[Federal Register Volume 74, Number 17 (Wednesday, January 28, 2009)]
[Rules and Regulations]
[Pages 5072-5093]
From the Federal Register Online via the Government Publishing Office [www.gpo.gov]
[FR Doc No: E9-523]
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Part III
Environmental Protection Agency
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40 CFR Part 60
Standards of Performance for Fossil-Fuel-Fired Steam Generators;
Standards of Performance for Industrial-Commercial-Institutional Steam
Generating Units; Final Rule
Federal Register / Vol. 74, No. 17 / Wednesday, January 28, 2009 /
Rules and Regulations
[[Page 5072]]
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ENVIRONMENTAL PROTECTION AGENCY
40 CFR Part 60
[EPA-HQ-OAR-2005-0031; FRL-8748-2]
RIN 2060-AO61
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 rule.
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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, eliminate the opacity standard for
facilities with a particulate matter (PM) limit of 0.030 lb/million
British thermal units (MMBtu) or less that choose to voluntarily
install and use PM continuous emission monitors (CEMS) to demonstrate
compliance with that limit, and to correct technical and editorial
errors.
DATES: This final rule is effective on January 28, 2009. The
incorporation by reference of certain publications listed in this final
rule is approved by the Director of the Federal Register as of January
28, 2009.
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
http://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 Response to Public Comments
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. Executive Order 12898: Federal Actions To Address
Environmental Justice in Minority Populations and Low-Income
Populations
K. 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 potentially
Category NAICS Code\1\ regulated entities
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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 a petroleum and natural
steam generating unit as gas.
defined in 60.40b or 60.4c.
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
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applicability criteria in Sec. 60.40, Sec. 60.40a, Sec. 60.40b, or
Sec. 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 EPA regional representative
as listed in Sec. 63.13 of subpart A (General Provisions) of title 40
of the Code of Federal Regulations.
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
March 30, 2009. 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 of the amendments to
the new source performance standards for steam generating units that
EPA promulgated on June 13, 2007 (72 FR 32710) filed by the Coke Oven
Environmental Task Force, EPA proposed revised amendments to address
issues for which the petitioners requested reconsideration (see docket
entry EPA-HQ-OAR-2005-0031-0276). EPA also proposed certain other
unrelated amendments it felt were appropriate. In sum, EPA proposed on
June 12, 2008 (73 FR 33642) to amend subparts D, Da, Db, and Dc of 40
CFR part 60 to clarify the intent for applying and implementing
specific rule requirements, provide additional compliance alternatives,
and to correct unintentional technical omissions and editorial errors.
A 45-day comment period (June 12, 2008 to July 28, 2008) 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.
We received comments on the proposed amendments from 11 commenters
during the comment period.
III. Final Amendments and Response to Public Comments
We are amending subparts D, Da, Db, and Dc of 40 CFR part 60 to add
compliance alternatives for owners/operators of certain affected
sources, to eliminate the opacity standard for certain facilities
voluntarily using PM CEMS, and to correct technical and editorial
errors. These amendments address issues raised by the Coke Oven
Environmental Task Force, including an alternate sulfur dioxide
(SO2) limit during SO2 control system maintenance
and allowing the use of parametric monitoring of nitrogen oxide
(NOX) emissions for owners and operators of coke oven gas-
fired (COG) steam generating units. In addition, we are specifying the
opacity monitoring requirements for owners and operators of all
affected facilities that are subject to an opacity limit, including
owner and operators of COG-fired steam generating units, but exempt
from the continuous opacity monitoring system (COMS) requirement. This
action promulgates the amended regulatory language as proposed, except
for those significant provisions identified below.
We are also finalizing several clarifications to correct technical
and editorial errors and to amend the monitoring requirements for
owners and operators of affected facilities that elect to install
particulate matter continuous emission monitoring systems (PM CEMS).
Owners and operators of affected facilities that install a PM CEMS will
be exempt from the opacity standard as long as they are complying with
a federally enforceable permit limiting PM emissions to 0.030 pounds
per million British thermal units or less. In addition, owner and
operators of affected facilities that elect to install PM CEMS will be
required to measure and report emissions of condensable PM.
Minor revisions to the proposed regulatory language were also 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 either as a result of
comments we received or based on our own subsequent review of the text.
One change revises 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. Another change clarifies the fact that not all
combined cycle facilities that burn solid derived fuels are subject to
the subpart.
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. A summary of selected public comments and our
responses is as follows.
Comment: Several commenters generally support the exemption of
affected facilities using PM CEMS from the opacity standard. However,
the commenters requested that EPA exempt those affected facilities
opting to use PM CEMS from the opacity standard without imposing
conditions for additional condensable PM or opacity tests. The
commenters stated the EPA's proposed method for measuring condensable
PM (Method 202) is flawed and significantly overstates the amount of
condensable PM, and noted that Method 202 itself condenses gaseous
emissions that would not be condensing in the flue gas. They also noted
that further improvements of Method 202 must be made before it is
required as the method to measure condensable PM.
Response: The opacity standard and all opacity monitoring
requirements have been eliminated for owner/operators of affected
facilities complying with a federally enforceable PM limit of 0.030 lb/
MMBtu or less who voluntarily elect to use a PM CEMS to demonstrate
continuous compliance with the PM limit. The contribution of filterable
PM to opacity at these emission levels is generally negligible, and
sources with mass limits at this level or less will operate with little
or no visible emissions (i.e. less than 5 percent opacity). As a
result, EPA believes that an opacity standard is no longer necessary
for these sources since the PM mass emission rate standard is
substantially tighter than the opacity standard and the mass of PM
emissions will be continually monitored.
We concluded, however, that it is only appropriate to eliminate the
opacity standard and associated opacity monitoring for owners/operators
of facilities complying with a PM limit of
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0.030 lb/MMBtu or less. At this emission rate, the presence of visible
emissions may indicate that the PM control device is not operating
properly. This amended NSPS does not require any corrective action in
such a case as long as the PM CEMS is complying with all applicable
federal requirements. However, PM CEMS readings cannot be verified as
readily as other CEMS, and since recalibration requires PM performance
tests, baseline opacity readings can be a valuable secondary check on
control device performance and PM emissions. The local permitting
authority does have the discretion to require an investigation to
determine the cause of the visible emissions. The presence of such
emissions is not, however, necessarily evidence of a violation of the
PM standard. In situations where the owner/operator of a facility has
documented visible emissions during the initial or subsequent PM CEMS
calibration testing or documented trends in PM CEMS readings that
correlate to the visible emissions, the relative amount of visible
emissions can still be used by the local permitting authority as a
secondary check that both the PM control device and PM CEMS are
operating properly. While these facilities will not be required to
install continuous opacity monitoring systems (COMS), if a facility
decided to or is required by the permitting authority to install a
COMS, the data would be useful as a secondary check on PM emissions and
proper operation of the PM control device and to verify that the PM
CEMS is operating properly. Owners/operators of affected facilities
with a PM limit greater than 0.030 lb/MMBtu that elect to install PM
CEMS may have some visible emissions, will still be subject to an
opacity limit, and will be required to either use a COMS or perform
periodic visual inspections to comply with the opacity standard.
In addition, we have concluded it is appropriate to require
condensable PM testing for owners/operators of affected facilities that
elect to use PM CEMS to determine the contribution of condensable PM to
total PM emissions. We will use this data to determine if the
condensable PM emissions from steam generating units have a significant
health and/or environmental impact and whether condensable PM should be
included in future amendments to the PM standard. By early 2009, we
intend to propose amendments to Method 202 that will address the
concerns about artifact measurement. Since the rule will not be
finalized until early in 2010, we are delaying the requirement to
perform condensable PM testing until July 1, 2010 or until Method 202
is revised to minimize artifact measurement, whichever is later.
Comment: Several commenters oppose increasing the Method 9
monitoring frequency. The commenters stated that increasing the
frequency from annually to a weekly, monthly, or quarterly basis
without identifying any particular issue of concern that might occur on
a weekly, monthly, or quarterly basis is arbitrary, unnecessary, overly
burdensome, and would provide little environmental benefit. In
addition, one commenter supports the use of Method 22 as an alternative
to Method 9 for those sources that are expected to have no significant
visible emissions. However, three 1-hour Method 22 observations would
actually take significantly longer than 3 hours. Under Method 22,
observers are instructed not to continuously view emissions for more
than 15-20 minutes at a time, and that breaks of 5-10 minutes should be
taken between each observation. Following these criteria, each 1-hour
observation would take at least one and a half hours. Finally, one
commenter requested that EPA allow for owners/operators of affected
facilities that comply with subpart D, Da, Db, or Dc, by the use of a
fabric filter, the alternative of installing and operating
triboelectric bag leak detectors as an alternative to using a COMS.
Response: We have concluded that the appropriate approach is to
base the frequency of visible emissions monitoring on the level of
visible emissions detected during the most recent observation. Owners/
operators of facilities that elect to not use a COMS to demonstrate
compliance with the opacity limit will conduct at least an initial
Method 9 performance test. The frequency of the required subsequent
Method 9 testing is based on the results of the highest 6-minute
opacity observed during the most recent performance test. Owners/
operators of affected facilities where the maximum 6-minute opacity
reading is greater than 10 percent will be required to conduct monthly
Method 9 performance testing; owners/operators of affected facilities
where the maximum 6-minute opacity reading is between 5 percent and 10
percent will be required to conduct quarterly Method 9 performance
testing; owners/operators of affected facilities with some visible
emissions but where the maximum 6-minute opacity reading is 5 percent
or less will be required to conduct semi-annual Method 9 performance
testing; and owners/operators of affected facilities with no visible
emissions will only be required to conduct an annual Method 9
performance test.
As an alternative, owners/operators of affected facilities where
maximum 6-minute opacity readings from the most recent Method 9
performance test is less than 10 percent may elect to use either Method
22 or the digital opacity monitoring system in lieu of subsequent
Method 9 performance testing. The proposed amendments required a total
of 3 hours of observation annually, but did not specify when or for how
long those observations would be done. We have concluded it is
appropriate to decrease the length of each observation to a minimum of
10 minutes, but to increase the frequency to daily observations. This
approach both minimizes the burden of this option while increasing
protection to the environment, as observations will be performed
throughout the year. If an owner/operator of an affected facility
observes visible emissions in excess of 5 percent during any
observation and is unable to take corrective action, they will be
required to either conduct a Method 9 performance test with the
previously specified frequency or to install a COMS. To maintain
consistency in the operation of the digital opacity monitoring system,
the EPA Administrator will approve opacity monitoring plans for owners/
operators that elect to use the digital opacity monitoring system to
detect the presence of visible emissions.
