affected facility and
identification of the fuels to be combusted in the affected facility;
(2) If applicable, a copy of any federally enforceable requirement
that limits the annual capacity factor for any fuel or mixture of fuels
under Sec. Sec. 60.42b(d)(1), 60.43b(a)(2), (a)(3)(iii), (c)(2)(ii),
(d)(2)(iii), 60.44b(c), (d), (e), (i), (j), (k), 60.45b(d), (g),
60.46b(h), or 60.48b(i);
(3) The annual capacity factor at which the owner or operator
anticipates operating the facility based on all fuels fired and based
on each individual fuel fired; and
(4) Notification that an emerging technology will be used for
controlling emissions of SO2. The Administrator will examine
the description of the emerging technology and will determine whether
the technology qualifies as an emerging technology. In making this
determination, the Administrator may require the owner or operator of
the affected facility to submit additional information concerning the
control device. The affected facility is subject to the provisions of
Sec. 60.42b(a) unless and until this determination is made by the
Administrator.
(b) The owner or operator of each affected facility subject to the
SO2, PM, and/or NOX emission limits under
Sec. Sec. 60.42b, 60.43b, and 60.44b shall submit to the Administrator
the performance test data from the initial performance test and the
performance evaluation of the CEMS using the applicable performance
specifications in appendix B of this part. The owner or operator of
each affected facility described in Sec. 60.44b(j) or Sec. 60.44b(k)
shall submit to the Administrator the maximum heat input capacity data
from the demonstration of the maximum heat input capacity of the
affected facility.
(c) The owner or operator of each affected facility subject to the
NOX standard of Sec. 60.44b who seeks to demonstrate
compliance with those standards through the monitoring of steam
generating unit operating conditions under the provisions of Sec.
60.48b(g)(2) shall submit to the Administrator for approval a plan that
identifies the operating conditions to be monitored under Sec.
60.48b(g)(2) and the records to be maintained under Sec. 60.49b(j).
This plan shall be submitted to the Administrator for approval within
360 days of the initial startup of the affected facility. If the plan
is approved, the owner or operator shall maintain records of predicted
nitrogen oxide emission rates and the monitored operating conditions,
including steam generating unit load, identified in the plan. The plan
shall:
(1) Identify the specific operating conditions to be monitored and
the relationship between these operating conditions and NOX
emission rates (i.e., ng/J or lbs/MMBtu heat input). Steam generating
unit operating conditions include, but are not limited to, the degree
of staged combustion (i.e., the ratio of primary air to secondary and/
or tertiary air) and the level of excess air (i.e., flue gas
O2 level);
(2) Include the data and information that the owner or operator
used to identify the relationship between NOX emission rates
and these operating conditions; and
(3) Identify how these operating conditions, including steam
generating unit load, will be monitored under Sec. 60.48b(g) on an
hourly basis by the owner or operator during the period of operation of
the affected facility; the quality assurance procedures or practices
that will be employed to ensure that the data generated by monitoring
these operating conditions will be representative and accurate; and the
type and format of the records of these operating conditions, including
steam generating unit load, that will be
[[Page 32756]]
maintained by the owner or operator under Sec. 60.49b(j).
(d) The owner or operator of an affected facility shall record and
maintain records of the amounts of each fuel combusted during each day
and calculate the annual capacity factor individually for coal,
distillate oil, residual oil, natural gas, wood, and municipal-type
solid waste for the reporting period. The annual capacity factor is
determined on a 12-month rolling average basis with a new annual
capacity factor calculated at the end of each calendar month.
(e) For an affected facility that combusts residual oil and meets
the criteria under Sec. Sec. 60.46b(e)(4), 60.44b(j), or (k), the
owner or operator shall maintain records of the nitrogen content of the
residual oil combusted in the affected facility and calculate the
average fuel nitrogen content for the reporting period. The nitrogen
content shall be determined using ASTM Method D4629 (incorporated by
reference, see Sec. 60.17), or fuel suppliers. If residual oil blends
are being combusted, fuel nitrogen specifications may be prorated based
on the ratio of residual oils of different nitrogen content in the fuel
blend.
(f) For facilities subject to the opacity standard under Sec.
60.43b, the owner or operator shall maintain records of opacity.
(g) Except as provided under paragraph (p) of this section, the
owner or operator of an affected facility subject to the NOX
standards under Sec. 60.44b shall maintain records of the following
information for each steam generating unit operating day:
(1) Calendar date;
(2) The average hourly NOX emission rates (expressed as
NO2) (ng/J or lb/MMBtu heat input) measured or predicted;
(3) The 30-day average NOX emission rates (ng/J or lb/
MMBtu heat input) calculated at the end of each steam generating unit
operating day from the measured or predicted hourly nitrogen oxide
emission rates for the preceding 30 steam generating unit operating
days;
(4) Identification of the steam generating unit operating days when
the calculated 30-day average NOX emission rates are in
excess of the NOX emissions standards under Sec. 60.44b,
with the reasons for such excess emissions as well as a description of
corrective actions taken;
(5) Identification of the steam generating unit operating days for
which pollutant data have not been obtained, including reasons for not
obtaining sufficient data and a description of corrective actions
taken;
(6) Identification of the times when emission data have been
excluded from the calculation of average emission rates and the reasons
for excluding data;
(7) Identification of ``F'' factor used for calculations, method of
determination, and type of fuel combusted;
(8) Identification of the times when the pollutant concentration
exceeded full span of the CEMS;
(9) Description of any modifications to the CEMS that could affect
the ability of the CEMS to comply with Performance Specification 2 or
3; and
(10) Results of daily CEMS drift tests and quarterly accuracy
assessments as required under appendix F, Procedure 1 of this part.
(h) The owner or operator of any affected facility in any category
listed in paragraphs (h)(1) or (2) of this section is required to
submit excess emission reports for any excess emissions that occurred
during the reporting period.
(1) Any affected facility subject to the opacity standards under
Sec. 60.43b(e) or to the operating parameter monitoring requirements
under Sec. 60.13(i)(1).
(2) Any affected facility that is subject to the NOX
standard of Sec. 60.44b, and that:
(i) Combusts natural gas, distillate oil, or residual oil with a
nitrogen content of 0.3 weight percent or less; or
(ii) Has a heat input capacity of 73 MW (250 MMBtu/hr) or less and
is required to monitor NOX emissions on a continuous basis
under Sec. 60.48b(g)(1) or steam generating unit operating conditions
under Sec. 60.48b(g)(2).
(3) For the purpose of Sec. 60.43b, excess emissions are defined
as all 6-minute periods during which the average opacity exceeds the
opacity standards under Sec. 60.43b(f).
(4) For purposes of Sec. 60.48b(g)(1), excess emissions are
defined as any calculated 30-day rolling average NOX
emission rate, as determined under Sec. 60.46b(e), that exceeds the
applicable emission limits in Sec. 60.44b.
(i) The owner or operator of any affected facility subject to the
continuous monitoring requirements for NOX under Sec.
60.48(b) shall submit reports containing the information recorded under
paragraph (g) of this section.
(j) The owner or operator of any affected facility subject to the
SO2 standards under Sec. 60.42b shall submit reports.
(k) For each affected facility subject to the compliance and
performance testing requirements of Sec. 60.45b and the reporting
requirement in paragraph (j) of this section, the following information
shall be reported to the Administrator:
(1) Calendar dates covered in the reporting period;
(2) Each 30-day average SO2 emission rate (ng/J or lb/
MMBtu heat input) measured during the reporting period, ending with the
last 30-day period; reasons for noncompliance with the emission
standards; and a description of corrective actions taken;
(3) Each 30-day average percent reduction in SO2
emissions calculated during the reporting period, ending with the last
30-day period; reasons for noncompliance with the emission standards;
and a description of corrective actions taken;
(4) Identification of the steam generating unit operating days that
coal or oil was combusted and for which SO2 or diluent
(O2 or CO2) data have not been obtained by an
approved method for at least 75 percent of the operating hours in the
steam generating unit operating day; justification for not obtaining
sufficient data; and description of corrective action taken;
(5) Identification of the times when emissions data have been
excluded from the calculation of average emission rates; justification
for excluding data; and description of corrective action taken if data
have been excluded for periods other than those during which coal or
oil were not combusted in the steam generating unit;
(6) Identification of ``F'' factor used for calculations, method of
determination, and type of fuel combusted;
(7) Identification of times when hourly averages have been obtained
based on manual sampling methods;
(8) Identification of the times when the pollutant concentration
exceeded full span of the CEMS;
(9) Description of any modifications to the CEMS that could affect
the ability of the CEMS to comply with Performance Specification 2 or
3;
(10) Results of daily CEMS drift tests and quarterly accuracy
assessments as required under appendix F, Procedure 1 of this part; and
(11) The annual capacity factor of each fired as provided under
paragraph (d) of this section.
(l) For each affected facility subject to the compliance and
performance testing requirements of Sec. 60.45b(d) and the reporting
requirements of paragraph (j) of this section, the following
information shall be reported to the Administrator:
(1) Calendar dates when the facility was in operation during the
reporting period;
(2) The 24-hour average SO2 emission rate measured for
each steam generating unit operating day during the reporting
[[Page 32757]]
period that coal or oil was combusted, ending in the last 24-hour
period in the quarter; reasons for noncompliance with the emission
standards; and a description of corrective actions taken;
(3) Identification of the steam generating unit operating days that
coal or oil was combusted for which S02 or diluent
(O2 or CO2) data have not been obtained by an
approved method for at least 75 percent of the operating hours;
justification for not obtaining sufficient data; and description of
corrective action taken;
(4) Identification of the times when emissions data have been
excluded from the calculation of average emission rates; justification
for excluding data; and description of corrective action taken if data
have been excluded for periods other than those during which coal or
oil were not combusted in the steam generating unit;
(5) Identification of ``F'' factor used for calculations, method of
determination, and type of fuel combusted;
(6) Identification of times when hourly averages have been obtained
based on manual sampling methods;
(7) Identification of the times when the pollutant concentration
exceeded full span of the CEMS;
(8) Description of any modifications to the CEMS that could affect
the ability of the CEMS to comply with Performance Specification 2 or
3; and
(9) Results of daily CEMS drift tests and quarterly accuracy
assessments as required under Procedure 1 of appendix F 1 of this part.
