[Federal Register: June 13, 2007 (Volume 72, Number 113)]
[Rules and Regulations]
[Page 32709-32768]
[DOCID:fr13jn07-15]

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Part II

Environmental Protection Agency

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40 CFR Part 60

Amendments to New Source Performance Standards (NSPS) for Electric
Utility Steam Generating Units and Industrial-Commercial-Institutional
Steam Generating Units; Final Rule

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ENVIRONMENTAL PROTECTION AGENCY

40 CFR Part 60

[EPA-HQ-OAR-2005-0031; FRL-8302-3]
RIN 2060-AN97

Standards of Performance for Fossil-Fuel-Fired Steam Generators
for Which Construction Is Commenced After August 17, 1971; Standards of
Performance for Electric Utility Steam Generating Units for Which
Construction Is Commenced After September 18, 1978; Standards of
Performance for Industrial-Commercial-Institutional Steam Generating
Units; and Standards of Performance for Small Industrial-Commercial-
Institutional Steam Generating Units

AGENCY: Environmental Protection Agency (EPA).

ACTION: Final reconsideration.

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SUMMARY: EPA is amending the new source performance standards (NSPS)
for electric utility steam generating units and industrial-commercial-
institutional steam generating units. These amendments to the
regulations are to add compliance alternatives for owners and operators
of certain affected sources, revise certain recordkeeping and reporting
requirements, correct technical and editorial errors, and update the
grammatical style of the four subparts to be more consistent across all
of the subparts.

DATES: This rule is effective on June 13, 2007. The incorporation by
reference of certain publications listed in these rules is approved by
the Director of the Federal Register as of June 13, 2007.

ADDRESSES: EPA has established a docket for this action under Docket ID
No. EPA-HQ-OAR-2005-0031. All documents in the docket are listed in the
Federal Docket Management System index at http://www.regulations.gov.

Although listed in the index, some information is not publicly
available, e.g., confidential business information or other information
whose disclosure is restricted by statute. Certain other material, such
as copyrighted material, is not placed on the Internet and will be
publicly available only in hard copy form. Publicly available docket
materials are available either electronically through
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<PHONE_NUMBER>, and the telephone
number for the Air Docket is<PHONE_NUMBER>.

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<PHONE_NUMBER>,
facsimile number<PHONE_NUMBER>, electronic mail (e-mail) address:
<EMAIL_ADDRESS>

SUPPLEMENTARY INFORMATION:
    Outline. The information presented in this preamble is organized as
follows:

I. General Information
    A. Does this action apply to me?
    B. Where can I get a copy of this document?
    C. Judicial Review
II. Background Information
III. Final Amendments and Changes Since Proposal
IV. Statutory and Executive Order Reviews
    A. Executive Order 12866: Regulatory Planning and Review
    B. Paperwork Reduction Act
    C. Regulatory Flexibility Act
    D. Unfunded Mandates Reform Act
    E. Executive Order 13132: Federalism
    F. Executive Order 13175: Consultation and Coordination With
Indian Tribal Governments
    G. Executive Order 13045: Protection of Children From
Environmental Health and Safety Risks
    H. Executive Order 13211: Actions Concerning Regulations That
Significantly Affect Energy Supply, Distribution, or Use
    I. National Technology Transfer Advancement Act
    J. Congressional Review Act

I. General Information

A. Does this action apply to me?

    The regulated categories and entities potentially affected by this
final action include, but are not limited to, the following:

------------------------------------------------------------------------
                                                        Examples of
           Category              NAICS code \1\    potentially regulated
                                                         entities
------------------------------------------------------------------------
Industry......................            221112  Fossil fuel-fired
                                                   electric utility
                                                   steam generating
                                                   units.
Federal Government............             22112  Fossil fuel-fired
                                                   electric utility
                                                   steam generating
                                                   units owned by the
                                                   Federal Government.
State/local/tribal government.             22112  Fossil fuel-fired
                                                   electric utility
                                                   steam generating
                                                   units owned by
                                                   municipalities.
                                          921150  Fossil fuel-fired
                                                   electric steam
                                                   generating units in
                                                   Indian Country.
Any industrial, commercial, or               211  Extractors of crude
 institutional facility using                      petroleum and natural
 a steam generating unit as                        gas.
 defined in 60.40b or 60.40c.
                                             321  Manufacturers of
                                                   lumber and wood
                                                   products.
                                             322  Pulp and paper mills.
                                             325  Chemical
                                                   manufacturers.
                                             324  Petroleum refiners and
                                                   manufacturers of coal
                                                   products.
                                   316, 326, 339  Manufacturers of
                                                   rubber and
                                                   miscellaneous plastic
                                                   products.
                                             331  Steel works, blast
                                                   furnaces.
                                             332  Electroplating,
                                                   plating, polishing,
                                                   anodizing, and
                                                   coloring.
                                             336  Manufacturers of motor
                                                   vehicle parts and
                                                   accessories.
                                             221  Electric, gas, and
                                                   sanitary services.
                                             622  Health services.
                                             611  Educational Services.
------------------------------------------------------------------------
\1\ North American Industry Classification System (NAICS) code.

This table is not intended to be exhaustive, but rather provides a
guide for readers regarding entities likely to be regulated by this
action. To determine whether your facility is regulated by this action,
you should examine the applicability criteria in Sec.  60.40a, 60.40b,
or 60.40c of 40 CFR part 60. If you have any questions regarding the
applicability of this action to a particular entity, consult either the
air permit authority for the entity or your

EPA regional representative as listed in 40 CFR 63.13 of subpart A
(General Provisions).

B. Where can I get a copy of this document?

    In addition to being available in the docket, an electronic copy of
this final action will also be available on the Worldwide Web (WWW)
through the Technology Transfer Network (TTN). Following signature, a
copy of this final action will be posted on the TTN's policy and
guidance page for newly proposed or promulgated rules at the following
address: http://www.epa.gov/ttn/oarpg/. The TTN provides information

and technology exchange in various areas of air pollution control.

C. Judicial Review

    Under section 307(b)(1) of the Clean Air Act (CAA), judicial review
of these final rules is available only by filing a petition for review
in the U.S. Court of Appeals for the District of Columbia Circuit by
August 13, 2007. Under section 307(d)(7)(B) of the CAA, only an
objection to these final rules that was raised with reasonable
specificity during the period for public comment can be raised during
judicial review. Moreover, under section 307(b)(2) of the CAA, the
requirements established by these final rules may not be challenged
separately in any civil or criminal proceedings brought by EPA to
enforce these requirements.

II. Background Information

    In response to petitions for reconsideration filed by the Utility
Air Regulatory Group and the Council of Industrial Boiler Owners of the
amendments to the new source performance standards for steam generating
units that EPA promulgated on February 27, 2006 (71 FR 9866), EPA
proposed revised amendments to address issues for which the petitioners
requested reconsideration (see docket entries EPA-HQ-OAR-2005-0031-0224
and EPA-HQ-OAR-2005-0031-0225). EPA proposed on February 9, 2007, (72
FR 6320) to amend 40 CFR part 60, subparts D, Da, Db, and Dc to clarify
the intent for applying and implementing specific rule requirements,
provide additional compliance alternatives, and to correct
unintentional technical omissions and editorial errors. In addition,
EPA proposed to republish 40 CFR 60.17 (Incorporations by reference)
and subparts D, Da, Db, and Dc in their entirety for the purpose of
revising the wording and writing style to be more consistent across all
the NSPS subparts applicable to steam generating units.
    A 30-day comment period (February 9, 2007 to March 12, 2007) was
provided to accept comments on the proposed rule. An opportunity for a
public hearing was provided to allow any interested persons to present
oral comments on the proposed rule. However, EPA did not receive a
request for a formal public hearing, so a public hearing was not held.
EPA did receive a request for a 15-day extension to the comment period.
EPA granted an extension of the public comment period to March 26, 2007
(72 FR 9903, March 6, 2007). We received comments on the proposed
amendments from 20 commenters during the comment period.

III. Final Amendments and Changes Since Proposal

    We are amending 40 CFR part 60, subparts D, Da, Db, and Dc to add
compliance alternatives for owners and operators of certain affected
sources, revise certain recordkeeping and reporting requirements,
correct technical and editorial errors, and update the grammatical
style of the four subparts to be more consistent across all of the
subparts. This action promulgates the proposed regulatory language for
the amendments except for those significant provisions, as noted below,
for which modifications were made to the regulatory language for the
final amendments in response to specific public comments. EPA did not
receive negative comments on the conforming changes to the regulatory
text and is, therefore, finalizing all those changes.
    The final amendments promulgated by this action reflect EPA's
consideration of the comments received on the proposal. EPA's responses
to the substantive public comments on the proposal are presented in a
comment summary and response document available in Docket ID No. EPA-
HQ-OAR-2005-0031.
    The requirements in subpart Da for demonstrating continuous
compliance with the particulate matter (PM) emission limits for
affected electric utility steam generating units that commence
construction, reconstruction, or modification after February 28, 2005,
have been revised since proposal in response to comments. EPA is
retaining the provision, established in the February 27, 2006 final
rule, allowing the optional use of PM continuous emission monitoring
systems (CEMS) to steam generating units for demonstration of
compliance with rule requirements related to controlling PM emissions.
Owners and operators choosing to install and properly operate PM CEMS
must demonstrate compliance with the applicable PM emission limit on a
daily basis and are not required to install a continuous opacity
monitoring system (COMS) or to monitor PM control device performance.
    We recognize that experience using PM CEMS at electric utility
power plants in the United States is limited, and not all affected
owners and operators will choose to use PM CEMS. Therefore, the final
amendments allow owners and operators of affected electric utility
steam generating units constructed, reconstructed, or modified after
February 28, 2005, to demonstrate compliance with the PM emissions
limit using periodic PM emissions performance testing and continuous
monitoring of the PM control device performance using one of two
alternatives. The first monitoring alternative is for an owner or
operator of an affected source to monitor PM control device performance
based on the opacity level measured during the stack performance test
conducted to demonstrate compliance with the applicable PM emissions
limit. The second alternative available to owners and operators depends
on the type of PM control device used for the electric utility steam
generating unit. The owner or operator of an affected source that uses
an electrostatic precipitator (ESP) can elect to monitor performance of
the control device using an ESP predictive emissions model. An owner or
operator of an affected source that uses a fabric filter can elect to
monitor control device performance using a bag leak detection system.
One significant change from the proposal is that owners or operators of
affected source that use parametric monitoring of PM emissions will
have a grace period to bring the monitoring parameters back into the
range established during the most recent PM emissions performance test
prior to the requirement to conduct a new PM emissions performance
test. The grace period does not apply to the 6-minute opacity standard
and owners and operators of affected sources must continue to report
excess 6-minute opacity measurements.
    EPA has finalized several other alternatives to provide owners and
operators of affected electric utility steam generating units
additional flexibility in complying with the NSPS. EPA has finalized
the optional use of Part 75 NOX and SO2 CEMS
calibration procedures to satisfy Part 60 requirements as proposed, the
amendments to Sec.  60.13 providing a standard methodology for
validating partial operating hours, and the amendments to Appendix B of
Part 60 allowing the calibration drift test be

conducted over 7 consecutive operating days instead of 7 consecutive
calendar days and the relative accuracy test audit flexibility (as
described in docket entry EPA-HQ-OAR-2005-0031-0234). In addition, EPA
has finalized the option for steam generating units subject to subpart
D allowing affected owners and operators to choose as an alternative to
complying with the applicable NOX and SO2
emission limits in the rule to comply with the 30-day average
NOX and SO2 standards for modified sources in
subparts Da and Db, as applicable to the affected source.
    For industrial/commercial/institutional steam generating units
subject to subpart Db and burning coke oven gas (COG), we have expanded
the applicability of the 30-day annual exemption from the
SO2 emissions limit to all units subject to subpart Db that
burn COG. The amendments to subpart Db promulgated in February 27,
2006, added this flexibility for those steam generating units
constructed, reconstructed, or modified after February 28, 2005, to
account for byproduct plant maintenance. Based on comments we received,
the amendments promulgated by this action provide the same compliance
flexibility to the owner or operator of any COG-fired steam generating
unit subject to subpart Db.
    The final amendments add to subparts D, Da, Db, and Dc monitoring
alternatives to existing requirements to use COMS for owners and
operators of steam generating units burning gaseous fuels or low sulfur
fuel oils. Owners and operators of electric utility steam generating
units subject to subpart D or Da may elect to use a carbon monoxide
(CO) CEMS in place of the COMS. Owners and operators of industrial/
commercial/institutional steam generating units subject to subpart Db
or Dc may elect to either use a CO CEMS or to operate according to a
site-specific monitoring plan in place of using a COMS.
    Finally, minor revisions to the proposed regulatory language were
made to clarify specific provisions or to correct unintentional
technical omissions and terminology, typographical, printing, and
grammatical errors that were identified in the proposed rule. These
changes include revising appropriate definitions and requirements in
subpart Da to clarify the applicability and implementation of the
subpart Da provisions to integrated coal gasification combined cycle
electric utility power plants.