Finally, we have concluded it is appropriate to allow owners/
operators of affected facilities subject to subparts Da, Db, and Dc,
and who install, maintain, and operate a bag leak detection system, the
option to use periodic visual inspections of plume opacity as an
alternative to monitoring opacity with a COMS. Modern baghouses often
operate with no visible emissions, and a bag leak detection system will
allow owners/operators to identify potential problems with the control
device and repair the problems prior to increases in opacity.
Comment: Several commenters oppose the proposed requirement to
electronically submit performance evaluation test date to EPA's WebFIRE
database. One commenter stated that EPA has not: (1) Provided any
rationale for requiring the data to be reported and entered
electronically; (2) provided any information on the proposed reporting
format or mechanism to allow interested parties to understand what sort
of burden this requirement would impose and whether the requirement is
more or less burdensome than other forms of reporting; or (3) provided
any mechanism for sources to confirm the
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authenticity of data submitted to this Web site for their facility.
Furthermore, before EPA can impose any new reporting requirement, EPA
must comply with the requirements of the Paperwork Reduction Act and
also address whether the submission meets the requirements of the
Cross-Media Electronic Reporting Rule (CROMERR), which is codified at
40 CFR part 3. Another commenter stated that any reporting should not
be required of sources until the WebFIRE is fully operational. A formal
regulation is not the proper venue to ``troubleshoot'' communications
with an external database for the regulated community.
Response: EPA does not expect WebFIRE and the associated Electronic
Reporting Tool (ERT) to be operational until early 2011, and we are
delaying the requirement until July 1, 2011. We do not expect
electronic submittal of performance test information to have any
significant costs or impacts to industry (because we are not requiring
additional testing or software and source testing companies already
compile these data electronically), and since submission of data
directly to EPA is only a requirement for facilities that voluntary
elect to use PM CEMS to demonstrate compliance with the PM limit, the
ICR does not need to be amended. In addition, as an alternate to using
the ERT we are allowing owner/operators to mail the test report
directly to EPA. Finally, we fully expect the ERT to be compliant with
CROMERR before reporting is required in 2011.
Comment: Two commenters requested that EPA reconsider the Agency's
decision to include direct contact water heaters in the definition of
``steam generating unit'' used for determining applicability of the
requirements under subparts Db and Dc because it is contrary to
previous EPA applicability determinations, and it is confusing to
include water heaters in a regulation for steam generating units.
Response: The definition of steam generating unit includes direct
contact water heaters and as such, these units meet the applicability
of subpart Dc. However, we recognize that two source-specific letters
exempt individual direct contact water heaters from the applicability
of subpart Dc of 40 CFR part 60, and owners/operators of the units in
question reasonably relied on these determinations and have not been
complying with subpart Dc to date. We do not intend to reverse these
source specific determinations or to require retroactive reporting for
any owner/operators of similar facilities that relied on these
determinations and have not been maintaining the proper records, but we
are clarifying and confirming that direct contact water heaters have
always been subject to subpart Dc, and records shall be maintained from
June 12, 2008 onward, consistent with the definition of steam
generating unit.
V. Statutory and Executive Order Reviews
A. Executive Order 12866: Regulatory Planning and Review
Under Executive Order 12866 (58 FR 51735, October 4, 1993), this
action is a ``significant regulatory action'' because it may raise
novel legal or policy issues arising out of legal mandates, the
President's priorities, or the principles set forth in the Executive
Order. Accordingly, EPA submitted this action to the Office of
Management and Budget (OMB) for review under Executive Order 12866 and
any changes made in response to OMB recommendations have been
documented in the docket for this action.
B. Paperwork Reduction Act
This action does not impose any new information collection burden.
The final rule results in no changes to the information collection
requirements of the existing standards of performance and will have no
impact on the information collection estimate of projected cost and
hour burden made and approved by the OMB during the development of the
existing standards of performance. Therefore, the information
collection requests have not been amended. However, OMB previously
approved the information collection requirements contained in the
existing regulations (subparts Da, Db, and Dc of 40 CFR part 60) under
the provisions of the Paperwork Reduction Act, 44 U.S.C. 3501 et seq.,
and has assigned OMB control numbers 2060-0023 for subpart Da of 40 CFR
part 60, 2060-0072 for subpart Db of 40 CFR part 60, and 2060-0202 for
subpart Dc of 40 CFR part 60. 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. In
determining whether a rule has a significant economic impact on a
substantial number of small entities, the impact of concern is any
significant adverse economic impact on small entities, since the
primary purpose of the regulatory flexibility analyses is to identify
and address regulatory alternatives ``which minimize any significant
economic impact of the rule on small entities.'' 5 U.S.C. 603 and 604.
Thus, an agency may certify that a rule will not have a significant
economic impact on a substantial number of small entities if the rule
relieves regulatory burden, or otherwise has a positive economic effect
on all of the small entities subject to the rule.
EPA is minimizing the opacity monitoring requirements for owner/
operators of affected facilities subject to an opacity standard but
exempt from the COMS requirement. We have therefore concluded that this
final rule will relieve regulatory burden for all affected small
entities.
D. Unfunded Mandates Reform Act
This rule does not change the overall cost of the rule and
therefore does not contain a Federal mandate that may result in
expenditures of $100 million or more for State, local, and trial
governments, in the aggregate, or the private sector in any 1 year.
Thus, this final rule is not subject to the requirements of sections
202 or 205 of UMRA.
This rule is also not subject to the requirements of section 203 of
UMRA because it contains no regulatory requirements that might
significantly or uniquely affect small governments. This rule modifies
previously established requirements and does not impose any new
obligations or enforceable duties on any small governments.
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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.''
This final rule does not have federalism implications. It 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. This action 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 this rule.
F. Executive Order 13175: Consultation and Coordination With Indian
Tribal Governments
This action does not have tribal implications, as specified in
Executive Order 13175 (65 FR 67249, November 9, 2000). While utility
steam generating units are located on tribal lands, EPA is not aware of
any that are owned by tribal governments. Thus, Executive Order 13175
does not apply to this action.
G. Executive Order 13045: Protection of Children From Environmental
Health and Safety Risks
EPA interprets Executive Order 13045 (62 FR 19885, April 23, 1997)
as applying to those regulatory actions that concern health or safety
risks, such that the analysis required under section 5-501 of the
Executive Order has the potential to influence the regulation. This
action is not subject to Executive Order 13045 because it is based
solely on technology performance.
H. Executive Order 13211: Actions Concerning Regulations That
Significantly Affect Energy Supply, Distribution, or Use
This action is not a ``significant energy action'' as defined in
Executive Order 13211 (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. We have concluded that this final rule
is not likely to have any adverse energy effects because it generally
only clarifies our intent and corrects errors in the existing rule.
I. National Technology Transfer Advancement Act
Section 12(d) of the National Technology Transfer and Advancement
Act of 1995 (``NTTAA''), Public Law 104-113 (15 U.S.C. 272 note)
directs EPA to use voluntary consensus standards (VCS) in its
regulatory activities unless to do so would be inconsistent with
applicable law or otherwise impractical. Voluntary consensus standards
are technical standards (e.g., materials specifications, test methods,
sampling procedures, and business practices) that are developed or
adopted by voluntary consensus standards bodies. NTTAA directs EPA to
provide Congress, through OMB, explanations when the Agency decides not
to use available and applicable voluntary consensus standards.
This final rule involves technical standards. EPA has decided to
use ASTM D975-08a, ``Standard Specification for Diesel Fuel Oils,'' for
defining diesel fuel oil. This standard is available from the American
Society for Testing and Materials (ASTM), 100 Barr Harbor Drive, Post
Office Box C700, West Conshohocken, PA 19428-2959.
EPA has also decided to use EPA Method 202 (40 CFR part 51,
appendix M). The Agency has not found any alternative methods. The
search and review results are in the docket for this regulation.
Under 40 CFR 60.13(i) of the NSPS General Provisions, a source may
apply to EPA for permission to use alternative test methods or
alternative monitoring requirements in place of any required testing
methods, performance specifications, or procedures in the final rule
and amendments.
J. Executive Order 12898: Federal Actions To Address Environmental
Justice in Minority Populations and Low-Income Populations
Executive Order 12898 (59 FR 7629, February 16, 1994) establishes
Federal executive policy on environmental justice. Its main provision
directs Federal agencies, to the greatest extent practical and
permitted by law, to make environmental justice part of their mission
by identifying and addressing, as appropriate, disproportionately high
and adverse human health or environmental effects of their programs,
policies, and activities on minority populations and low-income
populations in the United States.
EPA has determined that this final rule will not have
disproportionately high and adverse human health or environmental
effects on minority or low-income populations because it does not
affect the level of protection provided to human health or the
environment. This action does not change any emission limits and,
therefore, does not affect the level of protection provided to human
health or the environment.
H. 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). This final rule will be effective on January 28, 2009.
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: November 26, 2008.
Stephen L. Johnson,
Administrator.
Editorial Note: This document was received in the Office of the
Federal Register on Thursday, January 8, 2009.
0
For the reasons stated in the preamble, title 40, chapter I, part 60 of
the Code of 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 60.17 is amended by redesignating paragraphs (a)(17) through
(a)(92) as paragraphs (a)(18) through (a)(93) and by adding new
paragraph (a)(17) to read as follows:
[[Page 5077]]
Sec. 60.17 Incorporations by Reference.
* * * * *
(a) * * *
(17) ASTM D975-08a, Standard Specification for Diesel Fuel Oils,
IBR approved for Sec. Sec. 60.41b of subpart Db of this part and
60.41c of subpart Dc of this part.
* * * * *
Subpart D--[Amended]
0
3. Section 60.42 is amended by adding paragraph (c) to read as follows:
Sec. 60.42 Standard for particulate matter (PM).
* * * * *
(c) As an alternate to meeting the requirements of paragraph (a) of
this section, an owner or operator that elects to install, calibrate,
maintain, and operate a continuous emissions monitoring systems (CEMS)
for measuring PM emissions can petition the Administrator (in writing)
to comply with Sec. 60.42Da(a) 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. 60.43Da(a) of subpart Da of this part.
0
4. Section 60.43 is amended by revising paragraph (d) to read as
follows:
* * * * *
Sec. 60.43 Standard for sulfur dioxide (SO2).
(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)(4) 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)(4) of subpart Db of this part, as applicable to the
affected source.
0
5. Section 60.45 is amended to read as follows:
0
a. By revising paragraph (a);
0
b. By revising paragraphs (b)(1) and (b)(6)(i)(C) and adding paragraph
(b)(7);
0
c. By revising paragraphs (g)(2), (g)(3), and (g)(4); and
0
d. By adding paragraph (h).
