[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]



[[Page 5071]]

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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: 
<a href="/cdn-cgi/l/email-protection#b2d4d7dededcd7c09cd1dac0dbc1c6dbd3dcf2d7c2d39cd5ddc4"><span class="__cf_email__" data-cfemail="89efece5e5e7ecfba7eae1fbe0fafde0e8e7c9ecf9e8a7eee6ff">[email protected]</span></a>.

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
------------------------------------------------------------------------
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.
------------------------------------------------------------------------
\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

[[Page 5073]]

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 
(SO<INF>2</INF>) limit during SO<INF>2</INF> control system maintenance 
and allowing the use of parametric monitoring of nitrogen oxide 
(NO<INF>X</INF>) 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

[[Page 5074]]

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

[[Page 5075]]

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.

[[Page 5076]]

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 
SO<INF>2</INF> 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 SO<INF>2</INF> as measured by a CEMS exceed the 
applicable standard in Sec.  60.43. Facilities complying with the 30-
day SO<INF>2</INF> standard shall use the most current associated 
SO<INF>2</INF> 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 NO<INF>X</INF> 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 NO<INF>X</INF> as measured by a CEMS exceed the 
applicable standard in Sec.  60.44. Facilities complying with the 30-
day NO<INF>X</INF> standard shall use the most current associated 
NO<INF>X</INF> 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 NO<INF>X</INF> and oxygen (O<INF>2</INF>) (or carbon 
dioxide (CO<INF>2</INF>)) 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 SO<INF>2</INF> 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 SO<INF>2</INF> emissions rates 
of 26 ng/J (0.060 lb/MMBtu) or less, and does not use a post-combustion 
technology to reduce emissions of SO<INF>2</INF> 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, SO<INF>2</INF>, 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 
SO<INF>2</INF> 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 
SO<INF>2</INF> and, if required, CO<INF>2</INF> (or O<INF>2</INF>) 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 SO<INF>2</INF> 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 
O<INF>2</INF> or carbon dioxide (CO<INF>2</INF>) content of the flue 
gases at each location where SO<INF>2</INF> or NO<INF>X</INF> emissions 
are monitored. For affected facilities subject to a lb/MMBtu 
SO<INF>2</INF> emission limit under Sec.  60.43Da, if the owner or 
operator has installed and certified a CO<INF>2</INF> or O<INF>2</INF> 
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 SO<INF>2</INF> concentration 
monitoring system described in paragraph (b) of this section, to 
determine the SO<INF>2</INF> emission rate in lb/MMBtu. SO<INF>2</INF> 
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 NO<INF>X</INF> 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 
O<INF>2</INF> (or CO<INF>2</INF>) 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 O<INF>2</INF> (or CO<INF>2</INF>), 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 SO<INF>2</INF>, NO<INF>X</INF>, 
CO<INF>2</INF>, and O<INF>2</INF> 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 SO<INF>2</INF>, NO<INF>X</INF>, 
CO<INF>2</INF>, and O<INF>2</INF> 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 CO<INF>2</INF> and O<INF>2</INF> CEMS and for SO<INF>2</INF> 
and NO<INF>X</INF> 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 SO<INF>2</INF> and 
NO<INF>X</INF> 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, SO<INF>2</INF>, and NO<INF>X</INF> using the 
procedures of Method 19 of appendix A-7 of this part. The 
SO<INF>2</INF> and NO<INF>X</INF> 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 SO<INF>2</INF> and NO<INF>X</INF> 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 SO<INF>2</INF> 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 
SO<INF>2</INF> 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 SO<INF>2</INF> 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 
SO<INF>2</INF> emission control, has a SO<INF>2</INF> 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 SO<INF>2</INF> emission control, has a SO<INF>2</INF> 
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 SO<INF>2</INF> emission control, has a 
SO<INF>2</INF> 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 (SO<INF>2</INF>).