IV. Statutory and Executive Order Reviews

A. Executive Order 12866: Regulatory Planning and Review

    This action is not a ``significant regulatory action'' under the
terms of Executive Order 12866 (58 FR 51735, October 4, 1993) and is,
therefore, not subject to review under the Executive Order. EPA has
concluded that the amendments EPA is promulgating will not change the
costs or benefits of the rule.

B. Paperwork Reduction Act

     This action does not impose any new information collection burden
under the provisions of the Paperwork Reduction Act, 44 U.S.C. 3501 et
seq. The final amendments result in no changes to the information
collection requirements of the existing standards of performance and
would have no impact on the information collection estimate of
projected cost and hour burden made and approved by the Office of
Management and Budget (OMB) during the development of the existing
standards of performance. Therefore, the information collection
requests have not been amended. OMB has previously approved the
information collection requirements contained in the existing standards
of performance (40 CFR part 60, subparts D, Da, Db, and Dc) under the
provisions of the Paperwork Reduction Act, 44 U.S.C. 3501 et seq., at
the time the standards were promulgated on June 11, 1979 (40 CFR part
60, subpart Da, 44 FR 33580), November 25, 1986 (40 CFR part 60,
subpart Db, 51 FR 42768), and September 12, 1990 (40 CFR part 60,
subpart Dc, 55 FR 37674). OMB assigned OMB control numbers 2060-0023
(ICR 1053.08) for 40 CFR part 60, subpart Da; 2060-0072 (ICR 1088.11)
for 40 CFR part 60, subpart Db; 2060-0202 (ICR 1564.06) for 40 CFR part
60, subpart Dc. Copies of the information collection request
document(s) may be obtained from Susan Auby, Collection Strategies
Division, U.S. EPA (2822T), 1200 Pennsylvania Ave., NW., Washington, DC
20460, by e-mail at<EMAIL_ADDRESS>or by calling<PHONE_NUMBER>.
    Burden means the total time, effort, or financial resources
expended by persons to generate, maintain, retain, or disclose or
provide information to or for a Federal agency. This includes the time
needed to review instructions; develop, acquire, install, and utilize
technology and systems for the purposes of collecting, validating, and
verifying information, processing and maintaining information, and
disclosing and providing information; adjust the existing ways to
comply with any previously applicable instructions and requirements;
train personnel to be able to respond to a collection of information;
search data sources; complete and review the collection of information;
and transmit or otherwise disclose the information.
    An agency may not conduct or sponsor, and a person is not required
to respond to a collection of information unless it displays a
currently valid OMB control number. OMB control numbers for EPA's
regulations in 40 CFR are listed in 40 CFR part 9.

C. Regulatory Flexibility Act

    The Regulatory Flexibility Act generally requires an agency to
prepare a regulatory flexibility analysis of any rule subject to notice
and comment rulemaking requirements under the Administrative Procedure
Act or any other statute unless the agency certifies that the rule will
not have a significant economic impact on a substantial number of small
entities. Small entities include small businesses, small organizations,
and small governmental jurisdictions.
    For purposes of assessing the impacts of the final amendments on
small entities, small entity is defined as: (1) A small business as
defined by the Small Business Administration's regulations at 13 CFR
121.201; (2) a small governmental jurisdiction that is a government of
a city, county, town, school district or special district with a
population of less than 50,000; and (3) a small organization that is
any not-for-profit enterprise which is independently owned and operated
and is not dominant in its field.
    After considering the economic impacts of this final rule on small
entities, I certify that this action will not have a significant
economic impact on a substantial number of small entities.
    Although this action will not have a significant economic impact on
a substantial number of small entities, EPA nonetheless has tried to
reduce the impact of this rule on small entities. EPA is reducing the
fuel usage recordkeeping requirement for subpart Dc facilities. In
addition, EPA is minimizing the continuous opacity monitoring
requirements for certain oil-fired facilities. EPA has, therefore,
concluded that this action will relieve regulatory burden for the
majority of affected small entities. EPA continues to be interested in
the potential impacts of the rule on small entities and welcomes
comments on issues related to such impacts.

D. Unfunded Mandates Reform Act

    Title II of the Unfunded Mandates Reform Act of 1995 (UMRA), Public
Law 104-4, establishes requirements for Federal agencies to assess the
effects of their regulatory actions on State, local, and tribal
governments and the private sector. Under section 202 of the UMRA, EPA
generally must prepare a written statement, including a cost-benefit
analysis, for proposed and final rules with ``Federal mandates'' that
may result in expenditures to State, local, and tribal governments, in
the aggregate, or to the private sector, of $100 million or more in any
one year. Before promulgating an EPA rule for which a written statement
is needed, section 205 of the UMRA generally requires EPA to identify
and consider a reasonable number of regulatory alternatives and adopt
the least costly, most cost-effective or least burdensome alternative
that achieves the objectives of the rule. The provisions of section 205
do not apply when they are inconsistent with applicable law. Moreover,
section 205 allows EPA to adopt an alternative other than the least
costly, most cost-effective or least burdensome alternative if the
Administrator publishes with the final rule an explanation why that
alternative was not adopted. Before EPA establishes any regulatory
requirements that may significantly or uniquely affect small
governments, including tribal governments, it must have developed under
section 203 of the UMRA a small government agency plan. The plan must
provide for notifying potentially affected small governments, enabling
officials of affected small governments to have meaningful and timely
input in the development of EPA regulatory proposals with significant
Federal intergovernmental mandates, and informing, educating, and
advising small governments on compliance with the regulatory
requirements.
    EPA has determined that the final amendments will contain no
Federal mandates that may result in expenditures of $100 million or
more for State, local, and tribal governments, in the aggregate, or the
private sector in any 1 year. Thus, the final amendments are not
subject to the requirements of section 202 and 205 of the UMRA. In
addition, EPA has determined that the final amendments contain no
regulatory requirements that might significantly or uniquely affect
small governments because the burden is small and the regulation does
not unfairly apply to small governments. Therefore, the final
amendments are not subject to the requirements of section 203 of the
UMRA.

E. Executive Order 13132: Federalism

    Executive Order 13132, entitled ``Federalism'' (64 FR 43255, August
10, 1999), requires EPA to develop an accountable process to ensure
``meaningful and timely input by State and local officials in the
development of regulatory policies that have federalism implications.''
``Policies that have federalism implications'' is defined in the
Executive Order to include regulations that have ``substantial direct
effects on the States, on the relationship between the national
government and the States, or on the distribution of power and
responsibilities among the various levels of government.''
    The final amendments do not have federalism implications. They will
not have substantial direct effects on the States, on the relationship
between the national government and the States, or on the distribution
of power and responsibilities among the various levels of government,
as specified in Executive Order 13132. The final amendments will not
impose substantial direct compliance costs on State or local
governments; it will not preempt State law. Thus, Executive Order 13132
does not apply to the final amendments.

F. Executive Order 13175: Consultation and Coordination With Indian
Tribal Governments

    Executive Order 13175, entitled ``Consultation and Coordination
with Indian Tribal Governments'' (65 FR 67249, November 9, 2000),
requires EPA to develop an accountable process to ensure ``meaningful
and timely input by tribal officials in the development of regulatory
policies that have tribal implications.'' The final amendments do not
have tribal implications, as specified in Executive Order 13175. While
utility steam generating units are located on tribal lands EPA is not
aware of any that are tribally owned. To the extend that institutional
steam generating units are tribally owned the final amendments will not
have substantial direct effects on tribal governments, on the
relationship between the Federal government and Indian tribes, or on
the distribution of power and responsibilities between the Federal
government and Indian tribes. Thus, Executive Order 13175 does not
apply to the final amendments.

G. Executive Order 13045: Protection of Children From Environmental
Health and Safety Risks

    Executive Order 13045 (62 FR 19885, April 23, 1997) applies to any
rule that: (1) Is determined to be ``economically significant'' as
defined under Executive Order 12866, and (2) concerns an environmental
health or safety risk that EPA has reason to believe may have a
disproportionate effect on children. If the regulatory action meets
both criteria, the Agency must evaluate the environmental health or
safety effects of the planned rule on children, and explain why the
planned regulation is preferable to other potentially effective and
reasonably feasible alternatives considered by the Agency.
    This action is not subject to the Executive Order because it is not
economically significant as defined under Executive Order 12866, and
because EPA interprets Executive Order 13045 as applying only to those
regulatory actions that are based on health or safety risks, such that
the analysis required under section 5-501 of the Order has the
potential to influence the regulation. The final amendments are based
on technology performance and not on health or safety risks and,
therefore, are not subject to Executive Order 13045.

H. Executive Order 13211: Actions Concerning Regulations That
Significantly Affect Energy Supply, Distribution, or Use

    The final amendments are not a ``significant energy action'': As
defined in Executive Order 13211, ``Actions Concerning Regulations That
Significantly Affect Energy Supply, Distribution, or Use'' (66 FR
28355, May 22, 2001) because it is not likely to have a significant
adverse effect on the supply, distribution, or use of energy because it
only clarifies our intent and corrects errors in the existing rule.
Further, we have concluded that the final amendments are not likely to
have any adverse energy effects.

I. National Technology Transfer Advancement Act

    Section 12(d) of the National Technology Transfer and Advancement
Act of 1995 (NTTAA), Public Law 104-113, Section 12(d)(15 U.S.C. 272
note) directs us to use voluntary consensus standards in our regulatory
activities unless to do so would be inconsistent with applicable law or
otherwise impractical. Voluntary consensus standards are technical
standards (e.g., material specifications, test methods, sampling
procedures, business practices) developed or adopted by one or more
voluntary consensus bodies. The NTTAA directs us to provide Congress,
through OMB, explanations when we decide not use available and
applicable voluntary consensus standards.

    This action does not involve any new technical standards or the
incorporation by reference of existing technical standards. Therefore,
the consideration of voluntary consensus standards is not relevant to
this action.

J. Congressional Review Act

    The Congressional Review Act, 5 U.S.C. 801, et seq., as added by
the Small Business Regulatory Enforcement Fairness Act of 1996,
generally provides that before a rule may take effect, the agency
promulgating the rule must submit a rule report, which includes a copy
of the rule, to each House of Congress and to the Comptroller General
of the United States. EPA will submit a report containing these final
amendments and other required information to the U.S. Senate, the U.S.
House of Representatives, and the Comptroller General of the United
States prior to publication of the final rules in the Federal Register.
A major rule cannot take effect until 60 days after it is published in
the Federal Register. This action is not a ``major rule'' as defined by
5 U.S.C. 804(2). These final amendments will be effective on June 13,
2007.

List of Subjects in 40 CFR Part 60

    Environmental protection, Administrative practice and procedure,
Air pollution control, Incorporation by reference, Intergovernmental
relations, Reporting and recordkeeping requirements.

    Dated: April 13, 2007.
Stephen L. Johnson,
Administrator.

0
For the reasons stated in the preamble, title 40, chapter I, part 60,
of the Code of the Federal Regulations is amended as follows:

PART 60--[AMENDED]

0
1. The authority citation for part 60 continues to read as follows:

    Authority: 42 U.S.C. 7401, et seq.

Subpart A--[Amended]

0
2. Section 60.13 is amended by revising paragraph (h) to read as
follows:

Sec.  60.13  Monitoring requirements.