If the owner or operator elects to implement the alternative data
assessment procedures described in Sec. Sec. 60.47b(e)(4)(i) through
(e)(4)(iii), each data assessment report shall include a summary of the
results of all of the RATAs, linearity checks, CGAs, and calibration
error or drift assessments required by Sec. Sec. 60.47b(e)(4)(i)
through (e)(4)(iii).
(m) For each affected facility subject to the SO2
standards under Sec. 60.42(b) for which the minimum amount of data
required under Sec. 60.47b(f) were not obtained during the reporting
period, the following information is reported to the Administrator in
addition to that required under paragraph (k) of this section:
(1) The number of hourly averages available for outlet emission
rates and inlet emission rates;
(2) The standard deviation of hourly averages for outlet emission
rates and inlet emission rates, as determined in Method 19 of appendix
A of this part, section 7;
(3) The lower confidence limit for the mean outlet emission rate
and the upper confidence limit for the mean inlet emission rate, as
calculated in Method 19 of appendix A of this part, section 7; and
(4) The ratio of the lower confidence limit for the mean outlet
emission rate and the allowable emission rate, as determined in Method
19 of appendix A of this part, section 7.
(n) If a percent removal efficiency by fuel pretreatment (i.e.,
%Rf) is used to determine the overall percent reduction
(i.e., %Ro) under Sec. 60.45b, the owner or operator of the
affected facility shall submit a signed statement with the report.
(1) Indicating what removal efficiency by fuel pretreatment (i.e.,
%Rf) was credited during the reporting period;
(2) Listing the quantity, heat content, and date each pre-treated
fuel shipment was received during the reporting period, the name and
location of the fuel pretreatment facility; and the total quantity and
total heat content of all fuels received at the affected facility
during the reporting period;
(3) Documenting the transport of the fuel from the fuel
pretreatment facility to the steam generating unit; and
(4) Including a signed statement from the owner or operator of the
fuel pretreatment facility certifying that the percent removal
efficiency achieved by fuel pretreatment was determined in accordance
with the provisions of Method 19 of appendix A of this part and listing
the heat content and sulfur content of each fuel before and after fuel
pretreatment.
(o) All records required under this section shall be maintained by
the owner or operator of the affected facility for a period of 2 years
following the date of such record.
(p) The owner or operator of an affected facility described in
Sec. 60.44b(j) or (k) shall maintain records of the following
information for each steam generating unit operating day:
(1) Calendar date;
(2) The number of hours of operation; and
(3) A record of the hourly steam load.
(q) The owner or operator of an affected facility described in
Sec. 60.44b(j) or Sec. 60.44b(k) shall submit to the Administrator a
report containing:
(1) The annual capacity factor over the previous 12 months;
(2) The average fuel nitrogen content during the reporting period,
if residual oil was fired; and
(3) If the affected facility meets the criteria described in Sec.
60.44b(j), the results of any NOX emission tests required
during the reporting period, the hours of operation during the
reporting period, and the hours of operation since the last
NOX emission test.
(r) The owner or operator of an affected facility who elects to use
the fuel based compliance alternatives in Sec. 60.42b or Sec. 60.43b
shall either:
(1) The owner or operator of an affected facility who elects to
demonstrate that the affected facility combusts only very low sulfur
oil under Sec. 60.42b(j)(2) or Sec. 60.42b(k)(2) shall obtain and
maintain at the affected facility fuel receipts from the fuel supplier
that certify that the oil meets the definition of distillate oil as
defined in Sec. 60.41b and the applicable sulfur limit. For the
purposes of this section, the distillate oil need not meet the fuel
nitrogen content specification in the definition of distillate oil.
Reports shall be submitted to the Administrator certifying that only
very low sulfur oil meeting this definition and/or pipeline quality
natural gas was combusted in the affected facility during the reporting
period; or
(2) The owner or operator of an affected facility who elects to
demonstrate compliance based on fuel analysis in Sec. 60.42b or Sec.
60.43b shall develop and submit a site-specific fuel analysis plan to
the Administrator for review and approval no later than 60 days before
the date you intend to demonstrate compliance. Each fuel analysis plan
shall include a minimum initial requirement of weekly testing and each
analysis report shall contain, at a minimum, the following information:
(i) The potential sulfur emissions rate of the representative fuel
mixture in ng/J heat input;
(ii) The method used to determine the potential sulfur emissions
rate of each constituent of the mixture. For distillate oil and natural
gas a fuel receipt or tariff sheet is acceptable;
(iii) The ratio of different fuels in the mixture; and
(iv) The owner or operator can petition the Administrator to
approve monthly or quarterly sampling in place of weekly sampling.
(s) Facility specific NOX standard for Cytec Industries
Fortier Plant's C.AOG incinerator located in Westwego, Louisiana:
(1) Definitions.
Oxidation zone is defined as the portion of the C.AOG incinerator
that extends from the inlet of the oxidizing zone combustion air to the
outlet gas stack.
Reducing zone is defined as the portion of the C.AOG incinerator
that extends from the burner section to the inlet of the oxidizing zone
combustion air.
[[Page 32758]]
Total inlet air is defined as the total amount of air introduced
into the C.AOG incinerator for combustion of natural gas and chemical
by-product waste and is equal to the sum of the air flow into the
reducing zone and the air flow into the oxidation zone.
(2) Standard for nitrogen oxides. (i) When fossil fuel alone is
combusted, the NOX emission limit for fossil fuel in Sec.
60.44b(a) applies.
(ii) When natural gas and chemical by-product waste are
simultaneously combusted, the NOX emission limit is 289 ng/J
(0.67 lb/MMBtu) and a maximum of 81 percent of the total inlet air
provided for combustion shall be provided to the reducing zone of the
C.AOG incinerator.
(3) Emission monitoring. (i) The percent of total inlet air
provided to the reducing zone shall be determined at least every 15
minutes by measuring the air flow of all the air entering the reducing
zone and the air flow of all the air entering the oxidation zone, and
compliance with the percentage of total inlet air that is provided to
the reducing zone shall be determined on a 3-hour average basis.
(ii) The NOX emission limit shall be determined by the
compliance and performance test methods and procedures for
NOX in Sec. 60.46b(i).
(iii) The monitoring of the NOX emission limit shall be
performed in accordance with Sec. 60.48b.
(4) Reporting and recordkeeping requirements. (i) The owner or
operator of the C.AOG incinerator shall submit a report on any
excursions from the limits required by paragraph (a)(2) of this section
to the Administrator with the quarterly report required by paragraph
(i) of this section.
(ii) The owner or operator of the C.AOG incinerator shall keep
records of the monitoring required by paragraph (a)(3) of this section
for a period of 2 years following the date of such record.
(iii) The owner of operator of the C.AOG incinerator shall perform
all the applicable reporting and recordkeeping requirements of this
section.
(t) Facility-specific NOX standard for Rohm and Haas
Kentucky Incorporated's Boiler No. 100 located in Louisville, Kentucky:
(1) Definitions.
Air ratio control damper is defined as the part of the low
NOX burner that is adjusted to control the split of total
combustion air delivered to the reducing and oxidation portions of the
combustion flame.
Flue gas recirculation line is defined as the part of Boiler No.
100 that recirculates a portion of the boiler flue gas back into the
combustion air.
(2) Standard for nitrogen oxides. (i) When fossil fuel alone is
combusted, the NOX emission limit for fossil fuel in Sec.
60.44b(a) applies.
(ii) When fossil fuel and chemical by-product waste are
simultaneously combusted, the NOX emission limit is 473 ng/J
(1.1 lb/MMBtu), and the air ratio control damper tee handle shall be at
a minimum of 5 inches (12.7 centimeters) out of the boiler, and the
flue gas recirculation line shall be operated at a minimum of 10
percent open as indicated by its valve opening position indicator.
(3) Emission monitoring for nitrogen oxides. (i) The air ratio
control damper tee handle setting and the flue gas recirculation line
valve opening position indicator setting shall be recorded during each
8-hour operating shift.
(ii) The NOX emission limit shall be determined by the
compliance and performance test methods and procedures for
NOX in Sec. 60.46b.
(iii) The monitoring of the NOX emission limit shall be
performed in accordance with Sec. 60.48b.
(4) Reporting and recordkeeping requirements. (i) The owner or
operator of Boiler No. 100 shall submit a report on any excursions from
the limits required by paragraph (b)(2) of this section to the
Administrator with the quarterly report required by Sec. 60.49b(i).
(ii) The owner or operator of Boiler No. 100 shall keep records of
the monitoring required by paragraph (b)(3) of this section for a
period of 2 years following the date of such record.
(iii) The owner of operator of Boiler No. 100 shall perform all the
applicable reporting and recordkeeping requirements of Sec. 60.49b.
(u) Site-specific standard for Merck & Co., Inc.'s Stonewall Plant
in Elkton, Virginia. (1) This paragraph (u) applies only to the
pharmaceutical manufacturing facility, commonly referred to as the
Stonewall Plant, located at Route 340 South, in Elkton, Virginia
(``site'') and only to the natural gas-fired boilers installed as part
of the powerhouse conversion required pursuant to 40 CFR 52.2454(g).
The requirements of this paragraph shall apply, and the requirements of
Sec. Sec. 60.40b through 60.49b(t) shall not apply, to the natural
gas-fired boilers installed pursuant to 40 CFR 52.2454(g).
(i) The site shall equip the natural gas-fired boilers with low
NOX technology.
(ii) The site shall install, calibrate, maintain, and operate a
continuous monitoring and recording system for measuring NOX
emissions discharged to the atmosphere and opacity using a continuous
emissions monitoring system or a predictive emissions monitoring
system.
(iii) Within 180 days of the completion of the powerhouse
conversion, as required by 40 CFR 52.2454, the site shall perform a
performance test to quantify criteria pollutant emissions.