Sec. 60.45 Emissions and fuel monitoring.
(a) Each owner or operator shall install, calibrate, maintain, and
operate continuous opacity monitoring system (COMS) for measuring
opacity and a CEMS for measuring SO2 emissions, NOX emissions, and
either oxygen (O2) or carbon dioxide (CO2) except as provided in
paragraph (b) of this section.
(b) * * *
(1) For a fossil-fuel-fired steam generator that burns only gaseous
or liquid fossil fuel (excluding residual oil) with potential SO2
emissions rates of 26 ng/J (0.060 lb/MMBtu) or less 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 if the owner or operator monitors SO2 emissions by fuel
sampling and analysis or fuel receipts.
* * * * *
(6) * * *
(i) * * *
(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. The 1-hour averages are calculated using the
data points required in Sec. 60.13(h)(2).
* * * * *
(7) The owner or operator of an affected facility subject to an
opacity standard under Sec. 60.42 and that elects to not install a
COMS because the affected facility burns only fuels as specified under
paragraph (b)(1) of this section, monitors PM emissions as specified
under paragraph (b)(5) of this section, or monitors CO emissions as
specified under paragraph (b)(6) of this section shall conduct a
performance test using Method 9 of appendix A-4 of this part and the
procedures in Sec. 60.11 to demonstrate compliance with the applicable
limit in Sec. 60.42 and shall comply with either paragraphs (b)(7)(i),
(b)(7)(ii), or (b)(7)(iii) of this section. If during the initial 60
minutes of observation all 6-minute averages are less than 10 percent
and all individual 15-second observations are less than or equal to 20
percent, the observation period may be reduced from 3 hours to 60
minutes.
(i) Except as provided in paragraph (b)(7)(ii) or (b)(7)(iii) of
this section, the owner or operator shall conduct subsequent Method 9
of appendix A-4 of this part performance tests using the procedures in
paragraph (b)(7) of this section according to the applicable schedule
in paragraphs (b)(7)(i)(A) through (b)(7)(i)(D) of this section, as
determined by the most recent Method 9 of appendix A-4 of this part
performance test results.
(A) If no visible emissions are observed, a subsequent Method 9 of
appendix A-4 of this part performance test must be completed within 12
calendar months from the date that the most recent performance test was
conducted;
(B) If visible emissions are observed but the maximum 6-minute
average opacity is less than or equal to 5 percent, a subsequent Method
9 of appendix A-4 of this part performance test must be completed
within 6 calendar months from the date that the most recent performance
test was conducted;
(C) If the maximum 6-minute average opacity is greater than 5
percent but less than or equal to 10 percent, a subsequent Method 9 of
appendix A-4 of this part performance test must be completed within 3
calendar months from the date that the most recent performance test was
conducted; or
(D) If the maximum 6-minute average opacity is greater than 10
percent, a subsequent Method 9 of appendix A-4 of this part performance
test must be completed within 30 calendar days from the date that the
most recent performance test was conducted.
(ii) If the maximum 6-minute opacity is less than 10 percent during
the most recent Method 9 of appendix A-4 of this part performance test,
the owner or operator may, as an alternative to performing subsequent
Method 9 of appendix A-4 of this part performance test, elect to
perform subsequent monitoring using Method 22 of appendix A-7 of this
part according to the procedures specified in paragraphs (b)(7)(ii)(A)
and (B) of this section.
(A) The owner or operator shall conduct 10 minute observations
(during normal operation) each operating day the affected facility
fires fuel for which an opacity standard is applicable using Method 22
of appendix A-7 of this part and demonstrate that the sum of the
occurrences of any visible emissions is not in excess of 5 percent of
the observation period (i.e., 30 seconds per 10 minute period). If the
sum of the occurrence of any visible emissions is greater than 30
seconds during the initial 10 minute observation, immediately conduct a
30 minute observation. If the sum of the occurrence of visible
emissions is greater than 5 percent of the observation period (i.e., 90
seconds per 30 minute period) the owner or operator shall either
document and adjust the operation of the facility and demonstrate
within 24 hours that the sum of the occurrence of visible emissions is
equal to or less than 5 percent during a 30 minute observation (i.e.,
90 seconds) or conduct a new Method 9 of appendix A-4 of this part
performance test using the procedures
[[Page 5078]]
in paragraph (b)(7) of this section within 30 calendar days according
to the requirements in Sec. 60.46(b)(3).
(B) If no visible emissions are observed for 30 operating days
during which an opacity standard is applicable, observations can be
reduced to once every 7 operating days during which an opacity standard
is applicable. If any visible emissions are observed, daily
observations shall be resumed.
(iii) If the maximum 6-minute opacity is less than 10 percent
during the most recent Method 9 of appendix A-4 of this part
performance test, the owner or operator may, as an alternative to
performing subsequent Method 9 of appendix A-4 performance tests, elect
to perform subsequent monitoring using a digital opacity compliance
system according to a site-specific monitoring plan approved by the
Administrator. The observations shall be similar, but not necessarily
identical, to the requirements in paragraph (b)(7)(ii) of this section.
For reference purposes in preparing the monitoring plan, see OAQPS
``Determination of Visible Emission Opacity from Stationary Sources
Using Computer-Based Photographic Analysis Systems.'' This document is
available from the U.S. Environmental Protection Agency (U.S. EPA);
Office of Air Quality and Planning 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
Preliminary Methods.
* * * * *
(g) * * *
(2) Sulfur dioxide. Excess emissions for affected facilities are
defined as:
(i) For affected facilities electing not to comply with Sec.
60.43(d), 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 in
Sec. 60.43; or
(ii) For affected facilities electing to comply with Sec.
60.43(d), 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 in 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 or Sec. Sec. 60.45b and
60.47b of subpart Db of this part, as applicable.
(3) Nitrogen oxides. Excess emissions for affected facilities using
a CEMS for measuring NOX are defined as:
(i) For affected facilities electing not to comply with Sec.
60.44(e), any three-hour period during which the average emissions
(arithmetic average of three contiguous one-hour periods) exceed the
applicable standards in Sec. 60.44; or
(ii) For affected facilities electing to comply with Sec.
60.44(e), 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 in Sec. 60.44. 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 in Sec.
60.42. Affected facilities using PM CEMS must follow the most current
applicable compliance and monitoring provisions in Sec. Sec. 60.48Da
and 60.49Da of subpart Da of this part.
(h) The owner or operator of an affected facility subject to the
opacity limits in Sec. 60.42 that elects to monitor emissions
according to the requirements in Sec. 60.45(b)(7) shall maintain
records according to the requirements specified in paragraphs (h)(1)
through (3) of this section, as applicable to the visible emissions
monitoring method used.
(1) For each performance test conducted using Method 9 of appendix
A-4 of this part, the owner or operator shall keep the records
including the information specified in paragraphs (h)(1)(i) through
(iii) of this section.
(i) Dates and time intervals of all opacity observation periods;
(ii) Name, affiliation, and copy of current visible emission
reading certification for each visible emission observer participating
in the performance test; and
(iii) Copies of all visible emission observer opacity field data
sheets;
(2) For each performance test conducted using Method 22 of appendix
A-4 of this part, the owner or operator shall keep the records
including the information specified in paragraphs (h)(2)(i) through
(iv) of this section.
(i) Dates and time intervals of all visible emissions observation
periods;
(ii) Name and affiliation for each visible emission observer
participating in the performance test;
(iii) Copies of all visible emission observer opacity field data
sheets; and
(iv) Documentation of any adjustments made and the time the
adjustments were completed to the affected facility operation by the
owner or operator to demonstrate compliance with the applicable
monitoring requirements.
(3) For each digital opacity compliance system, the owner or
operator shall maintain records and submit reports according to the
requirements specified in the site-specific monitoring plan approved by
the Administrator.
0
6. Section 60.46 is amended by revising paragraph (d)(2) to read as
follows:
Sec. 60.46 Test methods and procedures.
* * * * *
(d) * * *
(2) For Method 5 or 5B of appendix A-3 of this part, Method 17 of
appendix A-6 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 160 [deg]C (320 [deg]F). The
procedures of sections 8.1 and 11.1 of Method 5B of appendix A-3 of
this part may be used with Method 17 of appendix A-6 of this part only
if it is used after wet FGD systems. Method 17 of appendix A-6 of this
part shall not be used after wet FGD systems if the effluent gas is
saturated or laden with water droplets.
* * * * *
Subpart Da--[Amended]
0
7. Section 60.40Da is amended by revising paragraphs (a) and (b), and
adding paragraph (e) to read as follows:
Sec. 60.40Da Applicability and designation of affected facility.
(a) Except as specified in paragraph (e) of this section, 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.
(b) An IGCC electric utility steam generating unit (both the
stationary combustion turbine and any associated duct burners) is
subject to this part and is not subject to subpart GG or KKKK of this
part if both of the conditions specified in paragraphs (b)(1) and (2)
of this section are met.
[[Page 5079]]
(1) The IGCC electric utility steam generating unit 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 IGCC electric utility steam generating unit commenced
construction, modification, or reconstruction after February 28, 2005.
* * * * *
(e) Applicability of the requirement of this subpart to an electric
utility combined cycle gas turbine other than an IGCC electric utility
steam generating unit is as specified in paragraphs (e)(1) and (2) of
this section.
(1) Heat recovery steam generators used with duct burners and
associated with an electric utility combined cycle gas turbine that are
capable of combusting more than 73 MW (250 MMBtu/hr) heat input of
fossil fuel are subject to this subpart except in cases when the heat
recovery steam generator meets the applicability requirements and is
subject to subpart KKKK of this part.
(2) For heat recovery steam generators use with duct burners
subject to this subpart, only emissions resulting from the combustion
of fuels in the steam generating unit (i.e. duct burners) are subject
to the standards under this subpart. (The emissions resulting from the
combustion of fuels in the stationary combustion turbine engine are
subject to subpart GG or KKK, as applicable, of this part).
0
8. Section 60.41Da is amended by revising the definitions of ``Gross
output,'' ``Integrated gasification combined cycle electric utility
steam generating unit or IGCC electric utility steam generating unit,''
``Natural gas,'' and ``Petroleum'' to read as follows:
Sec. 60.41Da Definitions.
* * * * *
Gross output means the gross useful work performed by the steam
generated and, for an IGCC electric utility steam generating unit, the
work performed by the 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 or to enhance the
performance of the unit (i.e., steam delivered to an industrial
process).