* * * * *
    (h)(1) Owners or operators of all continuous monitoring systems for
measurement of opacity shall reduce all data to 6-minute averages and
for continuous monitoring systems other than opacity to 1-hour averages
for time periods as defined in Sec.  60.2. Six-minute opacity averages
shall be calculated from 36 or more data points equally spaced over
each 6-minute period.
    (2) For continuous monitoring systems other than opacity, 1-hour
averages shall be computed as follows, except that the provisions
pertaining to the validation of partial operating hours are only
applicable for affected facilities that are required by the applicable
subpart to include partial hours in the emission calculations:
    (i) Except as provided under paragraph (h)(2)(iii) of this section,
for a full operating hour (any clock hour with 60 minutes of unit
operation), at least four valid data points are required to calculate
the hourly average, i.e., one data point in each of the 15-minute
quadrants of the hour.
    (ii) Except as provided under paragraph (h)(2)(iii) of this
section, for a partial operating hour (any clock hour with less than 60
minutes of unit operation), at least one valid data point in each 15-
minute quadrant of the hour in which the unit operates is required to
calculate the hourly average.
    (iii) For any operating hour in which required maintenance or
quality-assurance activities are performed:
    (A) If the unit operates in two or more quadrants of the hour, a
minimum of two valid data points, separated by at least 15 minutes, is
required to calculate the hourly average; or
    (B) If the unit operates in only one quadrant of the hour, at least
one valid data point is required to calculate the hourly average.
    (iv) If a daily calibration error check is failed during any
operating hour, all data for that hour shall be invalidated, unless a
subsequent calibration error test is passed in the same hour and the
requirements of paragraph (h)(2)(iii) of this section are met, based
solely on valid data recorded after the successful calibration.
    (v) For each full or partial operating hour, all valid data points
shall be used to calculate the hourly average.
    (vi) Except as provided under paragraph (h)(2)(vii) of this
section, data recorded during periods of continuous monitoring system
breakdown, repair, calibration checks, and zero and span adjustments
shall not be included in the data averages computed under this
paragraph.
    (vii) Owners and operators complying with the requirements of Sec.
60.7(f)(1) or (2) must include any data recorded during periods of
monitor breakdown or malfunction in the data averages.
    (viii) When specified in an applicable subpart, hourly averages for
certain partial operating hours shall not be computed or included in
the emission averages (e.g. hours with <  30 minutes of unit operation
under Sec.  60.47b(d)).
    (ix) Either arithmetic or integrated averaging of all data may be
used to calculate the hourly averages. The data may be recorded in
reduced or nonreduced form (e.g., ppm pollutant and percent
O2 or ng/J of pollutant).
    (3) All excess emissions shall be converted into units of the
standard using the applicable conversion procedures specified in the
applicable subpart. After conversion into units of the standard, the
data may be rounded to the same number of significant digits used in
the applicable subpart to specify the emission limit.
* * * * *

Sec.  60.17  [Amended]

0
3. Section 60.17 is amended by revising paragraphs (a) and (h)(2) to
read as follows:
* * * * *
    (a) The following materials are available for purchase from at
least one of the following addresses: American Society for Testing and
Materials (ASTM), 100 Barr Harbor Drive, Post Office Box C700, West
Conshohocken, PA 19428-2959; or ProQuest, 300 North Zeeb Road, Ann
Arbor, MI 48106.
    (1) ASTM A99-76, 82 (Reapproved 1987), Standard Specification for
Ferromanganese, incorporation by reference (IBR) approved for Sec.
60.261.
    (2) ASTM A100-69, 74, 93, Standard Specification for Ferrosilicon,
IBR approved for Sec.  60.261.
    (3) ASTM A101-73, 93, Standard Specification for Ferrochromium, IBR
approved for Sec.  60.261.
    (4) ASTM A482-76, 93, Standard Specification for
Ferrochromesilicon, IBR approved for Sec.  60.261.
    (5) ASTM A483-64, 74 (Reapproved 1988), Standard Specification for
Silicomanganese, IBR approved for Sec.  60.261.
    (6) ASTM A495-76, 94, Standard Specification for Calcium-Silicon
and Calcium Manganese-Silicon, IBR approved for Sec.  60.261.
    (7) ASTM D86-78, 82, 90, 93, 95, 96, Distillation of Petroleum
Products, IBR approved for Sec. Sec.  60.562-2(d), 60.593(d), and
60.633(h).
    (8) ASTM D129-64, 78, 95, 00, Standard Test Method for Sulfur in
Petroleum Products (General Bomb Method), IBR approved for Sec. Sec.
60.106(j)(2), 60.335(b)(10)(i), and Appendix A: Method 19, <IP_ADDRESS>.3.
    (9) ASTM D129-00 (Reapproved 2005), Standard Test Method for Sulfur
in Petroleum Products (General Bomb Method), IBR approved for Sec.
60.4415(a)(1)(i).

    (10) ASTM D240-76, 92, Standard Test Method for Heat of Combustion
of Liquid Hydrocarbon Fuels by Bomb Calorimeter, IBR approved for
Sec. Sec.  60.46(c), 60.296(b), and Appendix A: Method 19, Section
<IP_ADDRESS>.3.
    (11) ASTM D270-65, 75, Standard Method of Sampling Petroleum and
Petroleum Products, IBR approved for Appendix A: Method 19, Section
<IP_ADDRESS>.1.
    (12) ASTM D323-82, 94, Test Method for Vapor Pressure of Petroleum
Products (Reid Method), IBR approved for Sec. Sec.  60.111(l),
60.111a(g), 60.111b(g), and 60.116b(f)(2)(ii).
    (13) ASTM D388-77, 90, 91, 95, 98a, 99 (Reapproved 2004) [egr]\1\,
Standard Specification for Classification of Coals by Rank, IBR
approved for Sec. Sec.  60.24(h)(8), 60.41 of subpart D of this part,
60.45(f)(4)(i), 60.45(f)(4)(ii), 60.45(f)(4)(vi), 60.41Da of subpart Da
of this part, 60.41b of subpart Db of this part, 60.41c of subpart Dc
of this part, and 60.4102.
    (14) ASTM D388-77, 90, 91, 95, 98a, Standard Specification for
Classification of Coals by Rank, IBR approved for Sec. Sec.  60.251(b)
and (c) of subpart Y of this part.
    (15) ASTM D396-78, 89, 90, 92, 96, 98, Standard Specification for
Fuel Oils, IBR approved for Sec. Sec.  60.41b of subpart Db of this
part, 60.41c of subpart Dc of this part, 60.111(b) of subpart K of this
part, and 60.111a(b) of subpart Ka of this part.
    (16) ASTM D975-78, 96, 98a, Standard Specification for Diesel Fuel
Oils, IBR approved for Sec. Sec.  60.111(b) of subpart K of this part
and 60.111a(b) of subpart Ka of this part.
    (17) ASTM D1072-80, 90 (Reapproved 1994), Standard Test Method for
Total Sulfur in Fuel Gases, IBR approved for Sec.  60.335(b)(10)(ii).
    (18) ASTM D1072-90 (Reapproved 1999), Standard Test Method for
Total Sulfur in Fuel Gases, IBR approved for Sec.  60.4415(a)(1)(ii).
    (19) ASTM D1137-53, 75, Standard Method for Analysis of Natural
Gases and Related Types of Gaseous Mixtures by the Mass Spectrometer,
IBR approved for Sec.  60.45(f)(5)(i).
    (20) ASTM D1193-77, 91, Standard Specification for Reagent Water,
IBR approved for Appendix A: Method 5, Section 7.1.3; Method 5E,
Section 7.2.1; Method 5F, Section 7.2.1; Method 6, Section 7.1.1;
Method 7, Section 7.1.1; Method 7C, Section 7.1.1; Method 7D, Section
7.1.1; Method 10A, Section 7.1.1; Method 11, Section 7.1.3; Method 12,
Section 7.1.3; Method 13A, Section 7.1.2; Method 26, Section 7.1.2;
Method 26A, Section 7.1.2; and Method 29, Section 7.2.2.
    (21) ASTM D1266-87, 91, 98, Standard Test Method for Sulfur in
Petroleum Products (Lamp Method), IBR approved for Sec. Sec.
60.106(j)(2) and 60.335(b)(10)(i).
    (22) ASTM D1266-98 (Reapproved 2003)e1, Standard Test Method for
Sulfur in Petroleum Products (Lamp Method), IBR approved for Sec.
60.4415(a)(1)(i).
    (23) ASTM D1475-60 (Reapproved 1980), 90, Standard Test Method for
Density of Paint, Varnish Lacquer, and Related Products, IBR approved
for Sec.  60.435(d)(1), Appendix A: Method 24, Section 6.1; and Method
24A, Sections 6.5 and 7.1.
    (24) ASTM D1552-83, 95, 01, Standard Test Method for Sulfur in
Petroleum Products (High-Temperature Method), IBR approved for
Sec. Sec.  60.106(j)(2), 60.335(b)(10)(i), and Appendix A: Method 19,
Section <IP_ADDRESS>.3.
    (25) ASTM D1552-03, Standard Test Method for Sulfur in Petroleum
Products (High-Temperature Method), IBR approved for Sec.
60.4415(a)(1)(i).
    (26) ASTM D1826-77, 94, Standard Test Method for Calorific Value of
Gases in Natural Gas Range by Continuous Recording Calorimeter, IBR
approved for Sec. Sec.  60.45(f)(5)(ii), 60.46(c)(2), 60.296(b)(3), and
Appendix A: Method 19, Section <IP_ADDRESS>.
    (27) ASTM D1835-87, 91, 97, 03a, Standard Specification for
Liquefied Petroleum (LP) Gases, IBR approved for Sec. Sec.  60.41Da of
subpart Da of this part, 60.41b of subpart Db of this part, and 60.41c
of subpart Dc of this part.
    (28) ASTM D1945-64, 76, 91, 96, Standard Method for Analysis of
Natural Gas by Gas Chromatography, IBR approved for Sec.
60.45(f)(5)(i).
    (29) ASTM D1946-77, 90 (Reapproved 1994), Standard Method for
Analysis of Reformed Gas by Gas Chromatography, IBR approved for
Sec. Sec.  60.18(f)(3), 60.45(f)(5)(i), 60.564(f)(1), 60.614(e)(2)(ii),
60.614(e)(4), 60.664(e)(2)(ii), 60.664(e)(4), 60.704(d)(2)(ii), and
60.704(d)(4).
    (30) ASTM D2013-72, 86, Standard Method of Preparing Coal Samples
for Analysis, IBR approved for Appendix A: Method 19, Section
<IP_ADDRESS>.3.
    (31) ASTM D2015-77 (Reapproved 1978), 96, Standard Test Method for
Gross Calorific Value of Solid Fuel by the Adiabatic Bomb Calorimeter,
IBR approved for Sec.  60.45(f)(5)(ii), 60.46(c)(2), and Appendix A:
Method 19, Section <IP_ADDRESS>.3.
    (32) ASTM D2016-74, 83, Standard Test Methods for Moisture Content
of Wood, IBR approved for Appendix A: Method 28, Section 16.1.1.
    (33) ASTM D2234-76, 96, 97b, 98, Standard Methods for Collection of
a Gross Sample of Coal, IBR approved for Appendix A: Method 19, Section
<IP_ADDRESS>.1.
    (34) ASTM D2369-81, 87, 90, 92, 93, 95, Standard Test Method for
Volatile Content of Coatings, IBR approved for Appendix A: Method 24,
Section 6.2.
    (35) ASTM D2382-76, 88, Heat of Combustion of Hydrocarbon Fuels by
Bomb Calorimeter (High-Precision Method), IBR approved for Sec. Sec.
60.18(f)(3), 60.485(g)(6), 60.564(f)(3), 60.614(e)(4), 60.664(e)(4),
and 60.704(d)(4).
    (36) ASTM D2504-67, 77, 88 (Reapproved 1993), Noncondensable Gases
in C3 and Lighter Hydrocarbon Products by Gas Chromatography, IBR
approved for Sec.  60.485(g)(5).
    (37) ASTM D2584-68 (Reapproved 1985), 94, Standard Test Method for
Ignition Loss of Cured Reinforced Resins, IBR approved for Sec.
60.685(c)(3)(i).
    (38) ASTM D2597-94 (Reapproved 1999), Standard Test Method for
Analysis of Demethanized Hydrocarbon Liquid Mixtures Containing
Nitrogen and Carbon Dioxide by Gas Chromatography, IBR approved for
Sec.  60.335(b)(9)(i).
    (39) ASTM D2622-87, 94, 98, Standard Test Method for Sulfur in
Petroleum Products by Wavelength Dispersive X-Ray Fluorescence
Spectrometry, IBR approved for Sec. Sec.  60.106(j)(2) and
60.335(b)(10)(i).
    (40) ASTM D2622-05, Standard Test Method for Sulfur in Petroleum
Products by Wavelength Dispersive X-Ray Fluorescence Spectrometry, IBR
approved for Sec.  60.4415(a)(1)(i).
    (41) ASTM D2879-83, 96, 97, Test Method for Vapor Pressure-
Temperature Relationship and Initial Decomposition Temperature of
Liquids by Isoteniscope, IBR approved for Sec. Sec.  60.111b(f)(3),
60.116b(e)(3)(ii), 60.116b(f)(2)(i), and 60.485(e)(1).
    (42) ASTM D2880-78, 96, Standard Specification for Gas Turbine Fuel
Oils, IBR approved for Sec. Sec.  60.111(b), 60.111a(b), and 60.335(d).
    (43) ASTM D2908-74, 91, Standard Practice for Measuring Volatile
Organic Matter in Water by Aqueous-Injection Gas Chromatography, IBR
approved for Sec.  60.564(j).
    (44) ASTM D2986-71, 78, 95a, Standard Method for Evaluation of Air,
Assay Media by the Monodisperse DOP (Dioctyl Phthalate) Smoke Test, IBR
approved for Appendix A: Method 5, Section 7.1.1; Method 12, Section
7.1.1; and Method 13A, Section <IP_ADDRESS>.
    (45) ASTM D3173-73, 87, Standard Test Method for Moisture in the