(2) [Reserved]
(v) The owner or operator of an affected facility may submit
electronic quarterly reports for SO2 and/or NOX
and/or opacity in lieu of submitting the written reports required under
paragraphs (h), (i), (j), (k) or (l) of this section. The format of
each quarterly electronic report shall be coordinated with the
permitting authority. The electronic report(s) shall be submitted no
later than 30 days after the end of the calendar quarter and shall be
accompanied by a certification statement from the owner or operator,
indicating whether compliance with the applicable emission standards
and minimum data requirements of this subpart was achieved during the
reporting period. Before submitting reports in the electronic format,
the owner or operator shall coordinate with the permitting authority to
obtain their agreement to submit reports in this alternative format.
(w) The reporting period for the reports required under this
subpart is each 6 month period. All reports shall be submitted to the
Administrator and shall be postmarked by the 30th day following the end
of the reporting period.
(x) Facility-specific NOX standard for Weyerhaeuser
Company's No. 2 Power Boiler located in New Bern, North Carolina:
(1) Standard for nitrogen oxides. (i) When fossil fuel alone is
combusted, the NOX emission limit for fossil fuel in Sec.
60.44b(a) applies.
(ii) When fossil fuel and chemical by-product waste are
simultaneously combusted, the NOX emission limit is 215 ng/J
(0.5 lb/MMBtu).
(2) Emission monitoring for nitrogen oxides. (i) The NOX
emissions shall be determined by the compliance and performance test
methods and procedures for NOX in Sec. 60.46b.
(ii) The monitoring of the NOX emissions shall be
performed in accordance with Sec. 60.48b.
(3) Reporting and recordkeeping requirements. (i) The owner or
operator of the No. 2 Power Boiler shall submit a report on any
excursions from the limits required by paragraph (x)(2) of this section
to the Administrator with the quarterly report required by Sec.
60.49b(i).
[[Page 32759]]
(ii) The owner or operator of the No. 2 Power Boiler shall keep
records of the monitoring required by paragraph (x)(3) of this section
for a period of 2 years following the date of such record.
(iii) The owner or operator of the No. 2 Power Boiler shall perform
all the applicable reporting and recordkeeping requirements of Sec.
60.49b.
(y) Facility-specific NOX standard for INEOS USA's AOGI
located in Lima, Ohio:
(1) Standard for NOX. (i) When fossil fuel alone is
combusted, the NOX emission limit for fossil fuel in Sec.
60.44b(a) applies.
(ii) When fossil fuel and chemical byproduct/waste are
simultaneously combusted, the NOX emission limit is 645 ng/J
(1.5 lb/MMBtu).
(2) Emission monitoring for NOX. (i) The NOX
emissions shall be determined by the compliance and performance test
methods and procedures for NOX in Sec. 60.46b.
(ii) The monitoring of the NOX emissions shall be
performed in accordance with Sec. 60.48b.
(3) Reporting and recordkeeping requirements. (i) The owner or
operator of the AOGI shall submit a report on any excursions from the
limits required by paragraph (y)(2) of this section to the
Administrator with the quarterly report required by paragraph (i) of
this section.
(ii) The owner or operator of the AOGI shall keep records of the
monitoring required by paragraph (y)(3) of this section for a period of
2 years following the date of such record.
(iii) The owner or operator of the AOGI shall perform all the
applicable reporting and recordkeeping requirements of this section.
Subpart Dc--[Amended]
0
6. Subpart Dc is revised to read as follows:
Subpart Dc--Standards of Performance for Small Industrial-Commercial-
Institutional Steam Generating Units
Sec.
60.40c Applicability and delegation of authority.
60.41c Definitions.
60.42c Standard for sulfur dioxide (SO2).
60.43c Standard for particulate matter (PM).
60.44c Compliance and performance test methods and procedures for
sulfur dioxide.
60.45c Compliance and performance test methods and procedures for
particulate matter.
60.46c Emission monitoring for sulfur dioxide.
60.47c Emission monitoring for particulate matter.
60.48c Reporting and recordkeeping requirements.
Subpart Dc--Standards of Performance for Small Industrial-
Commercial-Institutional Steam Generating Units
Sec. 60.40c Applicability and delegation of authority.
(a) Except as provided in paragraph (d) of this section, the
affected facility to which this subpart applies is each steam
generating unit for which construction, modification, or reconstruction
is commenced after June 9, 1989 and that has a maximum design heat
input capacity of 29 megawatts (MW) (100 million British thermal units
per hour (MMBtu/hr)) or less, but greater than or equal to 2.9 MW (10
MMBtu/hr).
(b) In delegating implementation and enforcement authority to a
State under section 111(c) of the Clean Air Act, Sec. 60.48c(a)(4)
shall be retained by the Administrator and not transferred to a State.
(c) Steam generating units that meet the applicability requirements
in paragraph (a) of this section are not subject to the sulfur dioxide
(SO2) or particulate matter (PM) emission limits,
performance testing requirements, or monitoring requirements under this
subpart (Sec. Sec. 60.42c, 60.43c, 60.44c, 60.45c, 60.46c, or 60.47c)
during periods of combustion research, as defined in Sec. 60.41c.
(d) Any temporary change to an existing steam generating unit for
the purpose of conducting combustion research is not considered a
modification under Sec. 60.14.
(e) Heat recovery steam generators that are associated with
combined cycle gas turbines and meet the applicability requirements of
subpart GG or KKKK of this part are not subject to this subpart. This
subpart will continue to apply to all other heat recovery steam
generators that are capable of combusting more than or equal to 2.9 MW
(10 MMBtu/hr) heat input of fossil fuel but less than or equal to 29 MW
(100 MMBtu/hr) heat input of fossil fuel. If the heat recovery steam
generator is subject to this subpart, only emissions resulting from
combustion of fuels in the steam generating unit are subject to this
subpart. (The gas turbine emissions are subject to subpart GG or KKKK,
as applicable, of this part).
(f) Any facility covered by subpart AAAA of this part is not
covered by this subpart.
(g) Any facility covered by an EPA approved State or Federal
section 111(d)/129 plan implementing subpart BBBB of this part is not
covered by this subpart.
Sec. 60.41c Definitions.
As used in this subpart, all terms not defined herein shall have
the meaning given them in the Clean Air Act and in subpart A of this
part.
Annual capacity factor means the ratio between the actual heat
input to a steam generating unit from an individual fuel or combination
of fuels during a period of 12 consecutive calendar months and the
potential heat input to the steam generating unit from all fuels had
the steam generating unit been operated for 8,760 hours during that 12-
month period at the maximum design heat input capacity. In the case of
steam generating units that are rented or leased, the actual heat input
shall be determined based on the combined heat input from all
operations of the affected facility during a period of 12 consecutive
calendar months.
Coal means all solid fuels classified as anthracite, bituminous,
subbituminous, or lignite by the American Society of Testing and
Materials in ASTM D388 (incorporated by reference, see Sec. 60.17),
coal refuse, and petroleum coke. Coal-derived synthetic fuels derived
from coal for the purposes of creating useful heat, including but not
limited to solvent refined coal, gasified coal, coal-oil mixtures, and
coal-water mixtures, are also included in this definition for the
purposes of this subpart.
Coal refuse means any by-product of coal mining or coal cleaning
operations with an ash content greater than 50 percent (by weight) and
a heating value less than 13,900 kilojoules per kilogram (kJ/kg) (6,000
Btu per pound (Btu/lb) on a dry basis.
Cogeneration steam generating unit means a steam generating unit
that simultaneously produces both electrical (or mechanical) and
thermal energy from the same primary energy source.
Combined cycle system means a system in which a separate source
(such as a stationary gas turbine, internal combustion engine, or kiln)
provides exhaust gas to a steam generating unit.
Combustion research means the experimental firing of any fuel or
combination of fuels in a steam generating unit for the purpose of
conducting research and development of more efficient combustion or
more effective prevention or control of air pollutant emissions from
combustion, provided that, during these periods of research and
development, the heat generated is not used for any purpose other than
preheating combustion air for use by that steam generating unit (i.e.,
the heat generated is released to the atmosphere without being used for
space heating, process heating, driving pumps, preheating combustion
air for
[[Page 32760]]
other units, generating electricity, or any other purpose).
Conventional technology means wet flue gas desulfurization
technology, dry flue gas desulfurization technology, atmospheric
fluidized bed combustion technology, and oil hydrodesulfurization
technology.
Distillate oil means fuel oil that complies with the specifications
for fuel oil numbers 1 or 2, as defined by the American Society for
Testing and Materials in ASTM D396 (incorporated by reference, see
Sec. 60.17).
Dry flue gas desulfurization technology means a SO2
control system that is located between the steam generating unit and
the exhaust vent or stack, and that removes sulfur oxides from the
combustion gases of the steam generating unit by contacting the
combustion gases with an alkaline reagent and water, whether introduced
separately or as a premixed slurry or solution and forming a dry powder
material. This definition includes devices where the dry powder
material is subsequently converted to another form. Alkaline reagents
used in dry flue gas desulfurization systems include, but are not
limited to, lime and sodium compounds.
Duct burner means a device that combusts fuel and that is placed in
the exhaust duct from another source (such as a stationary gas turbine,
internal combustion engine, kiln, etc.) to allow the firing of
additional fuel to heat the exhaust gases before the exhaust gases
enter a steam generating unit.
Emerging technology means any SO2 control system that is
not defined as a conventional technology under this section, and for
which the owner or operator of the affected facility has received
approval from the Administrator to operate as an emerging technology
under Sec. 60.48c(a)(4).
Federally enforceable means all limitations and conditions that are
enforceable by the Administrator, including the requirements of 40 CFR
parts 60 and 61, requirements within any applicable State
implementation plan, and any permit requirements established under 40
CFR 52.21 or under 40 CFR 51.18 and 51.24.
Fluidized bed combustion technology means a device wherein fuel is
distributed onto a bed (or series of beds) of limestone aggregate (or
other sorbent materials) for combustion; and these materials are forced
upward in the device by the flow of combustion air and the gaseous
products of combustion. Fluidized bed combustion technology includes,
but is not limited to, bubbling bed units and circulating bed units.