* * * * *
Integrated gasification combined cycle electric utility steam
generating unit or IGCC electric utility steam generating unit means an
electric utility combined cycle gas turbine that is designed to burn
fuels containing 50 percent (by heat input) or more solid-derived fuel
not meeting the definition of natural gas. No solid fuel is directly
burned in the unit during operation.
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 dry standard cubic meter (910 and
1,150 Btu per dry standard cubic foot).
* * * * *
Petroleum means crude oil or a fuel derived from crude oil,
including, but not limited to, distillate oil, and residual oil.
* * * * *
0
9. Section 60.42Da is amended by revising paragraph (b) to read as
follows:
Sec. 60.42Da Standard for particulate matter (PM).
* * * * *
(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. Owners and operators of an affected
facility that elect to install, calibrate, maintain, and operate a
continuous emissions monitoring system (CEMS) for measuring PM
emissions according to the requirements of this subpart are exempt from
the opacity standard specified in this paragraph b.
* * * * *
0
10. Section 60.48Da is amended to read as follows:
0
a. By revising paragraph (g)(3);
0
b. By revising the first sentence of paragraph (j)(2);
0
c. By revising paragraph (n);
0
d. By revising paragraph (o) introductory text;
0
e. By revising paragraph (o)(1);
0
f. By revising paragraph (o)(2)(ii);
0
g. By revising the last sentence of paragraph (o)(2)(iii);
0
h. By revising paragraphs (o)(2)(iv) and (o)(2)(vi);
0
i. By revising paragraphs (o)(3)(i) and (o)(3)(ii);
0
j. By revising the first sentence of paragraph (o)(3)(iii);
0
k. By revising the last sentence of paragraph (o)(3)(v);
0
l. By revising paragraph (o)(4)(i)(E);
0
m. By revising the first sentence of paragraph (o)(4)(ii);
0
n. By revising paragraphs (o)(4)(ii)(F), (o)(4)(v) and (o)(4)(5);
0
o. By revising paragraph (p) introductory text and (p)(2); and
0
p. By adding paragraph (q).
Sec. 60.48Da Compliance provisions.
* * * * *
(g) * * *
(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,
all of the valid hourly emission rates of the operating day(s) not
meeting the minimum 18 hours valid data daily average requirement are
averaged with all of the valid hourly emission rates of the next boiler
operating day with 18 hours or more of valid PM CEMS data to determine
compliance.
* * * * *
(j) * * *
(2) The owner or operator of an affected duct burner may elect to
determine compliance by using the CEMS specified under Sec. 60.49Da
for measuring NOX and oxygen (O2) (or carbon
dioxide (CO2)) and meet the requirements of Sec. 60.49Da. *
* *
* * * * *
(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) or Sec.
60.49Da(m)), and divided by the average hourly gross energy output
(measured according to the provisions of Sec. 60.49Da(k)). Compliance
with the
[[Page 5080]]
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.
(1) You must conduct a performance test to demonstrate initial
compliance with the applicable PM emissions limit in Sec.
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 following the date the previous performance test was
required to be conducted. You must conduct each performance test
according to the requirements in Sec. 60.8 using the test methods and
procedures in Sec. 60.50Da. The owner or operator of an affected
facility that has not operated for 60 consecutive calendar days prior
to the date that the subsequent performance test would have been
required had the unit been operating is not required to perform the
subsequent performance test until 30 calendar days after the next
boiler operating day. Requests for additional 30 day extensions shall
be granted by the relevant air division or office director of the
appropriate Regional Office of the U.S. EPA.
(2) * * *
(ii) You must comply with the quality assurance requirements in
paragraphs (o)(2)(ii)(A) through (E) of this section.
* * * * *
(iii) * * * If your opacity baseline level 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 facility 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. In cases when a wet scrubber is used in combination with
another PM control device that serves as the primary PM control device,
the wet scrubber must be maintained and operated.
* * * * *
(vi) If the measured 24-hour average opacity for your affected
facility remains at a level greater than the opacity baseline level
after 7 boiler operating 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 measured 24-hour average opacity was first
determined to exceed the baseline opacity level unless a waiver is
granted by the permitting authority.
(3) * * *
(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 wet scrubber must be maintained and
operated.
(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 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
facility startup, shutdown, or malfunction. * * *
* * * * *
(v) * * * This new performance test must be conducted within 60
calendar days of the date that the model parameter was first determined
to exceed its baseline level unless a waiver is granted by the
permitting authority.
(4) * * *
(i) * * *
(E) Following initial adjustment, you must not adjust the averaging
period, alarm set point, or alarm delay time without approval from the
permitting authority except as provided in paragraph (d)(1)(vi) of this
section.
* * * * *
(ii) You must develop and submit to the permitting authority for
approval a site-specific monitoring plan for each bag leak detection
system. * * *
* * * * *
(F) Corrective action procedures as specified in paragraph
(o)(4)(iii) of this section. In approving the site-specific monitoring
plan, the 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 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.
* * * * *
(v) If after any period 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 calendar days of the date that the alarm rate was
first determined to exceed 5 percent limit unless a waiver is granted
by the permitting authority.
(5) An owner or operator of a modified affected facility electing
to meet the emission limitations in Sec. 60.42Da(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
[[Page 5081]]
or operator may elect to install, evaluate, 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.
* * * * *
(2) Each CEMS shall be installed, evaluated, operated, and
maintained according to the requirements in Sec. 60.49Da(v).
* * * * *
(q) Compliance provisions for sources subject to Sec. 60.42Da(b).
An owner or operator of an affected facility subject to the opacity
standard in Sec. 60.42Da(b) shall monitor the opacity of emissions
discharged from the affected facility to the atmosphere according to
the requirements in Sec. 60.49Da(a), as applicable to the affected
facility.
0
11. Section 60.49Da is amended to read as follows:
0
a. By revising paragraph (a);
0
b. By revising paragraphs (b)(4) introductory text and (b)(4)(iii);
0
c. By revising paragraph (d);
0
d. By revising paragraph (i)(3);
0
e. By revising paragraph (k) introductory text;
0
f. By revising paragraph (t);
0
g. By revising paragraph (u);
0
h. By revising paragraphs (v) introductory text and (v)(2), and adding
paragraph (v)(4); and
0
j. By adding paragraph (w) introductory text;
0
k. By revising paragraphs (w)(1) and (w)(2).
Sec. 60.49Da Emission monitoring.
(a) An owner or operator of an affected facility subject to the
opacity standard in Sec. 60.42Da(b) shall monitor the opacity of
emissions discharged from the affected facility to the atmosphere
according to the applicable requirements in paragraphs (a)(1) through
(3) of this section.
(1) Except as provided for in paragraph (a)(2) of this section, the
owner or operator of an affected facility, shall install, calibrate,
maintain, and operate a COMS, 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).
(2) As an alternative to the monitoring requirements in paragraph
(a)(1) of this section, an owner or operator of an affected facility
that meets the conditions in either paragraph (a)(2)(i), (ii), or (iii)
of this section may elect to monitor opacity as specified in paragraph
(a)(3) of this section.
(i) The affected facility uses a fabric filter (baghouse) to meet
the standards in Sec. 60.42Da and a bag leak detection system is
installed and operated according to the requirements in paragraphs
Sec. 60.48Da(o)(4)(i) through (v);
(ii) The affected facility burns only gaseous or liquid fuels
(excluding residual oil) 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 emissions of SO2 or PM; or
(iii) The affected facility meets all of the conditions specified
in paragraphs (a)(2)(iii)(A) through (C) of this section.
(A) No post-combustion technology (except a wet scrubber) is used
for reducing PM, SO2, or carbon monoxide (CO) emissions;
(B) Only natural gas, gaseous fuels, or fuel oils that contain less
than or equal to 0.30 weight percent sulfur are burned; and
(C) Emissions of CO discharged to the atmosphere are maintained at
levels less than or equal to 1.4 lb/MWh on a boiler operating day
average basis as demonstrated by the use of a CEMS measuring CO
emissions according to the procedures specified in paragraph (u) of
this section.
(3) The owner or operators of an affected facility that meets the
conditions in paragraph (a)(2) of this section may, as an alternative
to COMS, elect to monitor visible emissions using the applicable
procedures specified in paragraphs (a)(3)(i) through (iv) of this
section.
(i) The owner or operator shall conduct a performance test using
Method 9 of appendix A-4 of this part and the procedures in Sec.
60.11. If during the initial 60 minutes of the observation all the 6-
minute averages are less than 10 percent and all the individual 15-
second observations are less than or equal to 20 percent, then the
observation period may be reduced from 3 hours to 60 minutes.
(ii) Except as provided in paragraph (a)(3)(iii) or (iv) of this
section, the owner or operator shall conduct subsequent Method 9 of
appendix A-4 of this part performance tests using the procedures in
paragraph (a)(3)(i) of this section according to the applicable
schedule in paragraphs (a)(3)(ii)(A) through (a)(3)(ii)(D) of this
section, as determined by the most recent Method 9 of appendix A-4 of
this part performance test results.
(A) If no visible emissions are observed, a subsequent Method 9 of
appendix A-4 of this part performance test must be completed within 12
calendar months from the date that the most recent performance test was
conducted;
(B) If visible emissions are observed but the maximum 6-minute
average opacity is less than or equal to 5 percent, a subsequent Method
9 of appendix A-4 of this part performance test must be completed
within 6 calendar months from the date that the most recent performance
test was conducted;
(C) If the maximum 6-minute average opacity is greater than 5
percent but less than or equal to 10 percent, a subsequent Method 9 of
appendix A-4 of this part performance test must be completed within 3
calendar months from the date that the most recent performance test was
conducted; or
(D) If the maximum 6-minute average opacity is greater than 10
percent, a subsequent Method 9 of appendix A-4 of this part performance
test must be completed within 30 calendar days from the date that the
most recent performance test was conducted.
(iii) If the maximum 6-minute opacity is less than 10 percent
during the most recent Method 9 of appendix A-4 of this part
performance test, the owner or operator may, as an alternative to
performing subsequent Method 9 of appendix A-4 of this part performance
tests, elect to perform subsequent monitoring using Method 22 of
appendix A-7 of this part according to the procedures specified in
paragraphs (a)(3)(iii)(A) and (B) of this section.