Analysis Sample of Coal and Coke, IBR approved for Appendix A: Method
19, Section <IP_ADDRESS>.3.
    (46) ASTM D3176-74, 89, Standard Method for Ultimate Analysis of
Coal and Coke, IBR approved for Sec.  60.45(f)(5)(i) and Appendix A:
Method 19, Section <IP_ADDRESS>.
    (47) ASTM D3177-75, 89, Standard Test Method for Total Sulfur in
the Analysis Sample of Coal and Coke, IBR approved for Appendix A:
Method 19, Section <IP_ADDRESS>.3.
    (48) ASTM D3178-73 (Reapproved 1979), 89, Standard Test Methods for
Carbon and Hydrogen in the Analysis Sample of Coal and Coke, IBR
approved for Sec.  60.45(f)(5)(i).
    (49) ASTM D3246-81, 92, 96, Standard Test Method for Sulfur in
Petroleum Gas by Oxidative Microcoulometry, IBR approved for Sec.
60.335(b)(10)(ii).
    (50) ASTM D3246-05, Standard Test Method for Sulfur in Petroleum
Gas by Oxidative Microcoulometry, IBR approved for Sec.
60.4415(a)(1)(ii).
    (51) ASTM D3270-73T, 80, 91, 95, Standard Test Methods for Analysis
for Fluoride Content of the Atmosphere and Plant Tissues (Semiautomated
Method), IBR approved for Appendix A: Method 13A, Section 16.1.
    (52) ASTM D3286-85, 96, Standard Test Method for Gross Calorific
Value of Coal and Coke by the Isoperibol Bomb Calorimeter, IBR approved
for Appendix A: Method 19, Section <IP_ADDRESS>.3.
    (53) ASTM D3370-76, 95a, Standard Practices for Sampling Water, IBR
approved for Sec.  60.564(j).
    (54) ASTM D3792-79, 91, Standard Test Method for Water Content of
Water-Reducible Paints by Direct Injection into a Gas Chromatograph,
IBR approved for Appendix A: Method 24, Section 6.3.
    (55) ASTM D4017-81, 90, 96a, Standard Test Method for Water in
Paints and Paint Materials by the Karl Fischer Titration Method, IBR
approved for Appendix A: Method 24, Section 6.4.
    (56) ASTM D4057-81, 95, Standard Practice for Manual Sampling of
Petroleum and Petroleum Products, IBR approved for Appendix A: Method
19, Section <IP_ADDRESS>.3.
    (57) ASTM D4057-95 (Reapproved 2000), Standard Practice for Manual
Sampling of Petroleum and Petroleum Products, IBR approved for Sec.
60.4415(a)(1).
    (58) ASTM D4084-82, 94, Standard Test Method for Analysis of
Hydrogen Sulfide in Gaseous Fuels (Lead Acetate Reaction Rate Method),
IBR approved for Sec.  60.334(h)(1).
    (59) ASTM D4084-05, Standard Test Method for Analysis of Hydrogen
Sulfide in Gaseous Fuels (Lead Acetate Reaction Rate Method), IBR
approved for Sec. Sec.  60.4360 and 60.4415(a)(1)(ii).
    (60) ASTM D4177-95, Standard Practice for Automatic Sampling of
Petroleum and Petroleum Products, IBR approved for Appendix A: Method
19, Section <IP_ADDRESS>.1.
    (61) ASTM D4177-95 (Reapproved 2000), Standard Practice for
Automatic Sampling of Petroleum and Petroleum Products, IBR approved
for Sec.  60.4415(a)(1).
    (62) ASTM D4239-85, 94, 97, Standard Test Methods for Sulfur in the
Analysis Sample of Coal and Coke Using High Temperature Tube Furnace
Combustion Methods, IBR approved for Appendix A: Method 19, Section
<IP_ADDRESS>.3.
    (63) ASTM D4294-02, Standard Test Method for Sulfur in Petroleum
and Petroleum Products by Energy-Dispersive X-Ray Fluorescence
Spectrometry, IBR approved for Sec.  60.335(b)(10)(i).
    (64) ASTM D4294-03, Standard Test Method for Sulfur in Petroleum
and Petroleum Products by Energy-Dispersive X-Ray Fluorescence
Spectrometry, IBR approved for Sec.  60.4415(a)(1)(i).
    (65) ASTM D4442-84, 92, Standard Test Methods for Direct Moisture
Content Measurement in Wood and Wood-base Materials, IBR approved for
Appendix A: Method 28, Section 16.1.1.
    (66) ASTM D4444-92, Standard Test Methods for Use and Calibration
of Hand-Held Moisture Meters, IBR approved for Appendix A: Method 28,
Section 16.1.1.
    (67) ASTM D4457-85 (Reapproved 1991), Test Method for Determination
of Dichloromethane and 1, 1, 1-Trichloroethane in Paints and Coatings
by Direct Injection into a Gas Chromatograph, IBR approved for Appendix
A: Method 24, Section 6.5.
    (68) ASTM D4468-85 (Reapproved 2000), Standard Test Method for
Total Sulfur in Gaseous Fuels by Hydrogenolysis and Rateometric
Colorimetry, IBR approved for Sec. Sec.  60.335(b)(10)(ii) and
60.4415(a)(1)(ii).
    (69) ASTM D4629-02, Standard Test Method for Trace Nitrogen in
Liquid Petroleum Hydrocarbons by Syringe/Inlet Oxidative Combustion and
Chemiluminescence Detection, IBR approved for Sec. Sec.  60.49b(e) and
60.335(b)(9)(i).
    (70) ASTM D4809-95, Standard Test Method for Heat of Combustion of
Liquid Hydrocarbon Fuels by Bomb Calorimeter (Precision Method), IBR
approved for Sec. Sec.  60.18(f)(3), 60.485(g)(6), 60.564(f)(3),
60.614(d)(4), 60.664(e)(4), and 60.704(d)(4).
    (71) ASTM D4810-88 (Reapproved 1999), Standard Test Method for
Hydrogen Sulfide in Natural Gas Using Length of Stain Detector Tubes,
IBR approved for Sec. Sec.  60.4360 and 60.4415(a)(1)(ii).
    (72) ASTM D5287-97 (Reapproved 2002), Standard Practice for
Automatic Sampling of Gaseous Fuels, IBR approved for Sec.
60.4415(a)(1).
    (73) ASTM D5403-93, Standard Test Methods for Volatile Content of
Radiation Curable Materials, IBR approved for Appendix A: Method 24,
Section 6.6.
    (74) ASTM D5453-00, Standard Test Method for Determination of Total
Sulfur in Light Hydrocarbons, Motor Fuels and Oils by Ultraviolet
Fluorescence, IBR approved for Sec.  60.335(b)(10)(i).
    (75) ASTM D5453-05, Standard Test Method for Determination of Total
Sulfur in Light Hydrocarbons, Motor Fuels and Oils by Ultraviolet
Fluorescence, IBR approved for Sec.  60.4415(a)(1)(i).
    (76) ASTM D5504-01, Standard Test Method for Determination of
Sulfur Compounds in Natural Gas and Gaseous Fuels by Gas Chromatography
and Chemiluminescence, IBR approved for Sec. Sec.  60.334(h)(1) and
60.4360.
    (77) ASTM D5762-02, Standard Test Method for Nitrogen in Petroleum
and Petroleum Products by Boat-Inlet Chemiluminescence, IBR approved
for Sec.  60.335(b)(9)(i).
    (78) ASTM D5865-98, Standard Test Method for Gross Calorific Value
of Coal and Coke, IBR approved for Sec.  60.45(f)(5)(ii), 60.46(c)(2),
and Appendix A: Method 19, Section <IP_ADDRESS>.3.
    (79) ASTM D6216-98, Standard Practice for Opacity Monitor
Manufacturers to Certify Conformance with Design and Performance
Specifications, IBR approved for Appendix B, Performance Specification
1.
    (80) ASTM D6228-98, Standard Test Method for Determination of
Sulfur Compounds in Natural Gas and Gaseous Fuels by Gas Chromatography
and Flame Photometric Detection, IBR approved for Sec.  60.334(h)(1).
    (81) ASTM D6228-98 (Reapproved 2003), Standard Test Method for
Determination of Sulfur Compounds in Natural Gas and Gaseous Fuels by
Gas Chromatography and Flame Photometric Detection, IBR approved for
Sec. Sec.  60.4360 and 60.4415.
    (82) ASTM D6348-03, Standard Test Method for Determination of
Gaseous Compounds by Extractive Direct Interface Fourier Transform
Infrared

(FTIR) Spectroscopy, IBR approved for table 7 of Subpart IIII of this
part.
    (83) ASTM D6366-99, Standard Test Method for Total Trace Nitrogen
and Its Derivatives in Liquid Aromatic Hydrocarbons by Oxidative
Combustion and Electrochemical Detection, IBR approved for Sec.
60.335(b)(9)(i).
    (84) ASTM D6522-00, Standard Test Method for Determination of
Nitrogen Oxides, Carbon Monoxide, and Oxygen Concentrations in
Emissions from Natural Gas-Fired Reciprocating Engines, Combustion
Turbines, Boilers, and Process Heaters Using Portable Analyzers, IBR
approved for Sec.  60.335(a).
    (85) ASTM D6667-01, Standard Test Method for Determination of Total
Volatile Sulfur in Gaseous Hydrocarbons and Liquefied Petroleum Gases
by Ultraviolet Fluorescence, IBR approved for Sec.  60.335(b)(10)(ii).
    (86) ASTM D6667-04, Standard Test Method for Determination of Total
Volatile Sulfur in Gaseous Hydrocarbons and Liquefied Petroleum Gases
by Ultraviolet Fluorescence, IBR approved for Sec.  60.4415(a)(1)(ii).
    (87) ASTM D6784-02, Standard Test Method for Elemental, Oxidized,
Particle-Bound and Total Mercury in Flue Gas Generated from Coal-Fired
Stationary Sources (Ontario Hydro Method), IBR approved for Appendix B
to part 60, Performance Specification 12A, Section 8.6.2.
    (88) ASTM E168-67, 77, 92, General Techniques of Infrared
Quantitative Analysis, IBR approved for Sec. Sec.  60.593(b)(2) and
60.632(f).
    (89) ASTM E169-63, 77, 93, General Techniques of Ultraviolet
Quantitative Analysis, IBR approved for Sec. Sec.  60.593(b)(2) and
60.632(f).
    (90) ASTM E260-73, 91, 96, General Gas Chromatography Procedures,
IBR approved for Sec. Sec.  60.593(b)(2) and 60.632(f).
* * * * *
    (h) * * *
    (2) ASME PTC 4.1-1964 (Reaffirmed 1991), Power Test Codes: Test
Code for Steam Generating Units (with 1968 and 1969 Addenda), IBR
approved for Sec. Sec.  60.46b of subpart Db of this part,
60.58a(h)(6)(ii), 60.58b(i)(6)(ii), 60.1320(a)(3) and 60.1810(a)(3).
* * * * *

Subpart D--[Amended]

0
4. Part 60 is amended by revising subpart D to read as follows:
Subpart D--Standards of Performance for Fossil-Fuel-Fired Steam
Generators for Which Construction Is Commenced After August 17, 1971
Sec.
60.40 Applicability and designation of affected facility.
60.41 Definitions.
60.42 Standard for particulate matter (PM).
60.43 Standard for sulfur dioxide (SO2).
60.44 Standard for nitrogen oxides (NOX).
60.45 Emission and fuel monitoring.
60.46 Test methods and procedures.

Subpart D--Standards of Performance for Fossil-Fuel-Fired Steam
Generators for Which Construction Is Commenced After August 17,
1971

Sec.  60.40  Applicability and designation of affected facility.

    (a) The affected facilities to which the provisions of this subpart
apply are:
    (1) Each fossil-fuel-fired steam generating unit of more than 73
megawatts (MW) heat input rate (250 million British thermal units per
hour (MMBtu/hr)).
    (2) Each fossil-fuel and wood-residue-fired steam generating unit
capable of firing fossil fuel at a heat input rate of more than 73 MW
(250 MMBtu/hr).
    (b) Any change to an existing fossil-fuel-fired steam generating
unit to accommodate the use of combustible materials, other than fossil
fuels as defined in this subpart, shall not bring that unit under the
applicability of this subpart.
    (c) Except as provided in paragraph (d) of this section, any
facility under paragraph (a) of this section that commenced
construction or modification after August 17, 1971, is subject to the
requirements of this subpart.
    (d) The requirements of Sec. Sec.  60.44 (a)(4), (a)(5), (b) and
(d), and 60.45(f)(4)(vi) are applicable to lignite-fired steam
generating units that commenced construction or modification after
December 22, 1976.
    (e) Any facility covered under subpart Da is not covered under this
subpart.

Sec.  60.41  Definitions.

    As used in this subpart, all terms not defined herein shall have
the meaning given them in the Act, and in subpart A of this part.
    Boiler operating day means a 24-hour period between 12 midnight and
the following midnight during which any fuel is combusted at any time
in the steam-generating unit. It is not necessary for fuel to be
combusted the entire 24-hour period.
    Coal means all solid fuels classified as anthracite, bituminous,
subbituminous, or lignite by ASTM D388 (incorporated by reference, see
Sec.  60.17).
    Coal refuse means waste-products of coal mining, cleaning, and coal
preparation operations (e.g. culm, gob, etc.) containing coal, matrix
material, clay, and other organic and inorganic material.
    Fossil fuel means natural gas, petroleum, coal, and any form of
solid, liquid, or gaseous fuel derived from such materials for the
purpose of creating useful heat.
    Fossil fuel and wood residue-fired steam generating unit means a
furnace or boiler used in the process of burning fossil fuel and wood
residue for the purpose of producing steam by heat transfer.
    Fossil-fuel-fired steam generating unit means a furnace or boiler
used in the process of burning fossil fuel for the purpose of producing
steam by heat transfer.
    Wood residue means bark, sawdust, slabs, chips, shavings, mill
trim, and other wood products derived from wood processing and forest
management operations.