Fuel pretreatment means a process that removes a portion of the
sulfur in a fuel before combustion of the fuel in a steam generating
unit.
Heat input means heat derived from combustion of fuel in a steam
generating unit and does not include the heat derived from preheated
combustion air, recirculated flue gases, or exhaust gases from other
sources (such as stationary gas turbines, internal combustion engines,
and kilns).
Heat transfer medium means any material that is used to transfer
heat from one point to another point.
Maximum design heat input capacity means the ability of a steam
generating unit to combust a stated maximum amount of fuel (or
combination of fuels) on a steady state basis as determined by the
physical design and characteristics of the steam generating unit.
Natural gas means: (1) A naturally occurring mixture of hydrocarbon
and nonhydrocarbon gases found in geologic formations beneath the
earth's surface, of which the principal constituent is methane; or (2)
liquefied petroleum (LP) gas, as defined by the American Society for
Testing and Materials in ASTM D1835 (incorporated by reference, see
Sec. 60.17).
Noncontinental area means the State of Hawaii, the Virgin Islands,
Guam, American Samoa, the Commonwealth of Puerto Rico, or the Northern
Mariana Islands.
Oil means crude oil or petroleum, or a liquid fuel derived from
crude oil or petroleum, including distillate oil and residual oil.
Potential sulfur dioxide emission rate means the theoretical
SO2 emissions (nanograms per joule (ng/J) or lb/MMBtu heat
input) that would result from combusting fuel in an uncleaned state and
without using emission control systems.
Process heater means a device that is primarily used to heat a
material to initiate or promote a chemical reaction in which the
material participates as a reactant or catalyst.
Residual oil means crude oil, fuel oil that does not comply with
the specifications under the definition of distillate oil, and all fuel
oil numbers 4, 5, and 6, as defined by the American Society for Testing
and Materials in ASTM D396 (incorporated by reference, see Sec.
60.17).
Steam generating unit means a device that combusts any fuel and
produces steam or heats water or any other heat transfer medium. This
term includes any duct burner that combusts fuel and is part of a
combined cycle system. This term does not include process heaters as
defined in this subpart.
Steam generating unit operating day means a 24-hour period between
12:00 midnight and the following midnight during which any fuel is
combusted at any time in the steam generating unit. It is not necessary
for fuel to be combusted continuously for the entire 24-hour period.
Wet flue gas desulfurization technology means an SO2
control system that is located between the steam generating unit and
the exhaust vent or stack, and that removes sulfur oxides from the
combustion gases of the steam generating unit by contacting the
combustion gases with an alkaline slurry or solution and forming a
liquid material. This definition includes devices where the liquid
material is subsequently converted to another form. Alkaline reagents
used in wet flue gas desulfurization systems include, but are not
limited to, lime, limestone, and sodium compounds.
Wet scrubber system means any emission control device that mixes an
aqueous stream or slurry with the exhaust gases from a steam generating
unit to control emissions of PM or SO2.
Wood means wood, wood residue, bark, or any derivative fuel or
residue thereof, in any form, including but not limited to sawdust,
sanderdust, wood chips, scraps, slabs, millings, shavings, and
processed pellets made from wood or other forest residues.
Sec. 60.42c Standard for sulfur dioxide (SO2).
(a) Except as provided in paragraphs (b), (c), and (e) of this
section, on and after the date on which the performance test is
completed or required to be completed under Sec. 60.8, whichever date
comes first, the owner or operator of an affected facility that
combusts only coal shall neither: cause to be discharged into the
atmosphere from the affected facility any gases that contain
SO2 in excess of 87 ng/J (0.20 lb/MMBtu) heat input or 10
percent (0.10) of the potential SO2 emission rate (90
percent reduction), nor cause to be discharged into the atmosphere from
the affected facility any gases that contain SO2 in excess
of 520 ng/J (1.2 lb/MMBtu) heat input. If coal is combusted with other
fuels, the affected facility shall neither: cause to be discharged into
the atmosphere from the affected facility any gases that contain
SO2 in excess of 87 ng/J (0.20 lb/MMBtu) heat input or 10
percent (0.10) of the potential SO2 emission rate (90
percent reduction), nor cause to be discharged into the atmosphere from
the affected facility any gases that contain SO2 in excess
of the emission limit is determined pursuant to paragraph (e)(2) of
this section.
[[Page 32761]]
(b) Except as provided in paragraphs (c) and (e) of this section,
on and after the date on which the performance test is completed or
required to be completed under Sec. 60.8, whichever date comes first,
the owner or operator of an affected facility that:
(1) Combusts only coal refuse alone in a fluidized bed combustion
steam generating unit shall neither:
(i) Cause to be discharged into the atmosphere from that affected
facility any gases that contain SO2 in excess of 87 ng/J
(0.20 lb/MMBtu) heat input or 20 percent (0.20) of the potential
SO2 emission rate (80 percent reduction); nor
(ii) Cause to be discharged into the atmosphere from that affected
facility any gases that contain SO2 in excess of
SO2 in excess of 520 ng/J (1.2 lb/MMBtu) heat input. If coal
is fired with coal refuse, the affected facility subject to paragraph
(a) of this section. If oil or any other fuel (except coal) is fired
with coal refuse, the affected facility is subject to the 87 ng/J (0.20
lb/MMBtu) heat input SO2 emissions limit or the 90 percent
SO2 reduction requirement specified in paragraph (a) of this
section and the emission limit is determined pursuant to paragraph
(e)(2) of this section.
(2) Combusts only coal and that uses an emerging technology for the
control of SO2 emissions shall neither:
(i) Cause to be discharged into the atmosphere from that affected
facility any gases that contain SO2 in excess of 50 percent
(0.50) of the potential SO2 emission rate (50 percent
reduction); nor
(ii) Cause to be discharged into the atmosphere from that affected
facility any gases that contain SO2 in excess of 260 ng/J
(0.60 lb/MMBtu) heat input. If coal is combusted with other fuels, the
affected facility is subject to the 50 percent SO2 reduction
requirement specified in this paragraph and the emission limit
determined pursuant to paragraph (e)(2) of this section.
(c) On and after the date on which the initial performance test is
completed or required to be completed under Sec. 60.8, whichever date
comes first, no owner or operator of an affected facility that combusts
coal, alone or in combination with any other fuel, and is listed in
paragraphs (c)(1), (2), (3), or (4) of this section shall cause to be
discharged into the atmosphere from that affected facility any gases
that contain SO2 in excess of the emission limit determined
pursuant to paragraph (e)(2) of this section. Percent reduction
requirements are not applicable to affected facilities under paragraphs
(c)(1), (2), (3), or (4).
(1) Affected facilities that have a heat input capacity of 22 MW
(75 MMBtu/hr) or less.
(2) Affected facilities that have an annual capacity for coal of 55
percent (0.55) or less and are subject to a federally enforceable
requirement limiting operation of the affected facility to an annual
capacity factor for coal of 55 percent (0.55) or less.
(3) Affected facilities located in a noncontinental area.
(4) Affected facilities that combust coal in a duct burner as part
of a combined cycle system where 30 percent (0.30) or less of the heat
entering the steam generating unit is from combustion of coal in the
duct burner and 70 percent (0.70) or more of the heat entering the
steam generating unit is from exhaust gases entering the duct burner.
(d) On and after the date on which the initial performance test is
completed or required to be completed under Sec. 60.8, whichever date
comes first, no owner or operator of an affected facility that combusts
oil shall cause to be discharged into the atmosphere from that affected
facility any gases that contain SO2 in excess of 215 ng/J
(0.50 lb/MMBtu) heat input; or, as an alternative, no owner or operator
of an affected facility that combusts oil shall combust oil in the
affected facility that contains greater than 0.5 weight percent sulfur.
The percent reduction requirements are not applicable to affected
facilities under this paragraph.
(e) On and after the date on which the initial performance test is
completed or required to be completed under Sec. 60.8, whichever date
comes first, no owner or operator of an affected facility that combusts
coal, oil, or coal and oil with any other fuel shall cause to be
discharged into the atmosphere from that affected facility any gases
that contain SO2 in excess of the following:
(1) The percent of potential SO2 emission rate or
numerical SO2 emission rate required under paragraph (a) or
(b)(2) of this section, as applicable, for any affected facility that
(i) Combusts coal in combination with any other fuel;
(ii) Has a heat input capacity greater than 22 MW (75 MMBtu/hr);
and
(iii) Has an annual capacity factor for coal greater than 55
percent (0.55); and
(2) The emission limit determined according to the following
formula for any affected facility that combusts coal, oil, or coal and
oil with any other fuel:
[GRAPHIC] [TIFF OMITTED] TR13JN07.032
Where:
Es = SO2 emission limit, expressed in ng/J or
lb/MMBtu heat input;
Ka = 520 ng/J (1.2 lb/MMBtu);
Kb = 260 ng/J (0.60 lb/MMBtu);
Kc = 215 ng/J (0.50 lb/MMBtu);
Ha = Heat input from the combustion of coal, except coal
combusted in an affected facility subject to paragraph (b)(2) of
this section, in Joules (J) [MMBtu];
Hb = Heat input from the combustion of coal in an
affected facility subject to paragraph (b)(2) of this section, in J
(MMBtu); and
Hc KaHb = Heat input from the
combustion of oil, in J (MMBtu).
(f) Reduction in the potential SO2 emission rate through
fuel pretreatment is not credited toward the percent reduction
requirement under paragraph (b)(2) of this section unless:
(1) Fuel pretreatment results in a 50 percent (0.50) or greater
reduction in the potential SO2 emission rate; and
(2) Emissions from the pretreated fuel (without either combustion
or post-combustion SO2 control) are equal to or less than
the emission limits specified under paragraph (b)(2) of this section.
(g) Except as provided in paragraph (h) of this section, compliance
with the percent reduction requirements, fuel oil sulfur limits, and
emission limits of this section shall be determined on a 30-day rolling
average basis.
(h) For affected facilities listed under paragraphs (h)(1), (2), or
(3) of this section, compliance with the emission limits or fuel oil
sulfur limits under this section may be determined based on a
certification from the fuel supplier, as described under Sec.