(A) The owner or operator shall conduct 10 minute observations
(during normal operation) each operating day the affected facility
fires fuel for which an opacity standard is applicable using Method 22
of appendix A-7 of this part and demonstrate that the sum of the
occurrences of any visible emissions is not in excess of 5 percent of
the observation period (i.e., 30 seconds per 10 minute period). If the
sum of the occurrence of any visible emissions is greater than 30
seconds during the initial 10 minute observation, immediately conduct a
30 minute observation. If the sum of the occurrence of visible
emissions is greater than 5 percent of the observation period (i.e., 90
seconds per 30 minute period) the owner or operator shall either
document and adjust the
[[Page 5082]]
operation of the facility and demonstrate within 24 hours that the sum
of the occurrence of visible emissions is equal to or less than 5
percent during a 30 minute observation (i.e., 90 seconds) or conduct a
new Method 9 of appendix A-4 of this part performance test using the
procedures in paragraph (a)(3)(i) of this section within 30 calendar
days according to the requirements in Sec. 60.50Da(b)(3).
(B) If no visible emissions are observed for 30 operating days
during which an opacity standard is applicable, observations can be
reduced to once every 7 operating days during which an opacity standard
is applicable. If any visible emissions are observed, daily
observations shall be resumed.
(iv) If the maximum 6-minute opacity is less than 10 percent during
the most recent Method 9 of appendix A-4 of this part performance test,
the owner or operator may, as an alternative to performing subsequent
Method 9 of appendix A-4 performance tests, elect to perform subsequent
monitoring using a digital opacity compliance system according to a
site-specific monitoring plan approved by the Administrator. The
observations shall be similar, but not necessarily identical, to the
requirements in paragraph (a)(3)(iii) of this section. For reference
purposes in preparing the monitoring plan, see OAQPS ``Determination of
Visible Emission Opacity from Stationary Sources Using Computer-Based
Photographic Analysis Systems.'' This document is available from the
U.S. Environmental Protection Agency (U.S. EPA); Office of Air Quality
and Planning 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 Preliminary Methods.
(b) * * *
(4) If the owner or operator has installed and certified a
SO2 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:
* * * * *
(iii) The reporting requirements of Sec. 60.51Da are met. The
SO2 and, if required, 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.
* * * * *
(d) The owner or operator of an affected facility not complying
with an output based limit 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.
* * * * *
(i) * * *
(3) For affected facilities burning only fossil fuel, the span
value for a COMS is between 60 and 80 percent. Span values for a CEMS
measuring NOX shall be determined using one of the following
procedures:
* * * * *
(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. Sec. 60.42Da(c), 60.43Da(i), 60.43Da(j), 60.44Da(d)(1), and
60.44Da(e).
* * * * *
(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 facility
demonstrating compliance with the input-based emission limitation in
Sec. 60.42Da(a)(1) or 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) The owner or operator of an affected facility using a CEMS
measuring CO emissions to meet requirements of this subpart shall meet
the requirements specified in paragraphs (u)(1) through (4) of this
section.
(1) You must monitor CO emissions using a CEMS according to the
procedures specified in paragraphs (u)(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. The 1-hour averages are calculated using the
data points required in Sec. 60.13(h)(2).
(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 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 facility. 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.
(3) You must evaluate the preceding 24-hour average CO emission
level each boiler operating day excluding periods of affected facility
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.
(4) You must record the CO measurements and calculations performed
according to paragraph (u)(3)
[[Page 5083]]
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)(4) of this section.
* * * * *
(2) During each PM correlation testing 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 performance
tests conducted using the following test methods.
(i) For PM, Method 5 or 5B of appendix A-3 of this part or Method
17 of appendix A-6 of this part shall be used; and
(ii) After July 1, 2010 or after Method 202 of appendix M of part
51 has been revised to minimize artifact measurement and notice of that
change has been published in the Federal Register, whichever is later,
for condensable PM emissions, Method 202 of appendix M of part 51 shall
be used; and
(iii) For O2 (or CO2), Method 3A or 3B of
appendix A-2 of this part, as applicable shall be used.
* * * * *
(4) After July 1, 2011, within 90 days after the date of completing
each performance evaluation required by paragraph (v) of this section,
the owner or operator of the affected facility must either submit the
test data to EPA by successfully entering the data electronically into
EPA's WebFIRE data base available at http://cfpub.epa.gov/oarweb/index.cfm?action=fire.main or mail a copy to: United States
Environmental Protection Agency; Energy Strategies Group; 109 TW
Alexander DR; Mail Code: D243-01; RTP, NC 27711.
(w) The owner or operator using a SO2, NOX,
CO2, and O2 CEMS to meet the requirements of this
subpart shall install, certify, operate, and maintain the CEMS as
specified in paragraphs (w)(1) through (w)(5) of this section.
(1) Except as provided for under paragraphs (w)(2), (w)(3), and
(w)(4) of this section, each 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.
(2) As an alternative to meeting the requirements of paragraph
(w)(1) of this section, an owner or operator 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 or equal to 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;
* * * * *
0
12. Section 60.50Da is amended by revising paragraphs (e)(1) and (f) to
read as follows:
Sec. 60.50Da Compliance determination procedures and methods.
* * * * *
(e) * * *
(1) For Method 5 or 5B of appendix A-3 of this part, Method 17 of
appendix A-6 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 sections 8.1 and 11.1 of Method 5B of appendix A-3 of
this part may be used in Method 17 of appendix A-6 of this part only if
it is used after wet FGD systems. Method 17 of appendix A-6 of this
part shall not be used after wet FGD systems if the effluent is
saturated or laden with water droplets.
* * * * *
(f) Electric utility combined cycle gas turbines that are not
designed to burn fuels containing 50 percent (by heat input) or more
solid derived fuel not meeting the definition of natural gas are
performance tested for PM, SO2, and NOX using the
procedures of Method 19 of appendix A-7 of this part. The
SO2 and NOX emission rates calculations from the
gas turbine used in Method 19 of appendix A-7 of this part 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.
* * * * *
0
13. Section 60.51Da is amended by revising paragraphs (b)(2) and (b)(3)
to read as follows:
Sec. 60.51Da Reporting requirements.
* * * * *
(b) * * *
(2) The average SO2 and NOX emission rates
(ng/J, lb/MMBtu, or lb/MWh) 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) For owners or operators of affected facilities complying with
the percent reduction requirement, 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.
* * * * *
0
14. Section 60.52Da is revised to read as follows:
Sec. 60.52Da Recordkeeping requirements.
(a) 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).
(b) The owner or operator of an affected facility subject to the
opacity limits in Sec. 60.42Da(b) that elects to monitor emissions
according to the requirements in Sec. 60.49Da(a)(3) shall maintain
records according to the requirements specified in paragraphs
[[Page 5084]]
(b)(1) through (3) of this section, as applicable to the visible
emissions monitoring method used.
(1) For each performance test conducted using Method 9 of appendix
A-4 of this part, the owner or operator shall keep the records
including the information specified in paragraphs (b)(1)(i) through
(iii) of this section.
(i) Dates and time intervals of all opacity observation periods;
(ii) Name, affiliation, and copy of current visible emission
reading certification for each visible emission observer participating
in the performance test; and
(iii) Copies of all visible emission observer opacity field data
sheets;
(2) For each performance test conducted using Method 22 of appendix
A-4 of this part, the owner or operator shall keep the records
including the information specified in paragraphs (b)(2)(i) through
(iv) of this section.
(i) Dates and time intervals of all visible emissions observation
periods;
(ii) Name and affiliation for each visible emission observer
participating in the performance test;
(iii) Copies of all visible emission observer opacity field data
sheets; and
(iv) Documentation of any adjustments made and the time the
adjustments were completed to the affected facility operation by the
owner or operator to demonstrate compliance with the applicable
monitoring requirements.
(3) For each digital opacity compliance system, the owner or
operator shall maintain records and submit reports according to the
requirements specified in the site-specific monitoring plan approved by
the Administrator.
Subpart Db--[Amended]
0
15. Section 60.40b is amended by revising the first sentence of
paragraph (i) to read as follows:
Sec. 60.40b Applicability and delegation of authority.
* * * * *
(i) Heat recovery steam generators that are associated with
combined cycle gas turbines and that meet the applicability
requirements of subpart KKKK of this part are not subject to this
subpart. * * *
* * * * *
0
16. Section 60.41b is amended by revising the definitions of ``Coal,''
``Distillate oil,'' ``Gaseous fuel,'' ``Gross output,'' ``Natural
gas,'' ``Potential sulfur dioxide emission rate,'' ``Steam generating
unit,'' and ``Very low sulfur oil'' to read as follows:
Sec. 60.41b Definitions.
* * * * *
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 not
meeting the definition of natural gas, coal-oil mixtures, coke oven
gas, and coal-water mixtures, are also included in this definition for
the purposes of this subpart.
* * * * *
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) or
diesel fuel oil numbers 1 and 2, as defined by the American Society for
Testing and Materials in ASTM D975 (incorporated by reference, see
Sec. 60.17).
* * * * *
Gaseous fuel means any fuel that is a gas at ISO conditions. This
includes, but is not limited to, natural gas and gasified coal
(including coke oven gas).
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 or to enhance the
performance of the unit (i.e., steam delivered to an industrial
process).
* * * * *
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); 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 dry standard cubic meter (910 and
1,150 Btu per dry standard cubic foot).
* * * * *
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. For gasified coal or oil that
is desulfurized prior to combustion, the Potential sulfur dioxide
emission rate is the theoretical SO2 emissions (ng/J or lb/
MMBtu heat input) that would result from combusting fuel in a cleaned
state without using any post combustion emission control systems.
* * * * *
Steam generating unit means a device that combusts any fuel or
byproduct/waste and produces steam or heats water or heats any 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.
* * * * *
Very low sulfur oil means for units constructed, reconstructed, or
modified on or before February 28, 2005, 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 and not
located in a noncontinental area, very low sulfur oil means oil that
contains no more than 0.30 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. For units constructed, reconstructed, or modified after February
28, 2005 and located in a noncontinental area, very low sulfur oil
means 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 (0.50 lb/
MMBtu) heat input.
0
17. Section 60.42b is amended to read as follows:
0
a. By revising paragraph (a);
0
b. By revising paragraph (b);
0
c. By revising paragraph (c);
0
d. By revising paragraph (d) introductory text; and
0
e. By revising paragraphs (k)(1), (k)(2), and (k)(3).
[[Page 5085]]
Sec. 60.42b Standard for sulfur dioxide (SO2).
(a) Except as provided in paragraphs (b), (c), (d), or (j) 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] TR28JA09.003
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).
For facilities complying with the percent reduction standard, only
the heat input supplied to the affected facility from the combustion of
coal and oil is counted in this paragraph. 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 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. For
facilities complying with the percent reduction standard, only the heat
input supplied to the affected facility from the combustion of coal and
oil is counted in this paragraph. 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.