Sec.  60.42  Standard for particulate matter (PM).

    (a) On and after the date on which the performance test required to
be conducted by Sec.  60.8 is completed, no owner or operator subject
to the provisions of this subpart shall cause to be discharged into the
atmosphere from any affected facility any gases that:
    (1) Contain PM in excess of 43 nanograms per joule (ng/J) heat
input (0.10 lb/MMBtu) derived from fossil fuel or fossil fuel and wood
residue.
    (2) Exhibit greater than 20 percent opacity except for one six-
minute period per hour of not more than 27 percent opacity.
    (b)(1) On or after December 28, 1979, no owner or operator shall
cause to be discharged into the atmosphere from the Southwestern Public
Service Company's Harrington Station 1, in Amarillo, TX, any
gases which exhibit greater than 35 percent opacity, except that a
maximum or 42 percent opacity shall be permitted for not more than 6
minutes in any hour.
    (2) Interstate Power Company shall not cause to be discharged into
the atmosphere from its Lansing Station Unit No. 4 in Lansing, IA, any
gases which exhibit greater than 32 percent opacity, except that a
maximum of 39 percent opacity shall be permitted for not more than six
minutes in any hour.

Sec.  60.43  Standard for sulfur dioxide (SO2).

    (a) Except as provided under paragraph (d) of this section, on and
after the date on which the performance test required to be conducted
by Sec.  60.8 is completed, no owner or operator subject to the
provisions of this subpart shall cause to be discharged into the
atmosphere from any affected facility any gases that contain
SO2 in excess of:

    (1) 340 ng/J heat input (0.80 lb/MMBtu) derived from liquid fossil
fuel or liquid fossil fuel and wood residue.
    (2) 520 ng/J heat input (1.2 lb/MMBtu) derived from solid fossil
fuel or solid fossil fuel and wood residue, except as provided in
paragraph (e) of this section.
    (b) Except as provided under paragraph (d) of this section, when
different fossil fuels are burned simultaneously in any combination,
the applicable standard (in ng/J) shall be determined by proration
using the following formula:
[GRAPHIC] [TIFF OMITTED] TR13JN07.000

Where:

PSSO2 = Prorated standard for SO2 when burning
different fuels simultaneously, in ng/J heat input derived from all
fossil fuels or from all fossil fuels and wood residue fired;
y = Percentage of total heat input derived from liquid fossil fuel;
and
z = Percentage of total heat input derived from solid fossil fuel.

    (c) Compliance shall be based on the total heat input from all
fossil fuels burned, including gaseous fuels.
    (d) As an alternate to meeting the requirements of paragraphs (a)
and (b) of this section, an owner or operator can petition the
Administrator (in writing) to comply with Sec.  60.43Da(i)(3) of
subpart Da of this part or comply with Sec.  60.42b(k) of subpart Db of
this part, as applicable to the affected source. If the Administrator
grants the petition, the source will from then on (unless the unit is
modified or reconstructed in the future) have to comply with the
requirements in Sec.  60.43Da(i)(3) of subpart Da of this part or Sec.
60.42b(k) of subpart Db of this part, as applicable to the affected
source.
    (e) Units 1 and 2 (as defined in appendix G of this part) at the
Newton Power Station owned or operated by the Central Illinois Public
Service Company will be in compliance with paragraph (a)(2) of this
section if Unit 1 and Unit 2 individually comply with paragraph (a)(2)
of this section or if the combined emission rate from Units 1 and 2
does not exceed 470 ng/J (1.1 lb/MMBtu) combined heat input to Units 1
and 2.

Sec.  60.44  Standard for nitrogen oxides (NOX).

    (a) Except as provided under paragraph (e) of this section, on and
after the date on which the performance test required to be conducted
by Sec.  60.8 is completed, no owner or operator subject to the
provisions of this subpart shall cause to be discharged into the
atmosphere from any affected facility any gases that contain
NOX, expressed as NO2 in excess of:
    (1) 86 ng/J heat input (0.20 lb/MMBtu) derived from gaseous fossil
fuel.
    (2) 129 ng/J heat input (0.30 lb/MMBtu) derived from liquid fossil
fuel, liquid fossil fuel and wood residue, or gaseous fossil fuel and
wood residue.
    (3) 300 ng/J heat input (0.70 lb/MMBtu) derived from solid fossil
fuel or solid fossil fuel and wood residue (except lignite or a solid
fossil fuel containing 25 percent, by weight, or more of coal refuse).
    (4) 260 ng/J heat input (0.60 lb MMBtu) derived from lignite or
lignite and wood residue (except as provided under paragraph (a)(5) of
this section).
    (5) 340 ng/J heat input (0.80 lb MMBtu) derived from lignite which
is mined in North Dakota, South Dakota, or Montana and which is burned
in a cyclone-fired unit.
    (b) Except as provided under paragraphs (c), (d), and (e) of this
section, when different fossil fuels are burned simultaneously in any
combination, the applicable standard (in ng/J) is determined by
proration using the following formula:
[GRAPHIC] [TIFF OMITTED] TR13JN07.001

Where:

PSNOx = Prorated standard for NOX
when burning different fuels simultaneously, in ng/J heat input
derived from all fossil fuels fired or from all fossil fuels and
wood residue fired;
w = Percentage of total heat input derived from lignite;
x = Percentage of total heat input derived from gaseous fossil fuel;
y = Percentage of total heat input derived from liquid fossil fuel;
and
z = Percentage of total heat input derived from solid fossil fuel
(except lignite).

    (c) When a fossil fuel containing at least 25 percent, by weight,
of coal refuse is burned in combination with gaseous, liquid, or other
solid fossil fuel or wood residue, the standard for NOX does
not apply.
    (d) Except as provided under paragraph (e) of this section,
cyclone-fired units which burn fuels containing at least 25 percent of
lignite that is mined in North Dakota, South Dakota, or Montana remain
subject to paragraph (a)(5) of this section regardless of the types of
fuel combusted in combination with that lignite.
    (e) As an alternate to meeting the requirements of paragraphs (a),
(b), and (d) of this section, an owner or operator can petition the
Administrator (in writing) to comply with Sec.  60.44Da(e)(3) of
subpart Da of this part. If the Administrator grants the petition, the
source will from then on (unless the unit is modified or reconstructed
in the future) have to comply with the requirements in Sec.
60.44Da(e)(3) of subpart Da of this part.

Sec.  60.45  Emissions and fuel monitoring.

    (a) Each owner or operator shall install, calibrate, maintain, and
operate continuous emissions monitoring systems (CEMS) for measuring
the opacity of emissions, SO2 emissions, NOX
emissions, and either oxygen (O2) or carbon dioxide
(CO2) except as provided in paragraph (b) of this section.
    (b) Certain of the CEMS requirements under paragraph (a) of this
section do not apply to owners or operators under the following
conditions:
    (1) For a fossil-fuel-fired steam generator that burns only gaseous
fossil fuel and that does not use post-combustion technology to reduce
emissions of SO2 or PM, CEMS for measuring the opacity of
emissions and SO2 emissions are not required.
    (2) For a fossil-fuel-fired steam generator that does not use a
flue gas desulfurization device, a CEMS for measuring SO2
emissions is not required if the owner or operator monitors
SO2 emissions by fuel sampling and analysis.
    (3) Notwithstanding Sec.  60.13(b), installation of a CEMS for
NOX may be delayed until after the initial performance tests
under Sec.  60.8 have been conducted. If the owner or operator
demonstrates during the performance test that emissions of
NOX are less than 70 percent of the applicable standards in
Sec.  60.44, a CEMS for measuring NOX emissions is not
required. If the initial performance test results show that
NOX emissions are greater than 70 percent of the applicable
standard, the owner or operator shall install a CEMS for NOX
within one year after the date of the initial performance

tests under Sec.  60.8 and comply with all other applicable monitoring
requirements under this part.
    (4) If an owner or operator does not install any CEMS for sulfur
oxides and NOX, as provided under paragraphs (b)(1) and
(b)(3) or paragraphs (b)(2) and (b)(3) of this section a CEMS for
measuring either O2 or CO2 is not required.
    (5) An owner or operator may petition the Administrator (in
writing) to install a PM CEMS as an alternative to the CEMS for
monitoring opacity emissions.
    (6) A CEMS for measuring the opacity of emissions is not required
for a fossil fuel-fired steam generator that does not use post-
combustion technology (except a wet scrubber) for reducing PM,
SO2, or carbon monoxide (CO) emissions, burns only gaseous
fuels or fuel oils that contain less than or equal to 0.30 weight
percent sulfur, and is operated such that emissions of CO to the
atmosphere from the affected source are maintained at levels less than
or equal to 0.15 lb/MMBtu on a boiler operating day average basis.
Owners and operators of affected sources electing to comply with this
paragraph must demonstrate compliance according to the procedures
specified in paragraphs (b)(6)(i) through (iv) of this section.
    (i) You must monitor CO emissions using a CEMS according to the
procedures specified in paragraphs (b)(6)(i)(A) through (D) of this
section.
    (A) The CO CEMS must be installed, certified, maintained, and
operated according to the provisions in Sec.  60.58b(i)(3) of subpart
Eb of this part.
    (B) Each 1-hour CO emissions average is calculated using the data
points generated by the CO CEMS expressed in parts per million by
volume corrected to 3 percent oxygen (dry basis).
    (C) At a minimum, valid 1-hour CO emissions averages must be
obtained for at least 90 percent of the operating hours on a 30-day
rolling average basis. At least two data points per hour must be used
to calculate each 1-hour average.
    (D) Quarterly accuracy determinations and daily calibration drift
tests for the CO CEMS must be performed in accordance with procedure 1
in appendix F of this part.
    (ii) You must calculate the 1-hour average CO emissions levels for
each boiler operating day by multiplying the average hourly CO output
concentration measured by the CO CEMS times the corresponding average
hourly flue gas flow rate and divided by the corresponding average
hourly heat input to the affected source. The 24-hour average CO
emission level is determined by calculating the arithmetic average of
the hourly CO emission levels computed for each boiler operating day.
    (iii) You must evaluate the preceding 24-hour average CO emission
level each boiler operating day excluding periods of affected source
startup, shutdown, or malfunction. If the 24-hour average CO emission
level is greater than 0.15 lb/MMBtu, you must initiate investigation of
the relevant equipment and control systems within 24 hours of the first
discovery of the high emission incident and, take the appropriate
corrective action as soon as practicable to adjust control settings or
repair equipment to reduce the 24-hour average CO emission level to
0.15 lb/MMBtu or less.
    (iv) You must record the CO measurements and calculations performed
according to paragraph (b)(6) of this section and any corrective
actions taken. The record of corrective action taken must include the
date and time during which the 24-hour average CO emission level was
greater than 0.15 lb/MMBtu, and the date, time, and description of the
corrective action.
    (c) For performance evaluations under Sec.  60.13(c) and
calibration checks under Sec.  60.13(d), the following procedures shall
be used:
    (1) Methods 6, 7, and 3B of appendix A of this part, as applicable,
shall be used for the performance evaluations of SO2 and
NOX continuous monitoring systems. Acceptable alternative
methods for Methods 6, 7, and 3B of appendix A of this part are given
in Sec.  60.46(d).
    (2) Sulfur dioxide or nitric oxide, as applicable, shall be used
for preparing calibration gas mixtures under Performance Specification
2 of appendix B to this part.
    (3) For affected facilities burning fossil fuel(s), the span value
for a continuous monitoring system measuring the opacity of emissions
shall be 80, 90, or 100 percent. For a continuous monitoring system
measuring sulfur oxides or NOX the span value shall be
determined using one of the following procedures:
    (i) Except as provided under paragraph (c)(3)(ii) of this section,
SO2 and NOX span values shall be determined as
follows:

----------------------------------------------------------------------------------------------------------------
                                                                 In parts per million
             Fossil fuel             ---------------------------------------------------------------------------
                                               Span value for SO2                    Span value for NOX
----------------------------------------------------------------------------------------------------------------
Gas.................................  (\1\)...............................  500.
Liquid..............................  1,000...............................  500.
Solid...............................  1,500...............................  1,000.
Combinations........................  1,000y + 1,500z.....................  500 (x + y) + 1,000z.
----------------------------------------------------------------------------------------------------------------
\1\ Not applicable.

Where:

x = Fraction of total heat input derived from gaseous fossil fuel;
y = Fraction of total heat input derived from liquid fossil fuel;
and
z = Fraction of total heat input derived from solid fossil fuel.