60.48c(f), as applicable.
(1) Distillate oil-fired affected facilities with heat input
capacities between 2.9 and 29 MW (10 and 100 MMBtu/hr).
(2) Residual oil-fired affected facilities with heat input
capacities between 2.9 and 8.7 MW (10 and 30 MMBtu/hr).
(3) Coal-fired facilities with heat input capacities between 2.9
and 8.7 MW (10 and 30 MMBtu/hr).
(i) The SO2 emission limits, fuel oil sulfur limits, and
percent reduction requirements under this section apply at all times,
including periods of startup, shutdown, and malfunction.
(j) Only the heat input supplied to the affected facility from the
combustion of coal and oil is counted under this section. No credit is
provided for the heat input to the affected facility from wood or other
fuels or for heat derived from exhaust gases from other sources, such
as stationary gas turbines, internal combustion engines, and kilns.
[[Page 32762]]
Sec. 60.43c Standard for particulate matter (PM).
(a) On and after the date on which the initial performance test is
completed or required to be completed under Sec. 60.8, whichever date
comes first, no owner or operator of an affected facility that
commenced construction, reconstruction, or modification on or before
February 28, 2005, that combusts coal or combusts mixtures of coal with
other fuels and has a heat input capacity of 8.7 MW (30 MMBtu/hr) or
greater, shall cause to be discharged into the atmosphere from that
affected facility any gases that contain PM in excess of the following
emission limits:
(1) 22 ng/J (0.051 lb/MMBtu) heat input if the affected facility
combusts only coal, or combusts coal with other fuels and has an annual
capacity factor for the other fuels of 10 percent (0.10) or less.
(2) 43 ng/J (0.10 lb/MMBtu) heat input if the affected facility
combusts coal with other fuels, has an annual capacity factor for the
other fuels greater than 10 percent (0.10), and is subject to a
federally enforceable requirement limiting operation of the affected
facility to an annual capacity factor greater than 10 percent (0.10)
for fuels other than coal.
(b) On and after the date on which the initial performance test is
completed or required to be completed under Sec. 60.8, whichever date
comes first, no owner or operator of an affected facility that
commenced construction, reconstruction, or modification on or before
February 28, 2005, that combusts wood or combusts mixtures of wood with
other fuels (except coal) and has a heat input capacity of 8.7 MW (30
MMBtu/hr) or greater, shall cause to be discharged into the atmosphere
from that affected facility any gases that contain PM in excess of the
following emissions limits:
(1) 43 ng/J (0.10 lb/MMBtu) heat input if the affected facility has
an annual capacity factor for wood greater than 30 percent (0.30); or
(2) 130 ng/J (0.30 lb/MMBtu) heat input if the affected facility
has an annual capacity factor for wood of 30 percent (0.30) or less and
is subject to a federally enforceable requirement limiting operation of
the affected facility to an annual capacity factor for wood of 30
percent (0.30) or less.
(c) On and after the date on which the initial performance test is
completed or required to be completed under Sec. 60.8, whichever date
comes first, no owner or operator of an affected facility that combusts
coal, wood, or oil and has a heat input capacity of 8.7 MW (30 MMBtu/
hr) or greater shall cause to be discharged into the atmosphere from
that affected facility any gases that exhibit greater than 20 percent
opacity (6-minute average), except for one 6-minute period per hour of
not more than 27 percent opacity.
(d) The PM and opacity standards under this section apply at all
times, except during periods of startup, shutdown, or malfunction.
(e)(1) On and after the date on which the initial performance test
is completed or is required to be completed under Sec. 60.8, whichever
date comes first, no owner or operator of an affected facility that
commences construction, reconstruction, or modification after February
28, 2005, and that combusts coal, oil, wood, a mixture of these fuels,
or a mixture of these fuels with any other fuels and has a heat input
capacity of 8.7 MW (30 MMBtu/hr) or greater shall cause to be
discharged into the atmosphere from that affected facility any gases
that contain PM in excess of 13 ng/J (0.030 lb/MMBtu) heat input,
except as provided in paragraphs (e)(2), (e)(3), and (e)(4) of this
section.
(2) As an alternative to meeting the requirements of paragraph
(e)(1) of this section, the owner or operator of an affected facility
for which modification commenced after February 28, 2005, may elect to
meet the requirements of this paragraph. On and after the date on which
the initial performance test is completed or required to be completed
under Sec. 60.8, whichever date comes first, no owner or operator of
an affected facility that commences modification after February 28,
2005 shall cause to be discharged into the atmosphere from that
affected facility any gases that contain PM in excess of both:
(i) 22 ng/J (0.051 lb/MMBtu) heat input derived from the combustion
of coal, oil, wood, a mixture of these fuels, or a mixture of these
fuels with any other fuels; and
(ii) 0.2 percent of the combustion concentration (99.8 percent
reduction) when combusting coal, oil, wood, a mixture of these fuels,
or a mixture of these fuels with any other fuels.
(3) On and after the date on which the initial performance test is
completed or is required to be completed under Sec. 60.8, whichever
date comes first, no owner or operator of an affected facility that
commences modification after February 28, 2005, and that combusts over
30 percent wood (by heat input) on an annual basis and has a heat input
capacity of 8.7 MW (30 MMBtu/hr) or greater shall cause to be
discharged into the atmosphere from that affected facility any gases
that contain PM in excess of 43 ng/J (0.10 lb/MMBtu) heat input.
(4) On and after the date on which the initial performance test is
completed or is required to be completed under Sec. 60.8, whichever
date comes first, an owner or operator of an affected facility that
commences construction, reconstruction, or modification after February
28, 2005, and that combusts only oil that contains no more than 0.50
weight percent sulfur or a mixture of 0.50 weight percent sulfur oil
with other fuels not subject to a PM standard under Sec. 60.43c and
not using a post-combustion technology (except a wet scrubber) to
reduce PM or SO2 emissions is not subject to the PM limit in
this section.
Sec. 60.44c Compliance and performance test methods and procedures
for sulfur dioxide.
(a) Except as provided in paragraphs (g) and (h) of this section
and Sec. 60.8(b), performance tests required under Sec. 60.8 shall be
conducted following the procedures specified in paragraphs (b), (c),
(d), (e), and (f) of this section, as applicable. Section 60.8(f) does
not apply to this section. The 30-day notice required in Sec. 60.8(d)
applies only to the initial performance test unless otherwise specified
by the Administrator.
(b) The initial performance test required under Sec. 60.8 shall be
conducted over 30 consecutive operating days of the steam generating
unit. Compliance with the percent reduction requirements and
SO2 emission limits under Sec. 60.42c shall be determined
using a 30-day average. The first operating day included in the initial
performance test shall be scheduled within 30 days after achieving the
maximum production rate at which the affect facility will be operated,
but not later than 180 days after the initial startup of the facility.
The steam generating unit load during the 30-day period does not have
to be the maximum design heat input capacity, but must be
representative of future operating conditions.
(c) After the initial performance test required under paragraph (b)
of this section and Sec. 60.8, compliance with the percent reduction
requirements and SO2 emission limits under Sec. 60.42c is
based on the average percent reduction and the average SO2
emission rates for 30 consecutive steam generating unit operating days.
A separate performance test is completed at the end of each steam
generating unit operating day, and a new 30-day average percent
reduction and SO2 emission rate are calculated to show
compliance with the standard.
(d) If only coal, only oil, or a mixture of coal and oil is
combusted in an
[[Page 32763]]
affected facility, the procedures in Method 19 of appendix A of this
part are used to determine the hourly SO2 emission rate
(Eho) and the 30-day average SO2 emission rate
(Eao). The hourly averages used to compute the 30-day
averages are obtained from the CEMS. Method 19 of appendix A of this
part shall be used to calculate Eao when using daily fuel
sampling or Method 6B of appendix A of this part.
(e) If coal, oil, or coal and oil are combusted with other fuels:
(1) An adjusted Eho (Ehoo) is used in
Equation 19-19 of Method 19 of appendix A of this part to compute the
adjusted Eao (Eaoo). The Ehoo is
computed using the following formula:
[GRAPHIC] [TIFF OMITTED] TR13JN07.033
Where:
Ehoo = Adjusted Eho, ng/J (lb/MMBtu);
Eho = Hourly SO2 emission rate, ng/J (lb/
MMBtu);
Ew = SO2 concentration in fuels other than
coal and oil combusted in the affected facility, as determined by
fuel sampling and analysis procedures in Method 9 of appendix A of
this part, ng/J (lb/MMBtu). The value Ew for each fuel
lot is used for each hourly average during the time that the lot is
being combusted. The owner or operator does not have to measure
Ew if the owner or operator elects to assume
Ew = 0.
Xk = Fraction of the total heat input from fuel
combustion derived from coal and oil, as determined by applicable
procedures in Method 19 of appendix A of this part.
(2) The owner or operator of an affected facility that qualifies
under the provisions of Sec. 60.42c(c) or (d) (where percent reduction
is not required) does not have to measure the parameters Ew
or Xk if the owner or operator of the affected facility
elects to measure emission rates of the coal or oil using the fuel
sampling and analysis procedures under Method 19 of appendix A of this
part.
(f) Affected facilities subject to the percent reduction
requirements under Sec. 60.42c(a) or (b) shall determine compliance
with the SO2 emission limits under Sec. 60.42c pursuant to
paragraphs (d) or (e) of this section, and shall determine compliance
with the percent reduction requirements using the following procedures:
(1) If only coal is combusted, the percent of potential
SO2 emission rate is computed using the following formula:
[GRAPHIC] [TIFF OMITTED] TR13JN07.034
Where:
%Ps = Potential SO2 emission rate, in percent;
%Rg = SO2 removal efficiency of the control
device as determined by Method 19 of appendix A of this part, in
percent; and
%Rf = SO2 removal efficiency of fuel
pretreatment as determined by Method 19 of appendix A of this part,
in percent.