    (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 SO<INF>2</INF> in excess of 87 ng/J 
(0.20 lb/MMBtu) or 10 percent (0.10) of the potential SO<INF>2</INF> 
emission rate (90 percent reduction) and the emission limit determined 
according to the following formula:
[GRAPHIC] [TIFF OMITTED] TR28JA09.003

Where:

E<INF>s</INF> = SO<INF>2</INF> emission limit, in ng/J or lb/MMBtu 
heat input;
K<INF>a</INF> = 520 ng/J (or 1.2 lb/MMBtu);
K<INF>b</INF> = 340 ng/J (or 0.80 lb/MMBtu);
H<INF>a</INF> = Heat input from the combustion of coal, in J 
(MMBtu); and
H<INF>b</INF> = 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 SO<INF>2</INF> in excess of 87 ng/J 
(0.20 lb/MMBtu) or 20 percent (0.20) of the potential SO<INF>2</INF> 
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 SO<INF>2</INF> 
emissions, shall cause to be discharged into the atmosphere any gases 
that contain SO<INF>2</INF> in excess of 50 percent of the potential 
SO<INF>2</INF> emission rate (50 percent reduction) and that contain 
SO<INF>2</INF> in excess of the emission limit determined according to 
the following formula:

[GRAPHIC] [TIFF OMITTED] TR28JA09.004

Where:

E<INF>s</INF> = SO2 emission limit, in ng/J or lb/MM Btu heat input;
K<INF>c</INF> = 260 ng/J (or 0.60 lb/MMBtu);
K<INF>d</INF> = 170 ng/J (or 0.40 lb/MMBtu);
H<INF>c</INF> = Heat input from the combustion of coal, in J 
(MMBtu); and
H<INF>d</INF> = 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 
SO<INF>2</INF> 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 SO<INF>2</INF> in excess of 87 ng/J (0.20 lb/MMBtu) heat input 
or 8 percent (0.08) of the potential SO<INF>2</INF> 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 SO<INF>2</INF> emission rate of 140 ng/J (0.32 lb/MMBtu) heat 
input or less are exempt from the SO<INF>2</INF> 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 SO<INF>2</INF> 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 SO<INF>2</INF> 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 SO<INF>2</INF> 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 (NO<INF>X</INF>).

* * * * *
    (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 SO<INF>2</INF> 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 SO<INF>2</INF> 
control system maintenance.
* * * * *
    (c) * * *
    (2) * * *
    (i) The procedures in Method 19 of appendix A-7 of this part are 
used to determine the hourly SO<INF>2</INF> emission rate 
(E<INF>ho</INF>) and the 30-day average emission rate (E<INF>ao</INF>). 
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 
E<INF>w</INF> or X<INF>k</INF> if the owner or operator elects to 
assume that X<INF>k</INF>= 1.0. Owners or operators of affected 
facilities who assume X<INF>k</INF> = 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 E<INF>w</INF> or X<INF>k</INF> in paragraph (c)(3) of this 
section if the owner or operator of the affected facility elects to 
measure SO<INF>2</INF> 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 SO<INF>2</INF> 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 NO<INF>X</INF> 
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 NO<INF>X</INF> 
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 NO<INF>X</INF> standards in Sec.  60.44b 
through the use of a 30-day performance test. During periods when 
performance tests are not requested, NO<INF>X</INF> 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 NO<INF>X</INF> 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 
NO<INF>X</INF> 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 
O<INF>2</INF> (or CO<INF>2</INF>) 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 O<INF>2</INF> (or CO<INF>2</INF>), 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 
SO<INF>2</INF> standards in Sec.  60.42b shall install, calibrate, 
maintain, and operate CEMS for measuring SO<INF>2</INF> concentrations 
and either O<INF>2</INF> or CO<INF>2</INF> concentrations and shall 
record the output of the systems. * * *
* * * * *
    (e) * * *
    (4) * * *
    (i) For all required CO<INF>2</INF> and O<INF>2</INF> monitors and 
for SO<INF>2</INF> and NO<INF>X</INF> 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 NO<INF>X</INF> 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 
NO<INF>X</INF> 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 
NO<INF>X</INF> 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 SO<INF>2</INF> 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 SO<INF>2</INF> 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 SO<INF>2</INF> 
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 (SO<INF>2</INF>).

* * * * *
    (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:

E<INF>s</INF> = SO<INF>2</INF> emission limit, expressed in ng/J or 
lb/MMBtu heat input;
K<INF>a</INF> = 520 ng/J (1.2 lb/MMBtu);
K<INF>b</INF> = 260 ng/J (0.60 lb/MMBtu);
K<INF>c</INF> = 215 ng/J (0.50 lb/MMBtu);
H<INF>a</INF> = 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];
H<INF>b</INF> = Heat input from the combustion of coal in an 
affected facility subject to paragraph (b)(2) of this section, in J 
(MMBtu); and
H<INF>c</INF> = 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 SO<INF>2</INF> 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 
O<INF>2</INF> (or CO<INF>2</INF>) 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 CO<INF>2</INF>), 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, 
SO<INF>2</INF>, 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


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