    (ii) As an alternative to meeting the requirements of paragraph
(c)(3)(i) of this section, the owner or operator of an affected
facility may elect to use the SO2 and NOX span
values determined according to sections 2.1.1 and 2.1.2 in appendix A
to part 75 of this chapter.
    (4) All span values computed under paragraph (c)(3)(i) of this
section for burning combinations of fossil fuels shall be rounded to
the nearest 500 ppm. Span values that are computed under paragraph
(c)(3)(ii) of this section shall be rounded off according to the
applicable procedures in section 2 of appendix A to part 75 of this
chapter.
    (5) For a fossil-fuel-fired steam generator that simultaneously
burns fossil fuel and nonfossil fuel, the span value of all CEMS shall
be subject to the Administrator's approval.
    (d) [Reserved]
    (e) For any CEMS installed under paragraph (a) of this section, the
following conversion procedures shall be used to convert the continuous
monitoring data into units of the applicable standards (ng/J, lb/
MMBtu):
    (1) When a CEMS for measuring O2 is selected, the
measurement of the pollutant concentration and O2
concentration shall each be on a consistent basis (wet or dry).
Alternative procedures approved by the Administrator shall be used when
measurements are on a wet basis. When measurements are on a dry basis,
the

following conversion procedure shall be used:
[GRAPHIC] [TIFF OMITTED] TR13JN07.002

Where E, C, F, and %O2 are determined under paragraph (f)
of this section.

    (2) When a CEMS for measuring CO2 is selected, the
measurement of the pollutant concentration and CO2
concentration shall each be on a consistent basis (wet or dry) and the
following conversion procedure shall be used:
[GRAPHIC] [TIFF OMITTED] TR13JN07.003

Where E, C, Fc and %CO2 are determined under
paragraph (f) of this section.

    (f) The values used in the equations under paragraphs (e)(1) and
(2) of this section are derived as follows:
    (1) E = pollutant emissions, ng/J (lb/MMBtu).
    (2) C = pollutant concentration, ng/dscm (lb/dscf), determined by
multiplying the average concentration (ppm) for each one-hour period by
4.15 x 104 M ng/dscm per ppm (2.59 x 10-9 M lb/
dscf per ppm) where M = pollutant molecular weight, g/g-mole (lb/lb-
mole). M = 64.07 for SO2 and 46.01 for NOX.
    (3) %O2, %CO2 = O2 or
CO2 volume (expressed as percent), determined with equipment
specified under paragraph (a) of this section.
    (4) F, Fc = a factor representing a ratio of the volume
of dry flue gases generated to the calorific value of the fuel
combusted (F), and a factor representing a ratio of the volume of
CO2 generated to the calorific value of the fuel combusted
(Fc), respectively. Values of F and Fc are given
as follows:
    (i) For anthracite coal as classified according to ASTM D388
(incorporated by reference, see Sec.  60.17), F = 2,723 x
10-17 dscm/J (10,140 dscf/MMBtu) and Fc = 0.532 x
10-17 scm CO2/J (1,980 scf CO2/MMBtu).
    (ii) For subbituminous and bituminous coal as classified according
to ASTM D388 (incorporated by reference, see Sec.  60.17), F = 2.637 x
10-7 dscm/J (9,820 dscf/MMBtu) and Fc = 0.486 x
10-7 scm CO2/J (1,810 scf CO2/MMBtu).
    (iii) For liquid fossil fuels including crude, residual, and
distillate oils, F = 2.476 x 10-7 dscm/J (9,220 dscf/MMBtu)
and Fc = 0.384 x 10-7 scm CO2/J (1,430
scf CO2/MMBtu).
    (iv) For gaseous fossil fuels, F = 2.347 x 10-7 dscm/J
(8,740 dscf/MMBtu). For natural gas, propane, and butane fuels,
Fc = 0.279 x 10-7 scm CO2/J (1,040 scf
CO2/MMBtu) for natural gas, 0.322 x 10-7 scm
CO2/J (1,200 scf CO2/MMBtu) for propane, and
0.338 x 10-7 scm CO2/J (1,260 scf CO2/
MMBtu) for butane.
    (v) For bark F = 2.589 x 10-7 dscm/J (9,640 dscf/MMBtu)
and Fc = 0.500 x 10-7 scm CO2/J (1,840
scf CO2/MMBtu). For wood residue other than bark F = 2.492 x
10-7 dscm/J (9,280 dscf/MMBtu) and Fc = 0.494 x
10-7 scm CO2/J (1,860 scf CO2/MMBtu).
    (vi) For lignite coal as classified according to ASTM D388
(incorporated by reference, see Sec.  60.17), F = 2.659 x
10-7 dscm/J (9,900 dscf/MMBtu) and Fc = 0.516 x
10-7 scm CO2/J (1,920 scf CO2/MMBtu).
    (5) The owner or operator may use the following equation to
determine an F factor (dscm/J or dscf/MMBtu) on a dry basis (if it is
desired to calculate F on a wet basis, consult the Administrator) or Fc
factor (scm CO2/J, or scf CO2/MMBtu) on either
basis in lieu of the F or Fc factors specified in paragraph
(f)(4) of this section:
[GRAPHIC] [TIFF OMITTED] TR13JN07.004

    (i) %H, %C, %S, %N, and %O are content by weight of hydrogen,
carbon, sulfur, nitrogen, and O2 (expressed as percent),
respectively, as determined on the same basis as GCV by ultimate
analysis of the fuel fired, using ASTM D3178 or D3176 (solid fuels), or
computed from results using ASTM D1137, D1945, or D1946 (gaseous fuels)
as applicable. (These five methods are incorporated by reference, see
Sec.  60.17.)
    (ii) GVC is the gross calorific value (kJ/kg, Btu/lb) of the fuel
combusted determined by the ASTM test methods D2015 or D5865 for solid
fuels and D1826 for gaseous fuels as applicable. (These three methods
are incorporated by reference, see Sec.  60.17.)
    (iii) For affected facilities which fire both fossil fuels and
nonfossil fuels, the F or Fc value shall be subject to the
Administrator's approval.
    (6) For affected facilities firing combinations of fossil fuels or
fossil fuels and wood residue, the F or Fc factors determined by
paragraphs (f)(4) or (f)(5) of this section shall be prorated in
accordance with the applicable formula as follows:
[GRAPHIC] [TIFF OMITTED] TR13JN07.005

Where:

Xi = Fraction of total heat input derived from each type
of fuel (e.g. natural gas, bituminous coal, wood residue, etc.);
Fi or (Fc)i = Applicable F or
Fc factor for each fuel type determined in accordance
with paragraphs (f)(4) and (f)(5) of this section; and
n = Number of fuels being burned in combination.

    (g) Excess emission and monitoring system performance reports shall
be submitted to the Administrator semiannually for each six-month
period in the calendar year. All semiannual reports shall be postmarked
by the 30th day following the end of each six-month period. Each excess
emission and MSP report shall include the information required in Sec.
60.7(c). Periods of excess emissions and monitoring systems (MS)
downtime that shall be reported are defined as follows:
    (1) Opacity. Excess emissions are defined as any six-minute period
during which the average opacity of emissions exceeds 20 percent
opacity, except that one six-minute average per hour of up to 27
percent opacity need not be reported.
    (i) For sources subject to the opacity standard of Sec.
60.42(b)(1), excess emissions are defined as any six-minute period
during which the average opacity of emissions exceeds 35 percent
opacity, except that one six-minute average per hour of up to 42
percent opacity need not be reported.
    (ii) For sources subject to the opacity standard of Sec.
60.42(b)(2), excess emissions are defined as any six-minute period
during which the average opacity of emissions exceeds 32 percent
opacity, except that one six-minute average per hour of up to 39
percent opacity need not be reported.
    (2) Sulfur dioxide. Excess emissions for affected facilities are
defined as:
    (i) Any three-hour period during which the average emissions
(arithmetic average of three contiguous one-hour periods) of
SO2 as measured by a CEMS exceed the applicable standard
under Sec.  60.43, or
    (ii) Any 30 operating day period during which the average emissions
(arithmetic average of all one-hour periods during the 30 operating
days) of SO2 as measured by a CEMS exceed the applicable
standard under Sec.  60.43. Facilities complying with the 30-day
SO2 standard shall use the most current associated
SO2 compliance and monitoring requirements in Sec. Sec.
60.48Da and 60.49Da of subpart Da of this part.
    (3) Nitrogen oxides. Excess emissions for affected facilities using
a CEMS for measuring NOX are defined as:
    (i) Any three-hour period during which the average emissions
(arithmetic average of three contiguous one-hour periods) exceed the
applicable standards under Sec.  60.44, or
    (ii) Any 30 operating day period during which the average emissions
(arithmetic average of all one-hour periods during the 30 operating
days) of NOX as measured by a CEMS exceed the applicable
standard under Sec.  60.43. Facilities complying with the 30-day
NOX standard shall use the most current associated
NOX compliance and monitoring requirements in Sec. Sec.
60.48Da and 60.49Da of subpart Da of this part.
    (4) Particulate matter. Excess emissions for affected facilities
using a CEMS for measuring PM are defined as any boiler operating day
period during which the average emissions (arithmetic average of all
operating one-hour periods) exceed the applicable standards under Sec.
60.43. Affected facilities using PM CEMS in lieu of a CEMS for
monitoring opacity emissions must follow the most current applicable
compliance and monitoring provisions in Sec. Sec.  60.48Da and 60.49Da
of subpart Da of this part.

Sec.  60.46  Test methods and procedures.

    (a) In conducting the performance tests required in Sec.  60.8, and
subsequent performance tests as requested by the EPA Administrator, the
owner or operator shall use as reference methods and procedures the
test methods in appendix A of this part or other methods and procedures
as specified in this section, except as provided in Sec.  60.8(b).
Acceptable alternative methods and procedures are given in paragraph
(d) of this section.
    (b) The owner or operator shall determine compliance with the PM,
SO2, and NOX standards in Sec. Sec.  60.42,
60.43, and 60.44 as follows:
    (1) The emission rate (E) of PM, SO2, or NOX
shall be computed for each run using the following equation:
[GRAPHIC] [TIFF OMITTED] TR13JN07.006

Where:

E = Emission rate of pollutant, ng/J (1b/million Btu);
C = Concentration of pollutant, ng/dscm (1b/dscf);
%O2 = O2 concentration, percent dry basis; and
Fd = Factor as determined from Method 19 of appendix A of
this part.

    (2) Method 5 of appendix A of this part shall be used to determine
the PM concentration (C) at affected facilities without wet flue-gas-
desulfurization (FGD) systems and Method 5B of appendix A of this part
shall be used to determine the PM concentration (C) after FGD systems.
    (i) The sampling time and sample volume for each run shall be at
least 60 minutes and 0.85 dscm (30 dscf). The probe and filter holder
heating systems in the sampling train shall be set to provide an
average gas temperature of 16014 [deg]C (32025
[deg]F).
    (ii) The emission rate correction factor, integrated or grab
sampling and analysis procedure of Method 3B of appendix A of this part
shall be used to determine the O2 concentration
(%O2). The O2 sample shall be obtained
simultaneously with, and at the same traverse points as, the
particulate sample. If the grab sampling procedure is used, the
O2 concentration for the run shall be the arithmetic mean of
the sample O2 concentrations at all traverse points.
    (iii) If the particulate run has more than 12 traverse points, the
O2 traverse points may be reduced to 12 provided that Method
1 of appendix A of this part is used to locate the 12 O2
traverse points.
    (3) Method 9 of appendix A of this part and the procedures in Sec.
60.11 shall be used to determine opacity.
    (4) Method 6 of appendix A of this part shall be used to determine
the SO2 concentration.
    (i) The sampling site shall be the same as that selected for the
particulate sample. The sampling location in the duct shall be at the
centroid of the cross section or at a point no closer to the walls than
1 m (3.28 ft). The sampling time and sample volume for each sample run
shall be at least 20 minutes and 0.020 dscm (0.71 dscf). Two samples
shall be taken during a 1-hour period, with each sample taken within a
30-minute interval.
    (ii) The emission rate correction factor, integrated sampling and
analysis procedure of Method 3B of appendix A of this part shall be
used to determine the O2 concentration (%O2). The
O2 sample shall be taken simultaneously with, and at the
same point as, the SO2 sample. The SO2 emission
rate shall be computed for each pair of SO2 and
O2 samples. The SO2 emission rate (E) for each
run shall be the arithmetic mean of the results of the two pairs of
samples.
    (5) Method 7 of appendix A of this part shall be used to determine
the NOX concentration.
    (i) The sampling site and location shall be the same as for the
SO2 sample. Each run shall consist of four grab samples,
with each sample taken at about 15-minute intervals.
    (ii) For each NOX sample, the emission rate correction
factor, grab sampling and analysis procedure of

Method 3B of appendix A of this part shall be used to determine the
O2 concentration (%O2). The sample shall be taken
simultaneously with, and at the same point as, the NOX
sample.
    (iii) The NOX emission rate shall be computed for each
pair of NOX and O2 samples. The NOX
emission rate (E) for each run shall be the arithmetic mean of the
results of the four pairs of samples.
    (c) When combinations of fossil fuels or fossil fuel and wood
residue are fired, the owner or operator (in order to compute the
prorated standard as shown in Sec. Sec.  60.43(b) and 60.44(b)) shall
determine the percentage (w, x, y, or z) of the total heat input
derived from each type of fuel as follows:
    (1) The heat input rate of each fuel shall be determined by
multiplying the gross calorific value of each fuel fired by the rate of
each fuel burned.
    (2) ASTM Methods D2015, or D5865 (solid fuels), D240 (liquid
fuels), or D1826 (gaseous fuels) (all of these methods are incorporated
by reference, see Sec.  60.17) shall be used to determine the gross
calorific values of the fuels. The method used to determine the
calorific value of wood residue must be approved by the Administrator.
    (3) Suitable methods shall be used to determine the rate of each
fuel burned during each test period, and a material balance over the
steam generating system shall be used to confirm the rate.
    (d) The owner or operator may use the following as alternatives to
the reference methods and procedures in this section or in other
sections as specified:
    (1) The emission rate (E) of PM, SO2 and NOX
may be determined by using the Fc factor, provided that the following
procedure is used:
    (i) The emission rate (E) shall be computed using the following
equation:

[GRAPHIC] [TIFF OMITTED] TR13JN07.007

Where:

E = Emission rate of pollutant, ng/J (lb/MMBtu);
C = Concentration of pollutant, ng/dscm (lb/dscf);
%CO2 = CO2 concentration, percent dry basis;
and
Fc = Factor as determined in appropriate sections of
Method 19 of appendix A of this part.