(2) If coal, oil, or coal and oil are combusted with other fuels,
the same procedures required in paragraph (f)(1) of this section are
used, except as provided for in the following:
(i) To compute the %Ps, an adjusted %Rg
(%Rgo) is computed from Eaoo from paragraph
(e)(1) of this section and an adjusted average SO2 inlet
rate (Eaio) using the following formula:
[GRAPHIC] [TIFF OMITTED] TR13JN07.035
Where:
%Rgo = Adjusted %Rg, in percent;
Eaoo = Adjusted Eao, ng/J (lb/MMBtu); and
Eaio = Adjusted average SO2 inlet rate, ng/J
(lb/MMBtu).
(ii) To compute Eaio, an adjusted hourly SO2
inlet rate (Ehio) is used. The Ehio is computed
using the following formula:
[GRAPHIC] [TIFF OMITTED] TR13JN07.036
Where:
Ehio = Adjusted Ehi, ng/J (lb/MMBtu);
Ehi = Hourly SO2 inlet rate, ng/J (lb/MMBtu);
Ew = SO2 concentration in fuels other than
coal and oil combusted in the affected facility, as determined by
fuel sampling and analysis procedures in Method 19 of appendix A of
this part, ng/J (lb/MMBtu). The value Ew for each fuel
lot is used for each hourly average during the time that the lot is
being combusted. The owner or operator does not have to measure
Ew if the owner or operator elects to assume
Ew = 0; and
Xk = Fraction of the total heat input from fuel
combustion derived from coal and oil, as determined by applicable
procedures in Method 19 of appendix A of this part.
(g) For oil-fired affected facilities where the owner or operator
seeks to demonstrate compliance with the fuel oil sulfur limits under
Sec. 60.42c based on shipment fuel sampling, the initial performance
test shall consist of sampling and analyzing the oil in the initial
tank of oil to be fired in the steam generating unit to demonstrate
that the oil contains 0.5 weight percent sulfur or less. Thereafter,
the owner or operator of the affected facility shall sample the oil in
the fuel tank after each new shipment of oil is received, as described
under Sec. 60.46c(d)(2).
(h) For affected facilities subject to Sec. 60.42c(h)(1), (2), or
(3) where the owner or operator seeks to demonstrate compliance with
the SO2 standards based on fuel supplier certification, the
performance test shall consist of the certification, the certification
from the fuel supplier, as described under Sec. 60.48c(f), as
applicable.
(i) The owner or operator of an affected facility seeking to
demonstrate compliance with the SO2 standards under Sec.
60.42c(c)(2) shall demonstrate the maximum design heat input capacity
of the steam generating unit by operating the steam generating unit at
this capacity for 24 hours. This demonstration shall be made during the
initial performance test, and a subsequent demonstration may be
requested at any other time. If the demonstrated 24-hour average firing
rate for the affected facility is less than the maximum design heat
input capacity stated by the manufacturer of the affected facility, the
demonstrated 24-hour average firing rate shall be used to determine the
annual capacity factor for the affected facility; otherwise, the
maximum design heat input capacity provided by the manufacturer shall
be used.
(j) The owner or operator of an affected facility shall use all
valid SO2 emissions data in calculating %Ps and
Eho under paragraphs (d), (e), or (f) of this section, as
applicable, whether or not the minimum emissions data requirements
under Sec. 60.46c(f) are achieved. All valid emissions data, including
valid data collected during periods of startup, shutdown, and
malfunction, shall be used in calculating %Ps or
Eho pursuant to paragraphs (d), (e), or (f) of this section,
as applicable.
Sec. 60.45c Compliance and performance test methods and procedures
for particulate matter.
(a) The owner or operator of an affected facility subject to the PM
and/or opacity standards under Sec. 60.43c shall conduct an initial
performance test as required under Sec. 60.8, and shall conduct
subsequent performance tests as requested by the Administrator, to
determine compliance with the standards using the following procedures
and reference methods, except as specified in paragraph (c) of this
section.
(1) Method 1 of appendix A of this part shall be used to select the
sampling site and the number of traverse sampling points.
(2) Method 3 of appendix A of this part shall be used for gas
analysis when applying Method 5, 5B, or 17 of appendix A of this part.
[[Page 32764]]
(3) Method 5, 5B, or 17 of appendix A of this part shall be used to
measure the concentration of PM as follows:
(i) Method 5 of appendix A of this part may be used only at
affected facilities without wet scrubber systems.
(ii) Method 17 of appendix A of this part may be used at affected
facilities with or without wet scrubber systems provided the stack gas
temperature does not exceed a temperature of 160 [deg]C (320 [deg]F).
The procedures of Sections 8.1 and 11.1 of Method 5B of appendix A of
this part may be used in Method 17 of appendix A of this part only if
Method 17 of appendix A of this part is used in conjunction with a wet
scrubber system. Method 17 of appendix A of this part shall not be used
in conjunction with a wet scrubber system if the effluent is saturated
or laden with water droplets.
(iii) Method 5B of appendix A of this part may be used in
conjunction with a wet scrubber system.
(4) The sampling time for each run shall be at least 120 minutes
and the minimum sampling volume shall be 1.7 dry standard cubic meters
(dscm) [60 dry standard cubic feet (dscf)] except that smaller sampling
times or volumes may be approved by the Administrator when necessitated
by process variables or other factors.
(5) For Method 5 or 5B of appendix A of this part, the temperature
of the sample gas in the probe and filter holder shall be monitored and
maintained at 160 14 [deg]C (32025 [deg]F).
(6) For determination of PM emissions, an oxygen (O2) or
carbon dioxide (CO2) measurement shall be obtained
simultaneously with each run of Method 5, 5B, or 17 of appendix A of
this part by traversing the duct at the same sampling location.
(7) For each run using Method 5, 5B, or 17 of appendix A of this
part, the emission rates expressed in ng/J (lb/MMBtu) heat input shall
be determined using:
(i) The O2 or CO2 measurements and PM
measurements obtained under this section, (ii) The dry basis F factor,
and
(iii) The dry basis emission rate calculation procedure contained
in Method 19 of appendix A of this part.
(8) Method 9 of appendix A of this part (6-minute average of 24
observations) shall be used for determining the opacity of stack
emissions.
(b) The owner or operator of an affected facility seeking to
demonstrate compliance with the PM standards under Sec. 60.43c(b)(2)
shall demonstrate the maximum design heat input capacity of the steam
generating unit by operating the steam generating unit at this capacity
for 24 hours. This demonstration shall be made during the initial
performance test, and a subsequent demonstration may be requested at
any other time. If the demonstrated 24-hour average firing rate for the
affected facility is less than the maximum design heat input capacity
stated by the manufacturer of the affected facility, the demonstrated
24-hour average firing rate shall be used to determine the annual
capacity factor for the affected facility; otherwise, the maximum
design heat input capacity provided by the manufacturer shall be used.
(c) In place of PM testing with EPA Reference Method 5, 5B, or 17
of appendix A of this part, an owner or operator may elect to install,
calibrate, maintain, and operate a CEMS for monitoring PM emissions
discharged to the atmosphere and record the output of the system. The
owner or operator of an affected facility who elects to continuously
monitor PM emissions instead of conducting performance testing using
EPA Method 5, 5B, or 17 of appendix A of this part shall install,
calibrate, maintain, and operate a CEMS and shall comply with the
requirements specified in paragraphs (c)(1) through (c)(13) of this
section.
(1) Notify the Administrator 1 month before starting use of the
system.
(2) Notify the Administrator 1 month before stopping use of the
system.
(3) The monitor shall be installed, evaluated, and operated in
accordance with Sec. 60.13 of subpart A of this part.
(4) The initial performance evaluation shall be completed no later
than 180 days after the date of initial startup of the affected
facility, as specified under Sec. 60.8 of subpart A of this part or
within 180 days of notification to the Administrator of use of CEMS if
the owner or operator was previously determining compliance by Method
5, 5B, or 17 of appendix A of this part performance tests, whichever is
later.
(5) The owner or operator of an affected facility shall conduct an
initial performance test for PM emissions as required under Sec. 60.8
of subpart A of this part. Compliance with the PM emission limit shall
be determined by using the CEMS specified in paragraph (d) of this
section to measure PM and calculating a 24-hour block arithmetic
average emission concentration using EPA Reference Method 19 of
appendix A of this part, section 4.1.
(6) Compliance with the PM emission limit shall be determined based
on the 24-hour daily (block) average of the hourly arithmetic average
emission concentrations using CEMS outlet data.
(7) At a minimum, valid CEMS hourly averages shall be obtained as
specified in paragraph (d)(7)(i) of this section for 75 percent of the
total operating hours per 30-day rolling average.
(i) At least two data points per hour shall be used to calculate
each 1-hour arithmetic average.
(ii) [Reserved]
(8) The 1-hour arithmetic averages required under paragraph (d)(7)
of this section shall be expressed in ng/J or lb/MMBtu heat input and
shall be used to calculate the boiler operating day daily arithmetic
average emission concentrations. The 1-hour arithmetic averages shall
be calculated using the data points required under Sec. 60.13(e)(2) of
subpart A of this part.
(9) All valid CEMS data shall be used in calculating average
emission concentrations even if the minimum CEMS data requirements of
paragraph (d)(7) of this section are not met.
(10) The CEMS shall be operated according to Performance
Specification 11 in appendix B of this part.
(11) During the correlation testing runs of the CEMS required by
Performance Specification 11 in appendix B of this part, PM and
O2 (or CO2) data shall be collected concurrently
(or within a 30- to 60-minute period) by both the continuous emission
monitors and the test methods specified in paragraph (d)(7)(i) of this
section.
(i) For PM, EPA Reference Method 5, 5B, or 17 of appendix A of this
part shall be used.
(ii) For O2 (or CO2), EPA reference Method 3,
3A, or 3B of appendix A of this part, as applicable shall be used.
(12) Quarterly accuracy determinations and daily calibration drift
tests shall be performed in accordance with procedure 2 in appendix F
of this part. Relative Response Audit's must be performed annually and
Response Correlation Audits must be performed every 3 years.