(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] TR28JA09.004
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).
For facilities complying with the percent reduction standard, only
the heat input supplied to the affected facility from the combustion of
coal and oil is counted in this paragraph. 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.
For facilities complying with paragraphs (d)(1), (2), or (3) of this
section, only the heat input supplied to the affected facility from the
combustion of coal and oil is counted in this paragraph. 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.
* * * * *
(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. For
facilities complying with the percent reduction standard and paragraph
(k)(3) of this section, only the heat input supplied to the affected
facility from the combustion of coal and oil is counted in paragraph
(k) of 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.
(2) Units firing only very low sulfur oil, gaseous fuel, a mixture
of these fuels, or a mixture of these fuels with any other 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 (k)(1) of this section.
(3) Units that are located in a noncontinental area and that
combust coal, oil, or natural gas 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 or natural gas.
* * * * *
0
18. Section 60.43b is amended to read as follows:
0
a. By revising paragraph (f);
0
b. By revising paragraph (g); and
0
c. By revising paragraphs (h)(1) and (h)(5) and adding paragraph
(h)(6).
[[Page 5086]]
Sec. 60.43b Standard for particulate matter (PM).
* * * * *
(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 can
combust 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.
Owners and operators of an affected facility that elect to install,
calibrate, maintain, and operate a continuous emissions monitoring
system (CEMS) for measuring PM emissions according to the requirements
of this subpart and are subject to a federally enforceable PM limit of
0.030 lb/MMBtu or less are exempt from the opacity standard specified
in this paragraph.
(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),
(h)(5), and (h)(6) 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,
* * * * *
(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 not
located in a noncontinental area that commences construction,
reconstruction, or modification after February 28, 2005, and that
combusts only oil that contains no more than 0.30 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 in 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 in (h)(1) of this section.
(6) 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 located
in a noncontinental area that commences construction, reconstruction,
or modification after February 28, 2005, and that combusts only oil
that contains no more than 0.5 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 in 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 in (h)(1) of this section.
0
19. Section 60.44b is amended by revising paragraph (l)(1) to read as
follows:
Sec. 60.44b Standard for nitrogen oxides (NOX).
* * * * *
(l) * * *
(1) If the affected facility combusts coal, oil, natural gas, a
mixture of these fuels, or a mixture of these fuels 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
* * * * *
0
20. Section 60.45b is amended to read as follows:
0
a. By revising paragraph (a);
0
b. By revising paragraphs (c)(2)(i), (c)(4) introductory text, and
(c)(5);
0
c. By revising paragraph (d) introductory text;
0
d. By revising paragraph (j); and
0
e. By revising paragraph (k).
Sec. 60.45b Compliance and performance test methods and procedures
for sulfur dioxide.
(a) The SO2 emission standards in Sec. 60.42b apply at
all times. Facilities burning coke oven gas alone or in combination
with any other gaseous fuels or distillate oil are allowed to exceed
the limit 30 operating days per calendar year for SO2
control system maintenance.
* * * * *
(c) * * *
(2) * * *
(i) The procedures in Method 19 of appendix A-7 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 CEMS of Sec. 60.47b(a) or (b).
* * * * *
(4) The owner or operator of an affected facility subject to
paragraph (c)(3) of this section does not have to measure parameters
Ew or Xk if the owner or operator elects to
assume that Xk= 1.0. Owners or operators of affected
facilities who assume Xk = 1.0 shall:
* * * * *
(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 in paragraph (c)(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 in Method 19 of appendix A-7 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, natural gas, or a mixture of these fuels, 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:
* * * * *
(j) The owner or operator of an affected facility that only
combusts very low sulfur oil, natural gas, or a mixture of these fuels
with any other fuels not subject to an SO2 standard 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 in Sec. Sec. 60.42b(d)(4), 60.42b(j),
60.42b(k)(2), and 60.42b(k)(3) (when not burning coal) shall follow the
applicable procedures in Sec. 60.49b(r).
0
21. Section 60.46b is amended to read as follows:
0
a. By revising paragraphs (d)(1) and (d)(2)(ii);
0
b. By revising paragraphs (e)(2) and (e)(4);
0
c. By revising paragraph (g);
0
d. By revising paragraph (i); and
0
e. By revising paragraphs (j) introductory text and (j)(11) and adding
paragraph (j)(14).
Sec. 60.46b Compliance and performance test methods and procedures
for particulate matter and nitrogen oxides.
* * * * *
(d) * * *
(1) Method 3A or 3B of appendix A-2 of this part is used for gas
analysis when applying Method 5 of appendix
[[Page 5087]]
A-3 of this part or Method 17 of appendix A-6 of this part.
(2) * * *
(ii) Method 17 of appendix A-6 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 (320 [deg]F).
The procedures of sections 8.1 and 11.1 of Method 5B of appendix A-3 of
this part may be used in Method 17 of appendix A-6 of this part only if
it is used after a wet FGD system. Do not use Method 17 of appendix A-6
of this part after wet FGD systems if the effluent is saturated or
laden with water droplets.
* * * * *
(e) * * *
(2) Following the date on which the initial performance test is
completed or is required to be completed in Sec. 60.8, whichever date
comes first, the owner or operator of an affected facility which
combusts coal (except as specified under Sec. 60.46b(e)(4)) or which
combusts residual oil having a nitrogen content greater than 0.30
weight percent shall determine compliance with the NOX
emission standards in 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 for 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, gasified coal, or residual oil having a
nitrogen content of 0.30 weight percent or less shall upon request
determine compliance with the NOX standards in 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.
* * * * *
(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 or the heat input 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 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.
* * * * *
(i) The owner or operator of an affected facility seeking to
demonstrate compliance with the PM limit in paragraphs Sec.
60.43b(a)(4) or Sec. 60.43b(h)(5) shall follow the applicable
procedures in Sec. 60.49b(r).
(j) In place of PM testing with Method 5 or 5B of appendix A-3 of
this part, or Method 17 of appendix A-6 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 Method 5 or 5B of appendix A-3 of this part
or Method 17 of appendix A-6 of this part shall comply with the
requirements specified in paragraphs (j)(1) through (j)(14) of this
section.
* * * * *
(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 performance tests conducted using the following test
methods.
(i) For PM, Method 5 or 5B of appendix A-3 of this part or Method
17 of appendix A-6 of this part shall be used; and
(ii) After July 1, 2010 or after Method 202 of appendix M of part
51 has been revised to minimize artifact measurement and notice of that
change has been published in the Federal Register, whichever is later,
for condensable PM emissions, Method 202 of appendix M of part 51 shall
be used; and
(iii) For O2 (or CO2), Method 3A or 3B of
appendix A-2 of this part, as applicable shall be used.
* * * * *
(14) After July 1, 2011, within 90 days after completing a
correlation testing run, the owner or operator of an affected facility
shall either successfully enter the test data into EPA's WebFIRE data
base located at http://cfpub.epa.gov/oarweb/index.cfm?action=fire.main
or mail a copy to: United States Environmental Protection Agency;
Energy Strategies Group; 109 TW Alexander DR; Mail Code: D243-01; RTP,
NC 27711.
* * * * *
0
22. Section 60.47b is amended by revising the first sentence of
paragraph (a) introductory text and the first sentence of paragraph
(e)(4)(i) to read as follows:
Sec. 60.47b Emission monitoring for sulfur dioxide.
(a) Except as provided in paragraphs (b) and (f) of this section,
the owner or operator of an affected facility subject to the
SO2 standards in 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. * * *
* * * * *
(e) * * *
(4) * * *
(i) For all required CO2 and O2 monitors and
for SO2 and NOX monitors with span values greater
than or equal to 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. * * *
* * * * *
0
23. Section 60.48b is amended to read as follows:
[[Page 5088]]
0
a. By revising paragraph (a);
0
b. By revising paragraph (e)(1);
0
c. By revising paragraph (g) introductory text;
0
d. By revising paragraph (h);
0
e. By revising paragraphs (j) introductory text, the last sentence of
(j)(4) introductory text, (j)(4)(i)(C), (j)(5) and adding (j)(6); and
0
f. By revising the first sentence of paragraph (k).
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
continuous opacity monitoring systems (COMS) for measuring the opacity
of emissions discharged to the atmosphere and record the output of the
system. The owner or operator of an affected facility subject to an
opacity standard under Sec. 60.43b and meeting the conditions under
paragraphs (j)(1), (2), (3), (4), or (5) of this section who elects not
to install a COMS shall conduct a performance test using Method 9 of
appendix A-4 of this part and the procedures in Sec. 60.11 to
demonstrate compliance with the applicable limit in Sec. 60.43b and
shall comply with either paragraphs (a)(1), (a)(2), or (a)(3) of this
section. If during the initial 60 minutes of observation all 6-minute
averages are less than 10 percent and all individual 15-second
observations are less than or equal to 20 percent, the observation
period may be reduced from 3 hours to 60 minutes.
(1) Except as provided in paragraph (a)(2) and (a)(3) of this
section, the owner or operator shall conduct subsequent Method 9 of
appendix A-4 of this part performance tests using the procedures in
paragraph (a) of this section according to the applicable schedule in
paragraphs (a)(1)(i) through (a)(1)(iv) of this section, as determined
by the most recent Method 9 of appendix A-4 of this part performance
test results.
(i) If no visible emissions are observed, a subsequent Method 9 of
appendix A-4 of this part performance test must be completed within 12
calendar months from the date that the most recent performance test was
conducted;
(ii) If visible emissions are observed but the maximum 6-minute
average opacity is less than or equal to 5 percent, a subsequent Method
9 of appendix A-4 of this part performance test must be completed
within 6 calendar months from the date that the most recent performance
test was conducted;
(iii) If the maximum 6-minute average opacity is greater than 5
percent but less than or equal to 10 percent, a subsequent Method 9 of
appendix A-4 of this part performance test must be completed within 3
calendar months from the date that the most recent performance test was
conducted; or
(iv) If the maximum 6-minute average opacity is greater than 10
percent, a subsequent Method 9 of appendix A-4 of this part performance
test must be completed within 30 calendar days from the date that the
most recent performance test was conducted.
(2) If the maximum 6-minute opacity is less than 10 percent during
the most recent Method 9 of appendix A-4 of this part performance test,
the owner or operator may, as an alternative to performing subsequent
Method 9 of appendix A-4 of this part performance tests, elect to
perform subsequent monitoring using Method 22 of appendix A-7 of this
part according to the procedures specified in paragraphs (a)(2)(i) and
(ii) of this section.