    (ii) If and only if the average Fc factor in Method 19 of appendix
A of this part is used to calculate E and either E is from 0.97 to 1.00
of the emission standard or the relative accuracy of a continuous
emission monitoring system is from 17 to 20 percent, then three runs of
Method 3B of appendix A of this part shall be used to determine the
O2 and CO2 concentration according to the
procedures in paragraph (b)(2)(ii), (4)(ii), or (5)(ii) of this
section. Then if Fo (average of three runs), as calculated
from the equation in Method 3B of appendix A of this part, is more than
3 percent than the average Fo value, as
determined from the average values of Fd and Fc
in Method 19 of appendix A of this part, i.e., Foa = 0.209
(Fda/Fca), then the following procedure shall be
followed:
    (A) When Fo is less than 0.97 Foa, then E
shall be increased by that proportion under 0.97 Foa, e.g.,
if Fo is 0.95 Foa, E shall be increased by 2
percent. This recalculated value shall be used to determine compliance
with the emission standard.
    (B) When Fo is less than 0.97 Foa and when
the average difference (d) between the continuous monitor minus the
reference methods is negative, then E shall be increased by that
proportion under 0.97 Foa, e.g., if Fo is 0.95
Foa, E shall be increased by 2 percent. This recalculated
value shall be used to determine compliance with the relative accuracy
specification.
    (C) When Fo is greater than 1.03 Foa and when
the average difference d is positive, then E shall be decreased by that
proportion over 1.03 Foa, e.g., if Fo is 1.05
Foa, E shall be decreased by 2 percent. This recalculated
value shall be used to determine compliance with the relative accuracy
specification.
    (2) For Method 5 or 5B of appendix A of this part, Method 17 of
appendix A of this part may be used at facilities with or without wet
FGD systems if the stack gas temperature at the sampling location does
not exceed an average temperature of 16 0[deg]C (320 [deg]F). The
procedures of sections 2.1 and 2.3 of Method 5B of appendix A of this
part may be used with Method 17 of appendix A of this part only if it
is used after wet FGD systems. Method 17 of appendix A of this part
shall not be used after wet FGD systems if the effluent gas is
saturated or laden with water droplets.
    (3) Particulate matter and SO2 may be determined
simultaneously with the Method 5 of appendix A of this part train
provided that the following changes are made:
    (i) The filter and impinger apparatus in sections 2.1.5 and 2.1.6
of Method 8 of appendix A of this part is used in place of the
condenser (section 2.1.7) of Method 5 of appendix A of this part.
    (ii) All applicable procedures in Method 8 of appendix A of this
part for the determination of SO2 (including moisture) are
used:
    (4) For Method 6 of appendix A of this part, Method 6C of appendix
A of this part may be used. Method 6A of appendix A of this part may
also be used whenever Methods 6 and 3B of appendix A of this part data
are specified to determine the SO2 emission rate, under the
conditions in paragraph (d)(1) of this section.
    (5) For Method 7 of appendix A of this part, Method 7A, 7C, 7D, or
7E of appendix A of this part may be used. If Method 7C, 7D, or 7E of
appendix A of this part is used, the sampling time for each run shall
be at least 1 hour and the integrated sampling approach shall be used
to determine the O2 concentration (%O2) for the
emission rate correction factor.
    (6) For Method 3 of appendix A of this part, Method 3A or 3B of
appendix A of this part may be used.
    (7) For Method 3B of appendix A of this part, Method 3A of appendix
A of this part may be used.

Subpart Da--[Amended]

0
4a. Subpart Da is revised as follows:
Subpart Da--Standards of Performance for Electric Utility Steam
Generating Units for Which Construction is Commenced After September
18, 1978
Sec.
60.40Da Applicability and designation of affected facility.
60.41Da Definitions.
60.42Da Standard for particulate matter (PM).
60.43Da Standard for sulfur dioxide (SO2).
60.44Da Standard for nitrogen oxides (NOX).
60.45Da Standard for mercury (Hg).
60.46Da [Reserved]
60.47Da Commercial demonstration permit.
60.48Da Compliance provisions.
60.49Da Emission monitoring.
60.50Da Compliance determination procedures and methods.
60.51Da Reporting requirements.
60.52Da Recordkeeping requirements.

Subpart Da--Standards of Performance for Electric Utility Steam
Generating Units for Which Construction is Commenced After
September 18, 1978

Sec.  60.40Da  Applicability and designation of affected facility.

    (a) The affected facility to which this subpart applies is each
electric utility steam generating unit:
    (1) That is capable of combusting more than 73 megawatts (MW) (250
million British thermal units per hour (MMBtu/hr) heat input of fossil
fuel (either alone or in combination with any other fuel); and
    (2) For which construction, modification, or reconstruction is
commenced after September 18, 1978.

    (b) Combined cycle gas turbines (both the stationary combustion
turbine and any associated duct burners) are subject to this part and
not subject to subpart GG or KKKK of this part if:
    (1) The combined cycle gas turbine is capable of combusting more
than 73 MW (250 MMBtu/hr) heat input of fossil fuel (either alone or in
combination with any other fuel); and
    (2) The combined cycle gas turbine is designed and intended to burn
fuels containing 50 percent (by heat input) or more solid-derived fuel
not meeting the definition of natural gas on a 12-month rolling average
basis; and
    (3) The combined cycle gas turbine commenced construction,
modification, or reconstruction after February 28, 2005.
    (4) This subpart will continue to apply to all other electric
utility combined cycle gas turbines that are capable of combusting more
than 73 MW (250 MMBtu/hr) heat input of fossil fuel in the heat
recovery steam generator. If the heat recovery steam generator is
subject to this subpart and the stationary combustion turbine is
subject to either subpart GG or KKKK of this part, only emissions
resulting from combustion of fuels in the steam-generating unit are
subject to this subpart. (The stationary combustion turbine emissions
are subject to subpart GG or KKKK, as applicable, of this part).
    (c) Any change to an existing fossil-fuel-fired steam generating
unit to accommodate the use of combustible materials, other than fossil
fuels, shall not bring that unit under the applicability of this
subpart.
    (d) Any change to an existing steam generating unit originally
designed to fire gaseous or liquid fossil fuels, to accommodate the use
of any other fuel (fossil or nonfossil) shall not bring that unit under
the applicability of this subpart.

Sec.  60.41Da  Definitions.

    As used in this subpart, all terms not defined herein shall have
the meaning given them in the Act and in subpart A of this part.
    Anthracite means coal that is classified as anthracite according to
the American Society of Testing and Materials in ASTM D388
(incorporated by reference, see Sec.  60.17).
    Available purchase power means the lesser of the following:
    (a) The sum of available system capacity in all neighboring
companies.
    (b) The sum of the rated capacities of the power interconnection
devices between the principal company and all neighboring companies,
minus the sum of the electric power load on these interconnections.
    (c) The rated capacity of the power transmission lines between the
power interconnection devices and the electric generating units (the
unit in the principal company that has the malfunctioning flue gas
desulfurization system and the unit(s) in the neighboring company
supplying replacement electrical power) less the electric power load on
these transmission lines.
    Available system capacity means the capacity determined by
subtracting the system load and the system emergency reserves from the
net system capacity.
    Biomass means plant materials and animal waste.
    Bituminous coal means coal that is classified as bituminous
according to the American Society of Testing and Materials in ASTM D388
(incorporated by reference, see Sec.  60.17).
    Boiler operating day for units constructed, reconstructed, or
modified on or before February 28, 2005, means a 24-hour period during
which fossil fuel is combusted in a steam-generating unit for the
entire 24 hours. For units constructed, reconstructed, or modified
after February 28, 2005, boiler operating day means a 24-hour period
between 12 midnight and the following midnight during which any fuel is
combusted at any time in the steam-generating unit. It is not necessary
for fuel to be combusted the entire 24-hour period.
    Coal means all solid fuels classified as anthracite, bituminous,
subbituminous, or lignite by the American Society of Testing and
Materials in ASTM D388 (incorporated by reference, see Sec.  60.17) and
coal refuse. Synthetic fuels derived from coal for the purpose of
creating useful heat, including but not limited to solvent-refined
coal, gasified coal (not meeting the definition of natural gas), coal-
oil mixtures, and coal-water mixtures are included in this definition
for the purposes of this subpart.
    Coal-fired electric utility steam generating unit means an electric
utility steam generating unit that burns coal, coal refuse, or a
synthetic gas derived from coal either exclusively, in any combination
together, or in any combination with other fuels in any amount.
    Coal refuse means waste products of coal mining, physical coal
cleaning, and coal preparation operations (e.g. culm, gob, etc.)
containing coal, matrix material, clay, and other organic and inorganic
material.
    Cogeneration, also known as ``combined heat and power,'' means a
steam-generating unit that simultaneously produces both electric (or
mechanical) and useful thermal energy from the same primary energy
source.
    Combined cycle gas turbine means a stationary turbine combustion
system where heat from the turbine exhaust gases is recovered by a
steam generating unit.
    Dry flue gas desulfurization technology or dry FGD means a sulfur
dioxide control system that is located downstream of the steam
generating unit and removes sulfur oxides (SO2) from the
combustion gases of the steam generating unit by contacting the
combustion gases with an alkaline reagent and water, whether introduced
separately or as a premixed slurry or solution and forming a dry powder
material. This definition includes devices where the dry powder
material is subsequently converted to another form. Alkaline slurries
or solutions used in dry FGD technology include, but are not limited
to, lime and sodium.
    Duct burner means a device that combusts fuel and that is placed in
the exhaust duct from another source, such as a stationary gas turbine,
internal combustion engine, kiln, etc., to allow the firing of
additional fuel to heat the exhaust gases before the exhaust gases
enter a heat recovery steam generating unit.
    Electric utility combined cycle gas turbine means any combined
cycle gas turbine used for electric generation that is constructed for
the purpose of supplying more than one-third of its potential electric
output capacity and more than 25 MW net-electrical output to any
utility power distribution system for sale. Any steam distribution
system that is constructed for the purpose of providing steam to a
steam electric generator that would produce electrical power for sale
is also considered in determining the electrical energy output capacity
of the affected facility.
    Electric utility company means the largest interconnected
organization, business, or governmental entity that generates electric
power for sale (e.g., a holding company with operating subsidiary
companies).
    Electric utility steam-generating unit means any steam electric
generating unit that is constructed for the purpose of supplying more
than one-third of its potential electric output capacity and more than
25 MW net-electrical output to any utility power distribution system
for sale. Also, any steam supplied to a steam distribution system for
the purpose of providing steam to a steam-electric generator that would
produce electrical energy for sale is considered in determining the
electrical energy output capacity of the affected facility.