(13) When PM emissions data are not obtained because of CEMS
breakdowns, repairs, calibration checks, and zero and span adjustments,
emissions data shall be obtained by using other monitoring systems as
approved by the Administrator or EPA Reference Method 19 of appendix A
of this part to provide, as necessary, valid emissions data for a
minimum of 75 percent of total operating hours on a 30-day rolling
average.
(d) The owner or operator of an affected facility seeking to
demonstrate compliance under Sec. 60.43c(e)(4) shall follow the
applicable procedures under Sec. 60.48c(f). For residual oil-fired
affected facilities, fuel supplier certifications are only allowed for
facilities with heat input capacities
[[Page 32765]]
between 2.9 and 8.7 MW (10 to 30 MMBtu/hr).
Sec. 60.46c Emission monitoring for sulfur dioxide.
(a) Except as provided in paragraphs (d) and (e) of this section,
the owner or operator of an affected facility subject to the
SO2 emission limits under Sec. 60.42c shall install,
calibrate, maintain, and operate a CEMS for measuring SO2
concentrations and either O2 or CO2
concentrations at the outlet of the SO2 control device (or
the outlet of the steam generating unit if no SO2 control
device is used), and shall record the output of the system. The owner
or operator of an affected facility subject to the percent reduction
requirements under Sec. 60.42c shall measure SO2
concentrations and either O2 or CO2
concentrations at both the inlet and outlet of the SO2
control device.
(b) The 1-hour average SO2 emission rates measured by a
CEMS shall be expressed in ng/J or lb/MMBtu heat input and shall be
used to calculate the average emission rates under Sec. 60.42c. Each
1-hour average SO2 emission rate must be based on at least
30 minutes of operation, and shall be calculated using the data points
required under Sec. 60.13(h)(2). Hourly SO2 emission rates
are not calculated if the affected facility is operated less than 30
minutes in a 1-hour period and are not counted toward determination of
a steam generating unit operating day.
(c) The procedures under Sec. 60.13 shall be followed for
installation, evaluation, and operation of the CEMS.
(1) All CEMS shall be operated in accordance with the applicable
procedures under Performance Specifications 1, 2, and 3 of appendix B
of this part.
(2) Quarterly accuracy determinations and daily calibration drift
tests shall be performed in accordance with Procedure 1 of appendix F
of this part.
(3) For affected facilities subject to the percent reduction
requirements under Sec. 60.42c, the span value of the SO2
CEMS at the inlet to the SO2 control device shall be 125
percent of the maximum estimated hourly potential SO2
emission rate of the fuel combusted, and the span value of the
SO2 CEMS at the outlet from the SO2 control
device shall be 50 percent of the maximum estimated hourly potential
SO2 emission rate of the fuel combusted.
(4) For affected facilities that are not subject to the percent
reduction requirements of Sec. 60.42c, the span value of the
SO2 CEMS at the outlet from the SO2 control
device (or outlet of the steam generating unit if no SO2
control device is used) shall be 125 percent of the maximum estimated
hourly potential SO2 emission rate of the fuel combusted.
(d) As an alternative to operating a CEMS at the inlet to the
SO2 control device (or outlet of the steam generating unit
if no SO2 control device is used) as required under
paragraph (a) of this section, an owner or operator may elect to
determine the average SO2 emission rate by sampling the fuel
prior to combustion. As an alternative to operating a CEMS at the
outlet from the SO2 control device (or outlet of the steam
generating unit if no SO2 control device is used) as
required under paragraph (a) of this section, an owner or operator may
elect to determine the average SO2 emission rate by using
Method 6B of appendix A of this part. Fuel sampling shall be conducted
pursuant to either paragraph (d)(1) or (d)(2) of this section. Method
6B of appendix A of this part shall be conducted pursuant to paragraph
(d)(3) of this section.
(1) For affected facilities combusting coal or oil, coal or oil
samples shall be collected daily in an as-fired condition at the inlet
to the steam generating unit and analyzed for sulfur content and heat
content according the Method 19 of appendix A of this part. Method 19
of appendix A of this part provides procedures for converting these
measurements into the format to be used in calculating the average
SO2 input rate.
(2) As an alternative fuel sampling procedure for affected
facilities combusting oil, oil samples may be collected from the fuel
tank for each steam generating unit immediately after the fuel tank is
filled and before any oil is combusted. The owner or operator of the
affected facility shall analyze the oil sample to determine the sulfur
content of the oil. If a partially empty fuel tank is refilled, a new
sample and analysis of the fuel in the tank would be required upon
filling. Results of the fuel analysis taken after each new shipment of
oil is received shall be used as the daily value when calculating the
30-day rolling average until the next shipment is received. If the fuel
analysis shows that the sulfur content in the fuel tank is greater than
0.5 weight percent sulfur, the owner or operator shall ensure that the
sulfur content of subsequent oil shipments is low enough to cause the
30-day rolling average sulfur content to be 0.5 weight percent sulfur
or less.
(3) Method 6B of appendix A of this part may be used in lieu of
CEMS to measure SO2 at the inlet or outlet of the
SO2 control system. An initial stratification test is
required to verify the adequacy of the Method 6B of appendix A of this
part sampling location. The stratification test shall consist of three
paired runs of a suitable SO2 and CO2 measurement
train operated at the candidate location and a second similar train
operated according to the procedures in Sec. 3.2 and the applicable
procedures in section 7 of Performance Specification 2 of appendix B of
this part. Method 6B of appendix A of this part, Method 6A of appendix
A of this part, or a combination of Methods 6 and 3 of appendix A of
this part or Methods 6C and 3A of appendix A of this part are suitable
measurement techniques. If Method 6B of appendix A of this part is used
for the second train, sampling time and timer operation may be adjusted
for the stratification test as long as an adequate sample volume is
collected; however, both sampling trains are to be operated similarly.
For the location to be adequate for Method 6B of appendix A of this
part 24-hour tests, the mean of the absolute difference between the
three paired runs must be less than 10 percent (0.10).
(e) The monitoring requirements of paragraphs (a) and (d) of this
section shall not apply to affected facilities subject to Sec.
60.42c(h) (1), (2), or (3) where the owner or operator of the affected
facility seeks to demonstrate compliance with the SO2
standards based on fuel supplier certification, as described under
Sec. 60.48c(f), as applicable.
(f) The owner or operator of an affected facility operating a CEMS
pursuant to paragraph (a) of this section, or conducting as-fired fuel
sampling pursuant to paragraph (d)(1) of this section, shall obtain
emission data for at least 75 percent of the operating hours in at
least 22 out of 30 successive steam generating unit operating days. If
this minimum data requirement is not met with a single monitoring
system, the owner or operator of the affected facility shall supplement
the emission data with data collected with other monitoring systems as
approved by the Administrator.
Sec. 60.47c Emission monitoring for particulate matter.
(a) Except as provided in paragraphs (c), (d), (e), and (f) of this
section, the owner or operator of an affected facility combusting coal,
oil, or wood that is subject to the opacity standards under Sec.
60.43c shall install, calibrate, maintain, and operate a COMS for
measuring the opacity of the emissions discharged to the atmosphere and
record the output of the system.
(b) All COMS for measuring opacity shall be operated in accordance
with the
[[Page 32766]]
applicable procedures under Performance Specification 1 of appendix B
of this part. The span value of the opacity COMS shall be between 60
and 80 percent.
(c) Affected facilities that burn only distillate oil that contains
no more than 0.5 weight percent sulfur and/or liquid or gaseous fuels
with potential sulfur dioxide emission rates of 26 ng/J (0.06 lb/MMBtu)
heat input or less and that do not use a post-combustion technology to
reduce SO2 or PM emissions are not required to operate a
CEMS for measuring opacity if they follow the applicable procedures
under Sec. 60.48c(f).
(d) Owners or operators complying with the PM emission limit by
using a PM CEMS monitor instead of monitoring opacity must calibrate,
maintain, and operate a CEMS, and record the output of the system, for
PM emissions discharged to the atmosphere as specified in Sec.
60.45c(d). The CEMS specified in paragraph Sec. 60.45c(d) shall be
operated and data recorded during all periods of operation of the
affected facility except for CEMS breakdowns and repairs. Data is
recorded during calibration checks, and zero and span adjustments.
(e) An affected facility that does not use post-combustion
technology (except a wet scrubber) for reducing PM, SO2, or
carbon monoxide (CO) emissions, burns only gaseous fuels or fuel oils
that contain less than or equal to 0.5 weight percent sulfur, and is
operated such that emissions of CO to the atmosphere from the affected
facility are maintained at levels less than or equal to 0.15 lb/MMBtu
on a boiler operating day average basis is not required to operate a
COMS for measuring opacity. Owners and operators of affected facilities
electing to comply with this paragraph must demonstrate compliance
according to the procedures specified in paragraphs (e)(1) through (4)
of this section.
(1) You must monitor CO emissions using a CEMS according to the
procedures specified in paragraphs (e)(1)(i) through (iv) of this
section.
(i) The CO CEMS must be installed, certified, maintained, and
operated according to the provisions in Sec. 60.58b(i)(3) of subpart
Eb of this part.
(ii) Each 1-hour CO emissions average is calculated using the data
points generated by the CO CEMS expressed in parts per million by
volume corrected to 3 percent oxygen (dry basis).
(iii) At a minimum, valid 1-hour CO emissions averages must be
obtained for at least 90 percent of the operating hours on a 30-day
rolling average basis. At least two data points per hour must be used
to calculate each 1-hour average.
(iv) Quarterly accuracy determinations and daily calibration drift
tests for the CO CEMS must be performed in accordance with procedure 1
in appendix F of this part.
(2) You must calculate the 1-hour average CO emissions levels for
each steam generating unit operating day by multiplying the average
hourly CO output concentration measured by the CO CEMS times the
corresponding average hourly flue gas flow rate and divided by the
corresponding average hourly heat input to the affected source. The 24-
hour average CO emission level is determined by calculating the
arithmetic average of the hourly CO emission levels computed for each
steam generating unit operating day.