(i) The owner or operator shall conduct 10 minute observations
(during normal operation) each operating day the affected facility
fires fuel for which an opacity standard is applicable using Method 22
of appendix A-7 of this part and demonstrate that the sum of the
occurrences of any visible emissions is not in excess of 5 percent of
the observation period (i.e., 30 seconds per 10 minute period). If the
sum of the occurrence of any visible emissions is greater than 30
seconds during the initial 10 minute observation, immediately conduct a
30 minute observation. If the sum of the occurrence of visible
emissions is greater than 5 percent of the observation period (i.e., 90
seconds per 30 minute period) the owner or operator shall either
document and adjust the operation of the facility and demonstrate
within 24 hours that the sum of the occurrence of visible emissions is
equal to or less than 5 percent during a 30 minute observation (i.e.,
90 seconds) or conduct a new Method 9 of appendix A-4 of this part
performance test using the procedures in paragraph (a) of this section
within 30 calendar days according to the requirements in Sec.
60.46d(d)(7).
(ii) If no visible emissions are observed for 30 operating days
during which an opacity standard is applicable, observations can be
reduced to once every 7 operating days during which an opacity standard
is applicable. If any visible emissions are observed, daily
observations shall be resumed.
(3) If the maximum 6-minute opacity is less than 10 percent during
the most recent Method 9 of appendix A-4 of this part performance test,
the owner or operator may, as an alternative to performing subsequent
Method 9 of appendix A-4 performance tests, elect to perform subsequent
monitoring using a digital opacity compliance system according to a
site-specific monitoring plan approved by the Administrator. The
observations shall be similar, but not necessarily identical, to the
requirements in paragraph (a)(2) of this section. For reference
purposes in preparing the monitoring plan, see OAQPS ``Determination of
Visible Emission Opacity from Stationary Sources Using Computer-Based
Photographic Analysis Systems.'' This document is available from the
U.S. Environmental Protection Agency (U.S. EPA); Office of Air Quality
and Planning 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 Preliminary Methods.
* * * * *
(e) * * *
(1) For affected facilities combusting coal, wood or municipal-type
solid waste, the span value for a COMS shall be between 60 and 80
percent.
* * * * *
(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, gasified coal, or
any mixture of these fuels, greater than 10 percent (0.10) shall:
* * * * *
(h) The owner or operator of a duct burner, as described in Sec.
60.41b, that is subject to the NOX standards in Sec.
60.44b(a)(4), Sec. 60.44b(e), or Sec. 60.44b(l) is not required to
install or operate a continuous emissions monitoring system to measure
NOX emissions.
* * * * *
(j) The owner or operator of an affected facility that meets the
conditions in either paragraph (j)(1), (2), (3), (4), (5), or (6) of
this section is not required to install or operate a COMS if:
* * * * *
(4) * * * Owners and 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; or
[[Page 5089]]
(i) * * *
(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. The 1-hour averages are calculated using the
data points required in Sec. 60.13(h)(2).
* * * * *
(5) The affected facility uses a bag leak detection system to
monitor the performance of a fabric filter (baghouse) according to the
most recent requirements in section Sec. 60.48Da of this part; or
(6) 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 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 must calibrate, maintain, operate, and record the
output of the system for PM emissions discharged to the atmosphere as
specified in Sec. 60.46b(j). * * *
0
24. Section 60.49b is amended to read as follows:
0
a. By revising paragraphs (c) introductory text and (c)(3);
0
b. By revising paragraph (d);
0
c. By revising paragraph (f);
0
d. By revising paragraph (h)(1) and (h)(2)(i);
0
e. By revising paragraph (k)(2);
0
f. By revising paragraph (m) introductory text; and
0
g. By revising paragraph (r)(1).
Sec. 60.49b Reporting and recordkeeping requirements.
* * * * *
(c) The owner or operator of each affected facility subject to the
NOX standard in Sec. 60.44b who seeks to demonstrate
compliance with those standards through the monitoring of steam
generating unit operating conditions in 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 in Sec.
60.48b(g)(2) and the records to be maintained in Sec. 60.49b(g). This
plan shall be submitted to the Administrator for approval within 360
days of the initial startup of the affected facility. An affected
facility burning coke oven gas alone or in combination with other
gaseous fuels or distillate oil shall submit this plan to the
Administrator for approval within 360 days of the initial startup of
the affected facility or by November 30, 2009, whichever date comes
later. 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:
* * * * *
(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 maintained by the owner or
operator under Sec. 60.49b(g).
(d) Except as provided in paragraph (d)(2) of this section, the
owner or operator of an affected facility shall record and maintain
records as specified in paragraph (d)(1) of this section.
(1) 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.
(2) As an alternative to meeting the requirements of paragraph
(d)(1) of this section, the owner or operator of an affected facility
that is subject to a federally enforceable permit restricting fuel use
to a single fuel such that the facility is not required to continuously
monitor any emissions (excluding opacity) or parameters indicative of
emissions may elect to record and maintain records of the amount of
each fuel combusted during each calendar month.
* * * * *
(f) For an affected facility subject to the opacity standard in
Sec. 60.43b, the owner or operator shall maintain records of opacity.
In addition, an owner or operator that elects to monitor emissions
according to the requirements in Sec. 60.48b(a) shall maintain records
according to the requirements specified in paragraphs (f)(1) through
(3) of this section, as applicable to the visible emissions monitoring
method used.
(1) For each performance test conducted using Method 9 of appendix
A-4 of this part, the owner or operator shall keep the records
including the information specified in paragraphs (f)(1)(i) through
(iii) of this section.
(i) Dates and time intervals of all opacity observation periods;
(ii) Name, affiliation, and copy of current visible emission
reading certification for each visible emission observer participating
in the performance test; and
(iii) Copies of all visible emission observer opacity field data
sheets;
(2) For each performance test conducted using Method 22 of appendix
A-4 of this part, the owner or operator shall keep the records
including the information specified in paragraphs (f)(2)(i) through
(iv) of this section.
(i) Dates and time intervals of all visible emissions observation
periods;
(ii) Name and affiliation for each visible emission observer
participating in the performance test;
(iii) Copies of all visible emission observer opacity field data
sheets; and
(iv) Documentation of any adjustments made and the time the
adjustments were completed to the affected facility operation by the
owner or operator to demonstrate compliance with the applicable
monitoring requirements.
(3) For each digital opacity compliance system, the owner or
operator shall maintain records and submit reports according to the
requirements specified in the site-specific monitoring plan approved by
the Administrator.
* * * * *
(h) * * *
(1) Any affected facility subject to the opacity standards in Sec.
60.43b(f) or to the operating parameter monitoring requirements in
Sec. 60.13(i)(1).
(2) * * *
(i) Combusts natural gas, distillate oil, gasified coal, or
residual oil with a nitrogen content of 0.3 weight percent or less; or
* * * * *
(k) * * *
(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; For an
exceedance due to maintenance of the SO2 control system
covered in paragraph 60.45b(a), the report shall identify the days on
which the
[[Page 5090]]
maintenance was performed and a description of the maintenance;
* * * * *
(m) For each affected facility subject to the SO2
standards in Sec. 60.42(b) for which the minimum amount of data
required in Sec. 60.47b(c) 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:
* * * * *
(r) * * *
(1) The owner or operator of an affected facility who elects to
demonstrate that the affected facility combusts only very low sulfur
oil, natural gas, wood, a mixture of these fuels, or any of these fuels
(or a mixture of these fuels) in combination with other fuels that are
known to contain an insignificant amount of sulfur in Sec. 60.42b(j)
or Sec. 60.42b(k) 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 and gaseous fuel meets the definition
of natural gas 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,
natural gas, wood, and/or other fuels that are known to contain
insignificant amounts of sulfur were combusted in the affected facility
during the reporting period; or
* * * * *
Subpart Dc--[Amended]
0
25. Section 60.40c is amended to read as follows:
0
a. By revising paragraph (a);
0
b. By revising the first sentence of paragraph (e);
0
c. By revising paragraph (f); and
0
d. By revising paragraph (g).
Sec. 60.40c Applicability and delegation of authority.
(a) Except as provided in paragraphs (d), (e), (f), and (g) 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).
* * * * *
(e) Heat recovery steam generators that are associated with
combined cycle gas turbines and meet the applicability requirements of
subpart KKKK of this part are not subject to this subpart. * * *
(f) Any facility covered by subpart AAAA of this part is not
subject 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
subject by this subpart.
0
26. Section 60.41c is amended by revising the definitions of ``Coal,''
``Distillate oil,'' ``Natural gas,'' and ``Steam generating unit'' to
read as follows:
Sec. 60.41c Definitions.
* * * * *
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 not meeting the
definition of natural gas, coal-oil mixtures, and coal-water mixtures,
are also included in this definition for the purposes of this subpart.
* * * * *
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) or diesel fuel oil numbers 1 or 2, as defined by the
American Society for Testing and Materials in ASTM D975 (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) Liquefied petroleum (LP) gas, as defined by the American
Society for 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 dry standard cubic meter (910 and
1,150 Btu per dry standard cubic foot).
* * * * *
Steam generating unit means a device that combusts any fuel and
produces steam or heats water or heats any 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.
* * * * *
0
27. Section 60.42c is amended by revising paragraphs (e)(2) and (j) to
read as follows:
Sec. 60.42c Standard for sulfur dioxide (SO2).
* * * * *
(e) * * *
(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] TR28JA09.005
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 = Heat input from the combustion of oil, in J (MMBtu).
* * * * *
(j) For affected facilities located in noncontinental areas and
affected facilities complying with the percent reduction standard, only
the heat input supplied to the affected facility from the
[[Page 5091]]
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.
0
28. Section 60.43c is amended by revising paragraph (c) to read as
follows:
Sec. 60.43c Standard for particulate matter (PM).
* * * * *
(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 can
combust 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. Owners and operators of an
affected facility that elect to install, calibrate, maintain, and
operate a continuous emissions monitoring system (CEMS) for measuring
PM emissions according to the requirements of this subpart and are
subject to a federally enforceable PM limit of 0.030 lb/MMBtu or less
are exempt from the opacity standard specified in this paragraph.
* * * * *
0
29. Section 60.44c is amended by revising paragraph (h) to read as
follows:
Sec. 60.44c Compliance and performance test methods and procedures
for sulfur dioxide.
* * * * *
(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 from the fuel
supplier, as described in Sec. 60.48c(f), as applicable.
* * * * *
0
30. Section 60.45c is amended to read as follows:
0
a. By revising paragraphs (a)(2) and (a)(8);
0
b. By revising paragraphs (c) introductory text, (c)(7) introductory
text, (c)(8), (c)(9), and (c)(11), and by adding paragraph (c)(14).