(3) You must evaluate the preceding 24-hour average CO emission
level each steam generating unit operating day excluding periods of
affected source startup, shutdown, or malfunction. If the 24-hour
average CO emission level is greater than 0.15 lb/MMBtu, you must
initiate investigation of the relevant equipment and control systems
within 24 hours of the first discovery of the high emission incident
and, take the appropriate corrective action as soon as practicable to
adjust control settings or repair equipment to reduce the 24-hour
average CO emission level to 0.15 lb/MMBtu or less.
(4) You must record the CO measurements and calculations performed
according to paragraph (e) of this section and any corrective actions
taken. The record of corrective action taken must include the date and
time during which the 24-hour average CO emission level was greater
than 0.15 lb/MMBtu, and the date, time, and description of the
corrective action.
(f) An affected facility that burns only gaseous fuels or fuel oils
that contain less than or equal to 0.5 weight percent sulfur and
operates according to a written site-specific monitoring plan approved
by the appropriate delegated permitting authority is not required to
operate a COMS for measuring opacity. This monitoring plan must include
procedures and criteria for establishing and monitoring specific
parameters for the affected facility indicative of compliance with the
opacity standard.
Sec. 60.48c Reporting and recordkeeping requirements.
(a) The owner or operator of each affected facility shall submit
notification of the date of construction or reconstruction and actual
startup, as provided by Sec. 60.7 of this part. This notification
shall include:
(1) The design heat input capacity of the affected facility and
identification of fuels to be combusted in the affected facility.
(2) If applicable, a copy of any federally enforceable requirement
that limits the annual capacity factor for any fuel or mixture of fuels
under Sec. 60.42c, or Sec. 60.43c.
(3) The annual capacity factor at which the owner or operator
anticipates operating the affected facility based on all fuels fired
and based on each individual fuel fired.
(4) Notification if an emerging technology will be used for
controlling SO2 emissions. The Administrator will examine
the description of the control device and will determine whether the
technology qualifies as an emerging technology. In making this
determination, the Administrator may require the owner or operator of
the affected facility to submit additional information concerning the
control device. The affected facility is subject to the provisions of
Sec. 60.42c(a) or (b)(1), unless and until this determination is made
by the Administrator.
(b) The owner or operator of each affected facility subject to the
SO2 emission limits of Sec. 60.42c, or the PM or opacity
limits of Sec. 60.43c, shall submit to the Administrator the
performance test data from the initial and any subsequent performance
tests and, if applicable, the performance evaluation of the CEMS and/or
COMS using the applicable performance specifications in appendix B of
this part.
(c) The owner or operator of each coal-fired, oil-fired, or wood-
fired affected facility subject to the opacity limits under Sec.
60.43c(c) shall submit excess emission reports for any excess emissions
from the affected facility that occur during the reporting period.
(d) The owner or operator of each affected facility subject to the
SO2 emission limits, fuel oil sulfur limits, or percent
reduction requirements under Sec. 60.42c shall submit reports to the
Administrator.
(e) The owner or operator of each affected facility subject to the
SO2 emission limits, fuel oil sulfur limits, or percent
reduction requirements under Sec. 60.42c shall keep records and submit
reports as required under paragraph (d) of this section, including the
following information, as applicable.
(1) Calendar dates covered in the reporting period.
(2) Each 30-day average SO2 emission rate (ng/J or lb/
MMBtu), or 30-day average sulfur content (weight percent), calculated
during the reporting period, ending with the last 30-day period;
reasons for any noncompliance with the
[[Page 32767]]
emission standards; and a description of corrective actions taken.
(3) Each 30-day average percent of potential SO2
emission rate calculated during the reporting period, ending with the
last 30-day period; reasons for any noncompliance with the emission
standards; and a description of the corrective actions taken.
(4) Identification of any steam generating unit operating days for
which SO2 or diluent (O2 or CO2) data
have not been obtained by an approved method for at least 75 percent of
the operating hours; justification for not obtaining sufficient data;
and a description of corrective actions taken.
(5) Identification of any times when emissions data have been
excluded from the calculation of average emission rates; justification
for excluding data; and a description of corrective actions taken if
data have been excluded for periods other than those during which coal
or oil were not combusted in the steam generating unit.
(6) Identification of the F factor used in calculations, method of
determination, and type of fuel combusted.
(7) Identification of whether averages have been obtained based on
CEMS rather than manual sampling methods.
(8) If a CEMS is used, identification of any times when the
pollutant concentration exceeded the full span of the CEMS.
(9) If a CEMS is used, description of any modifications to the CEMS
that could affect the ability of the CEMS to comply with Performance
Specifications 2 or 3 of appendix B of this part.
(10) If a CEMS is used, results of daily CEMS drift tests and
quarterly accuracy assessments as required under appendix F, Procedure
1 of this part.
(11) If fuel supplier certification is used to demonstrate
compliance, records of fuel supplier certification is used to
demonstrate compliance, records of fuel supplier certification as
described under paragraph (f)(1), (2), (3), or (4) of this section, as
applicable. In addition to records of fuel supplier certifications, the
report shall include a certified statement signed by the owner or
operator of the affected facility that the records of fuel supplier
certifications submitted represent all of the fuel combusted during the
reporting period.
(f) Fuel supplier certification shall include the following
information:
(1) For distillate oil:
(i) The name of the oil supplier;
(ii) A statement from the oil supplier that the oil complies with
the specifications under the definition of distillate oil in Sec.
60.41c; and
(iii) The sulfur content of the oil.
(2) For residual oil:
(i) The name of the oil supplier;
(ii) The location of the oil when the sample was drawn for analysis
to determine the sulfur content of the oil, specifically including
whether the oil was sampled as delivered to the affected facility, or
whether the sample was drawn from oil in storage at the oil supplier's
or oil refiner's facility, or other location;
(iii) The sulfur content of the oil from which the shipment came
(or of the shipment itself); and
(iv) The method used to determine the sulfur content of the oil.
(3) For coal:
(i) The name of the coal supplier;
(ii) The location of the coal when the sample was collected for
analysis to determine the properties of the coal, specifically
including whether the coal was sampled as delivered to the affected
facility or whether the sample was collected from coal in storage at
the mine, at a coal preparation plant, at a coal supplier's facility,
or at another location. The certification shall include the name of the
coal mine (and coal seam), coal storage facility, or coal preparation
plant (where the sample was collected);
(iii) The results of the analysis of the coal from which the
shipment came (or of the shipment itself) including the sulfur content,
moisture content, ash content, and heat content; and
(iv) The methods used to determine the properties of the coal.
(4) For other fuels:
(i) The name of the supplier of the fuel;
(ii) The potential sulfur emissions rate of the fuel in ng/J heat
input; and
(iii) The method used to determine the potential sulfur emissions
rate of the fuel.
(g)(1) Except as provided under paragraphs (g)(2) and (g)(3) of
this section, the owner or operator of each affected facility shall
record and maintain records of the amount of each fuel combusted during
each operating day.
(2) As an alternative to meeting the requirements of paragraph
(g)(1) of this section, the owner or operator of an affected facility
that combusts only natural gas, wood, fuels using fuel certification in
Sec. 60.48c(f) to demonstrate compliance with the SO2
standard, fuels not subject to an emissions standard (excluding
opacity), or a mixture of these fuels may elect to record and maintain
records of the amount of each fuel combusted during each calendar
month.
(3) As an alternative to meeting the requirements of paragraph
(g)(1) of this section, the owner or operator of an affected facility
or multiple affected facilities located on a contiguous property unit
where the only fuels combusted in any steam generating unit (including
steam generating units not subject to this subpart) at that property
are natural gas, wood, distillate oil meeting the most current
requirements in Sec. 60.42C to use fuel certification to demonstrate
compliance with the SO2 standard, and/or fuels, excluding
coal and residual oil, not subject to an emissions standard (excluding
opacity) may elect to record and maintain records of the total amount
of each steam generating unit fuel delivered to that property during
each calendar month.
(h) The owner or operator of each affected facility subject to a
federally enforceable requirement limiting the annual capacity factor
for any fuel or mixture of fuels under Sec. 60.42c or Sec. 60.43c
shall calculate the annual capacity factor individually for each fuel
combusted. The annual capacity factor is determined on a 12-month
rolling average basis with a new annual capacity factor calculated at
the end of the calendar month.
(i) All records required under this section shall be maintained by
the owner or operator of the affected facility for a period of two
years following the date of such record.
(j) The reporting period for the reports required under this
subpart is each six-month period. All reports shall be submitted to the
Administrator and shall be postmarked by the 30th day following the end
of the reporting period.
Appendix B--[Amended]
0
7. Appendix B to part 60 is amended by revising section 8.3.1 in
Performance Specification 2, to read as follows:
Appendix B to Part 60--Performance Specifications
* * * * *
Performance Specification 2--Specifications and Test Procedures for
SO2 and NOX Continuous Emission Monitoring
Systems in Stationary Sources
* * * * *
8.3.1 CD Test Period. While the affected facility is operating,
determine the magnitude of the CD once each day (at 24-hour
intervals) for 7 consecutive calendar days according to the
procedure given in Sections 8.3.2 through 8.3.4. Alternatively, the
CD test may be conducted over 7 consecutive unit operating days.
* * * * *
[[Page 32768]]
Appendix F--[Amended]
0
8. Procedure 1 in Appendix F to part 60 is amended by:
0
a. Revising the first sentence of section 5.1.1; and
0
b. Revising section 5.1.4.
The revisions read as follows:
Appendix F to Part 60--Quality Assurance Procedures
* * * * *
5.1.1 Relative Accuracy Test Audit (RATA). The RATA must be
conducted at least once every four calendar quarters, except as
otherwise noted in section 5.1.4 of this appendix.
* * * * *
5.1.4 Other Alternative Audits. Other alternative audit
procedures may be used as approved by the Administrator for three of
four calendar quarters. One RATA is required at least every four
calendar quarters, except in the case where the affected facility is
off-line (does not operate) in the fourth calendar quarter since the
quarter of the previous RATA. In that case, the RATA shall be
performed in the quarter in which the unit recommences operation.
Also, cylinder gas audits are not be required for calendar quarters
in which the affected facility does not operate.
* * * * *
[FR Doc. E7-7673 Filed 6-12-07; 8:45 am]
BILLING CODE 6560-50-P