Sec. 60.45c Compliance and performance test methods and procedures
for particulate matter.
(a) * * *
(2) Method 3A or 3B of appendix A-2 of this part shall be used for
gas analysis when applying Method 5 or 5B of appendix A-3 of this part
or 17 of appendix A-6 of this part.
* * * * *
(8) Method 9 of appendix A-4 of this part shall be used for
determining the opacity of stack emissions.
* * * * *
(c) In place of PM testing with Method 5 or 5B of appendix A-3 of
this part or Method 17 of appendix A-6 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 Method 5 or 5B of appendix A-3 of this part
or Method 17 of appendix A-6 of this part shall install, calibrate,
maintain, and operate a CEMS and shall comply with the requirements
specified in paragraphs (c)(1) through (c)(14) of this section.
* * * * *
(7) At a minimum, valid CEMS hourly averages shall be obtained as
specified in paragraph (c)(7)(i) of this section for 75 percent of the
total operating hours per 30-day rolling average.
* * * * *
(8) The 1-hour arithmetic averages required under paragraph (c)(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 (c)(7) of this section are not met.
* * * * *
(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 performance tests conducted using the following test
methods.
(i) For PM, Method 5 or 5B of appendix A-3 of this part or Method
17 of appendix A-6 of this part shall be used; and
(ii) After July 1, 2010 or after Method 202 of appendix M of part
51 has been revised to minimize artifact measurement and notice of that
change has been published in the Federal Register, whichever is later,
for condensable PM emissions, Method 202 of appendix M of part 51 shall
be used; and
(iii) For O2 (or CO2), Method 3A or 3B of appendix A-2
of this part, as applicable shall be used.
* * * * *
(14) After July 1, 2011, within 90 days after the date of
completing each performance evaluation required by paragraph (c)(11) of
this section, the owner or operator of the affected facility must
either submit the test data to EPA by successfully entering the data
electronically into EPA's WebFIRE data base available at http://cfpub.epa.gov/oarweb/index.cfm?action=fire.main or mail a copy to:
United States Environmental Protection Agency; Energy Strategies Group;
109 TW Alexander DR; Mail Code: D243-01; RTP, NC 27711.
* * * * *
0
31. Section 60.47c is amended to read as follows:
0
a. By revising paragraph (a);
0
b. By revising paragraph (b);
0
c. By revising paragraph (c);
0
d. By revising paragraph (d);
0
e. By revising paragraphs (e) introductory text and (e)(1)(iii);
0
f. By revising paragraph (f); and
0
g. By adding paragraph (g).
Sec. 60.47c Emission monitoring for particulate matter.
(a) Except as provided in paragraphs (c), (d), (e), (f), and (g) 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 continuous
opacity monitoring system (COMS) for measuring the opacity of the
emissions discharged to the atmosphere and record the output of the
system. The owner or operator of an affected facility subject to an
opacity standard in Sec. 60.43c(c) and that is not required to install
a COMS due to paragraphs (c), (d), (e), or (f) of this section that
elects not to install a COMS shall conduct a performance test using
Method 9 of appendix A-4 of this part and the procedures in Sec. 60.11
to demonstrate compliance with the applicable limit in Sec. 60.43c and
shall comply with either paragraphs (a)(1), (a)(2), or (a)(3) of this
section. If during the initial 60 minutes of observation all 6-minute
averages are less than 10 percent and all individual 15-second
observations are less than or equal to 20 percent, the observation
period may be reduced from 3 hours to 60 minutes.
[[Page 5092]]
(1) Except as provided in paragraph (a)(2) and (a)(3) of this
section, the owner or operator shall conduct subsequent Method 9 of
appendix A-4 of this part performance tests using the procedures in
paragraph (a) of this section according to the applicable schedule in
paragraphs (a)(1)(i) through (a)(1)(iv) of this section, as determined
by the most recent Method 9 of appendix A-4 of this part performance
test results.
(i) If no visible emissions are observed, a subsequent Method 9 of
appendix A-4 of this part performance test must be completed within 12
calendar months from the date that the most recent performance test was
conducted;
(ii) If visible emissions are observed but the maximum 6-minute
average opacity is less than or equal to 5 percent, a subsequent Method
9 of appendix A-4 of this part performance test must be completed
within 6 calendar months from the date that the most recent performance
test was conducted;
(iii) If the maximum 6-minute average opacity is greater than 5
percent but less than or equal to 10 percent, a subsequent Method 9 of
appendix A-4 of this part performance test must be completed within 3
calendar months from the date that the most recent performance test was
conducted; or
(iv) If the maximum 6-minute average opacity is greater than 10
percent, a subsequent Method 9 of appendix A-4 of this part performance
test must be completed within 30 calendar days from the date that the
most recent performance test was conducted.
(2) If the maximum 6-minute opacity is less than 10 percent during
the most recent Method 9 of appendix A-4 of this part performance test,
the owner or operator may, as an alternative to performing subsequent
Method 9 of appendix A-4 of this part performance tests, elect to
perform subsequent monitoring using Method 22 of appendix A-7 of this
part according to the procedures specified in paragraphs (a)(2)(i) and
(ii) of this section.
(i) The owner or operator shall conduct 10 minute observations
(during normal operation) each operating day the affected facility
fires fuel for which an opacity standard is applicable using Method 22
of appendix A-7 of this part and demonstrate that the sum of the
occurrences of any visible emissions is not in excess of 5 percent of
the observation period (i.e. , 30 seconds per 10 minute period). If the
sum of the occurrence of any visible emissions is greater than 30
seconds during the initial 10 minute observation, immediately conduct a
30 minute observation. If the sum of the occurrence of visible
emissions is greater than 5 percent of the observation period (i.e. ,
90 seconds per 30 minute period) the owner or operator shall either
document and adjust the operation of the facility and demonstrate
within 24 hours that the sum of the occurrence of visible emissions is
equal to or less than 5 percent during a 30 minute observation (i.e. ,
90 seconds) or conduct a new Method 9 of appendix A-4 of this part
performance test using the procedures in paragraph (a) of this section
within 30 calendar days according to the requirements in Sec.
60.45c(a)(8).
(ii) If no visible emissions are observed for 30 operating days
during which an opacity standard is applicable, observations can be
reduced to once every 7 operating days during which an opacity standard
is applicable. If any visible emissions are observed, daily
observations shall be resumed.
(3) If the maximum 6-minute opacity is less than 10 percent during
the most recent Method 9 of appendix A-4 of this part performance test,
the owner or operator may, as an alternative to performing subsequent
Method 9 of appendix A-4 performance tests, elect to perform subsequent
monitoring using a digital opacity compliance system according to a
site-specific monitoring plan approved by the Administrator. The
observations shall be similar, but not necessarily identical, to the
requirements in paragraph (a)(2) of this section. For reference
purposes in preparing the monitoring plan, see OAQPS ``Determination of
Visible Emission Opacity from Stationary Sources Using Computer-Based
Photographic Analysis Systems.'' This document is available from the
U.S. Environmental Protection Agency (U.S. EPA); Office of Air Quality
and Planning 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 Preliminary Methods.
(b) All COMS shall be operated in accordance with the 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) Owners and operators of an 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 (0.060 lb/MMBtu) heat input or less and that do not
use a post-combustion technology to reduce SO2 or PM emissions and that
are subject to an opacity standard in Sec. 60.43c(c) are not required
to operate a COMS if they follow the applicable procedures in Sec.
60.48c(f).
(d) Owners or operators complying with the PM emission limit by
using a PM CEMS must calibrate, maintain, operate, and record the
output of the system for PM emissions discharged to the atmosphere as
specified in Sec. 60.45c(c). The CEMS specified in paragraph Sec.
60.45c(c) 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) Owners and operators of an affected facility that is subject to
an opacity standard in Sec. 60.43c(c) and 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 discharged 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. 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; or
(1) * * *
(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. The 1-hour averages are calculated using the
data points required in Sec. 60.13(h)(2).
* * * * *
(f) Owners and operators of an affected facility that is subject to
an opacity standard in Sec. 60.43c(c) and that uses a bag leak
detection system to monitor the performance of a fabric filter
(baghouse) according to the most recent requirements in section Sec.
60.48Da of this part is not required to operate a COMS.
(g) Owners and operators of an affected facility that is subject to
an opacity standard in Sec. 60.43c(c) and 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
[[Page 5093]]
approved by the permitting authority is not required to operate a COMS.
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.
0
32. Section 60.48c is amended to read as follows:
0
a. By revising paragraph (c);
0
b. By revising paragraph (e)(11); and
0
c. By revising paragraphs (f)(1)(iii) and (f)(4)(ii).
Sec. 60.48c Reporting and recordkeeping requirements.
* * * * *
(c) In addition to the applicable requirements in Sec. 60.7, the
owner or operator of an affected facility subject to the opacity limits
in Sec. 60.43c(c) shall submit excess emission reports for any excess
emissions from the affected facility that occur during the reporting
period and maintain records according to the requirements specified in
paragraphs (c)(1) through (3) of this section, as applicable to the
visible emissions monitoring method used.
(1) For each performance test conducted using Method 9 of appendix
A-4 of this part, the owner or operator shall keep the records
including the information specified in paragraphs (c)(1)(i) through
(iii) of this section.
(i) Dates and time intervals of all opacity observation periods;
(ii) Name, affiliation, and copy of current visible emission
reading certification for each visible emission observer participating
in the performance test; and
(iii) Copies of all visible emission observer opacity field data
sheets;
(2) For each performance test conducted using Method 22 of appendix
A-4 of this part, the owner or operator shall keep the records
including the information specified in paragraphs (c)(2)(i) through
(iv) of this section.
(i) Dates and time intervals of all visible emissions observation
periods;
(ii) Name and affiliation for each visible emission observer
participating in the performance test;
(iii) Copies of all visible emission observer opacity field data
sheets; and
(iv) Documentation of any adjustments made and the time the
adjustments were completed to the affected facility operation by the
owner or operator to demonstrate compliance with the applicable
monitoring requirements.
(3) For each digital opacity compliance system, the owner or
operator shall maintain records and submit reports according to the
requirements specified in the site-specific monitoring plan approved by
the Administrator
* * * * *
(e) * * *
(11) If 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) * * *
(1) * * *
(iii) The sulfur content or maximum sulfur content of the oil.
* * * * *
(4) * * *
(ii) The potential sulfur emissions rate or maximum potential
sulfur emissions rate of the fuel in ng/J heat input; and
* * * * *
[FR Doc. E9-523 Filed 1-27-09; 8:45 am]
BILLING CODE 6560-50-P