    Electrostatic precipitator or ESP means an add-on air pollution
control device used to capture particulate matter (PM) by charging the
particles using an electrostatic field, collecting the particles using
a grounded collecting surface, and transporting the particles into a
hopper.
    Emergency condition means that period of time when:
    (1) The electric generation output of an affected facility with a
malfunctioning flue gas desulfurization system cannot be reduced or
electrical output must be increased because:
    (i) All available system capacity in the principal company
interconnected with the affected facility is being operated, and
    (ii) All available purchase power interconnected with the affected
facility is being obtained, or
    (2) The electric generation demand is being shifted as quickly as
possible from an affected facility with a malfunctioning flue gas
desulfurization system to one or more electrical generating units held
in reserve by the principal company or by a neighboring company, or
    (3) An affected facility with a malfunctioning flue gas
desulfurization system becomes the only available unit to maintain a
part or all of the principal company's system emergency reserves and
the unit is operated in spinning reserve at the lowest practical
electric generation load consistent with not causing significant
physical damage to the unit. If the unit is operated at a higher load
to meet load demand, an emergency condition would not exist unless the
conditions under paragraph (1) of this definition apply.
    Emission limitation means any emissions limit or operating limit.
    Emission rate period means any calendar month included in a 12-
month rolling average period.
    Federally enforceable means all limitations and conditions that are
enforceable by the Administrator, including the requirements of 40 CFR
parts 60 and 61, requirements within any applicable State
implementation plan, and any permit requirements established under 40
CFR 52.21 or under 40 CFR 51.18 and 51.24.
    Fossil fuel means natural gas, petroleum, coal, and any form of
solid, liquid, or gaseous fuel derived from such material for the
purpose of creating useful heat.
    Gaseous fuel means any fuel derived from coal or petroleum that is
present as a gas at standard conditions and includes, but is not
limited to, refinery fuel gas, process gas, coke-oven gas, synthetic
gas, and gasified coal.
    Gross output means the gross useful work performed by the steam
generated and, for an IGCC electric utility steam generating unit, the
fuel burned in stationary combustion turbines. For a unit generating
only electricity, the gross useful work performed is the gross
electrical output from the unit's turbine/generator sets. For a
cogeneration unit, the gross useful work performed is the gross
electrical or mechanical output plus 75 percent of the useful thermal
output measured relative to ISO conditions that is not used to generate
additional electrical or mechanical output (i.e., steam delivered to an
industrial process).
    24-hour period means the period of time between 12:01 a.m. and
12:00 midnight.
    Integrated gasification combined cycle electric utility steam
generating unit or IGCC electric utility steam generating unit means a
coal-fired electric utility steam generating unit that burns a
synthetic gas derived from coal in a combined-cycle gas turbine. No
coal is directly burned in the unit during operation.
    Interconnected means that two or more electric generating units are
electrically tied together by a network of power transmission lines,
and other power transmission equipment.
    ISO conditions means a temperature of 288 Kelvin, a relative
humidity of 60 percent, and a pressure of 101.3 kilopascals.
    Lignite means coal that is classified as lignite A or B according
to the American Society of Testing and Materials in ASTM D388
(incorporated by reference, see Sec.  60.17).
    Natural gas means:
    (1) A naturally occurring mixture of hydrocarbon and nonhydrocarbon
gases found in geologic formations beneath the earth's surface, of
which the principal constituent is methane; or
    (2) Liquid petroleum gas, as defined by the American Society of
Testing and Materials in ASTM D1835 (incorporated by reference, see
Sec.  60.17); or
    (3) A mixture of hydrocarbons that maintains a gaseous state at ISO
conditions. Additionally, natural gas must either be composed of at
least 70 percent methane by volume or have a gross calorific value
between 34 and 43 megajoules (MJ) per standard cubic meter (910 and
1,150 Btu per standard cubic foot).
    Neighboring company means any one of those electric utility
companies with one or more electric power interconnections to the
principal company and which have geographically adjoining service
areas.
    Net-electric output means the gross electric sales to the utility
power distribution system minus purchased power on a calendar year
basis.
    Net system capacity means the sum of the net electric generating
capability (not necessarily equal to rated capacity) of all electric
generating equipment owned by an electric utility company (including
steam generating units, internal combustion engines, gas turbines,
nuclear units, hydroelectric units, and all other electric generating
equipment) plus firm contractual purchases that are interconnected to
the affected facility that has the malfunctioning flue gas
desulfurization system. The electric generating capability of equipment
under multiple ownership is prorated based on ownership unless the
proportional entitlement to electric output is otherwise established by
contractual arrangement.
    Noncontinental area means the State of Hawaii, the Virgin Islands,
Guam, American Samoa, the Commonwealth of Puerto Rico, or the Northern
Mariana Islands.
    Petroleum means crude oil or petroleum or a fuel derived from crude
oil or petroleum, including, but not limited to, distillate oil,
residual oil, and petroleum coke.
    Potential combustion concentration means the theoretical emissions
(nanograms per joule (ng/J), lb/MMBtu heat input) that would result
from combustion of a fuel in an uncleaned state without emission
control systems) and:
    (1) For particulate matter (PM) is:
    (i) 3,000 ng/J (7.0 lb/MMBtu) heat input for solid fuel; and
    (ii) 73 ng/J (0.17 lb/MMBtu) heat input for liquid fuels.
    (2) For sulfur dioxide (SO2) is determined under Sec.
60.50Da(c).
    (3) For nitrogen oxides (NOX) is:
    (i) 290 ng/J (0.67 lb/MMBtu) heat input for gaseous fuels;
    (ii) 310 ng/J (0.72 lb/MMBtu) heat input for liquid fuels; and
    (iii) 990 ng/J (2.30 lb/MMBtu) heat input for solid fuels.
    Potential electrical output capacity means 33 percent of the
maximum design heat input capacity of the steam generating unit,
divided by 3,413 Btu/KWh, divided by 1,000 kWh/MWh, and multiplied by
8,760 hr/yr (e.g., a steam generating unit with a 100 MW (340 MMBtu/hr)
fossil-fuel heat input capacity would have a 289,080 MWh 12 month
potential electrical output capacity). For electric utility combined
cycle gas turbines the potential electrical output capacity is
determined on the basis of the fossil-fuel firing

capacity of the steam generator exclusive of the heat input and
electrical power contribution by the gas turbine.
    Principal company means the electric utility company or companies
which own the affected facility.
    Resource recovery unit means a facility that combusts more than 75
percent non-fossil fuel on a quarterly (calendar) heat input basis.
    Responsible official means responsible official as defined in 40
CFR 70.2.
    Solid-derived fuel means any solid, liquid, or gaseous fuel derived
from solid fuel for the purpose of creating useful heat and includes,
but is not limited to, solvent refined coal, liquified coal, synthetic
gas, gasified coal, gasified petroleum coke, gasified biomass, and
gasified tire derived fuel.
    Spare flue gas desulfurization system module means a separate
system of SO2 emission control equipment capable of treating
an amount of flue gas equal to the total amount of flue gas generated
by an affected facility when operated at maximum capacity divided by
the total number of nonspare flue gas desulfurization modules in the
system.
    Spinning reserve means the sum of the unutilized net generating
capability of all units of the electric utility company that are
synchronized to the power distribution system and that are capable of
immediately accepting additional load. The electric generating
capability of equipment under multiple ownership is prorated based on
ownership unless the proportional entitlement to electric output is
otherwise established by contractual arrangement.
    Steam generating unit means any furnace, boiler, or other device
used for combusting fuel for the purpose of producing steam (including
fossil-fuel-fired steam generators associated with combined cycle gas
turbines; nuclear steam generators are not included).
    Subbituminous coal means coal that is classified as subbituminous
A, B, or C according to the American Society of Testing and Materials
in ASTM D388 (incorporated by reference, see Sec.  60.17).
    System emergency reserves means an amount of electric generating
capacity equivalent to the rated capacity of the single largest
electric generating unit in the electric utility company (including
steam generating units, internal combustion engines, gas turbines,
nuclear units, hydroelectric units, and all other electric generating
equipment) which is interconnected with the affected facility that has
the malfunctioning flue gas desulfurization system. The electric
generating capability of equipment under multiple ownership is prorated
based on ownership unless the proportional entitlement to electric
output is otherwise established by contractual arrangement.
    System load means the entire electric demand of an electric utility
company's service area interconnected with the affected facility that
has the malfunctioning flue gas desulfurization system plus firm
contractual sales to other electric utility companies. Sales to other
electric utility companies (e.g., emergency power) not on a firm
contractual basis may also be included in the system load when no
available system capacity exists in the electric utility company to
which the power is supplied for sale.
    Wet flue gas desulfurization technology or wet FGD means a
SO2 control system that is located downstream of the steam
generating unit and removes sulfur oxides from the combustion gases of
the steam generating unit by contacting the combustion gases with an
alkaline slurry or solution and forming a liquid material. This
definition applies to devices where the aqueous liquid material product
of this contact is subsequently converted to other forms. Alkaline
reagents used in wet FGD technology include, but are not limited to,
lime, limestone, and sodium.

Sec.  60.42Da  Standard for particulate matter (PM).

    (a) On and after the date on which the initial performance test is
completed or required to be completed under Sec.  60.8, whichever date
comes first, no owner or operator subject to the provisions of this
subpart shall cause to be discharged into the atmosphere from any
affected facility for which construction, reconstruction, or
modification commenced before or on February 28, 2005, any gases that
contain PM in excess of:
    (1) 13 ng/J (0.03 lb/MMBtu) heat input derived from the combustion
of solid, liquid, or gaseous fuel;
    (2) 1 percent of the potential combustion concentration (99 percent
reduction) when combusting solid fuel; and
    (3) 30 percent of potential combustion concentration (70 percent
reduction) when combusting liquid fuel.
    (b) On and after the date the initial PM performance test is
completed or required to be completed under Sec.  60.8, whichever date
comes first, no owner or operator subject to the provisions of this
subpart shall cause to be discharged into the atmosphere from any
affected facility any gases which exhibit greater than 20 percent
opacity (6-minute average), except for one 6-minute period per hour of
not more than 27 percent opacity.
    (c) Except as provided in paragraph (d) of this section, on and
after the date on which the initial performance test is completed or
required to be completed under Sec.  60.8, whichever date comes first,
no owner or operator of an affected facility that commenced
construction, reconstruction, or modification after February 28, 2005
shall cause to be discharged into the atmosphere from that affected
facility any gases that contain PM in excess of either:
    (1) 18 ng/J (0.14 lb/MWh) gross energy output; or
    (2) 6.4 ng/J (0.015 lb/MMBtu) heat input derived from the
combustion of solid, liquid, or gaseous fuel.
    (d) As an alternative to meeting the requirements of paragraph (c)
of this section, the owner or operator of an affected facility for
which construction, reconstruction, or modification commenced after
February 28, 2005, may elect to meet the requirements of this
paragraph. On and after the date on which the initial performance test
is completed or required to be completed under Sec.  60.8, whichever
date comes first, no owner or operator of an affected facility shall
cause to be discharged into the atmosphere from that affected facility
for which construction, reconstruction, or modification commenced after
February 28, 2005, any gases that contain PM in excess of:
    (1) 13 ng/J (0.03 lb/MMBtu) heat input derived from the combustion
of solid, liquid, or gaseous fuel, and
    (2) 0.1 percent of the combustion concentration determined
according to the procedure in Sec.  60.48Da(o)(5) (99.9 percent
reduction) for an affected facility for which construction or
reconstruction commenced after February 28, 2005 when combusting solid,
liquid, or gaseous fuel, or
    (3) 0.2 percent of the combustion concentration determined
according to the procedure in Sec.  60.48Da(o)(5) (99.8 percent
reduction) for an affected facility for which modification commenced
after February 28, 2005 when combusting solid, liquid, or gaseous fuel.

Sec.  60.43Da  Standard for sulfur dioxide (SO2).

    (a) On and after the date on which the initial performance test is
completed or required to be completed under Sec.  60.8, whichever date
comes first, no owner or operator subject to the provisions of this
subpart shall cause to be discharged into the atmosphere from any
affected facility which combusts solid fuel or

solid-derived fuel and for which construction, reconstruction, or
modification commenced before or on February 28, 2005, except as
provided under paragraphs (c), (d), (f) or (h) of this section, any
gases that contain SO2 in excess of:
    (1) 520 ng/J (1.20 lb/MMBtu) heat input and 10 percent of the
potential combustion concentration (90 percent reduction); or
    (2) 30 percent of the potential combustion concentration (70
percent reduction), when emissions are less than 260 ng/J (0.60 lb/
MMBtu) heat input.
    (b) On and after the date on which the initial performance test is
completed or required to be completed under Sec.  60.8, whichever date
comes first, no owner or operator subject to the provisions of this
subpart shall cause to be discharged into the atmosphere from any
affected facility which combusts liquid or gaseous fuels (except for
liquid or gaseous fuels derived from solid fuels and as provided under
paragraphs (e) or (h) of this section) and for which construction,
reconstruction, or modification commenced before or on February 28,
2005, any gases that contain SO2 in excess of:
    (1) 340 ng/J (0.80 lb/MMBtu) heat input and 10 percent of the
potential combustion concentration (90 percent reduction); or
    (2) 100 percent of the potential combustion concentration (zero
percent reduction) when emissions are less than 86 ng/J (0.20 lb/MMBtu)
heat input.
    (c) On and after the date on which the initial performance test is
completed or required to be completed under Sec.  60.8, whichever date
comes first, no owner or operator subject to the provisions of this
subpart shall cause to be discharged into the atmosphere from any
affected facility which combusts solid solvent refined coal (SRC-I) any
gases that contain SO2 in excess of 520 ng/J (1.20 lb/MMBtu)
heat input and 15 percent of the potential combustion concentration (85
percent reduction) except as provided under paragraph (f) of this
section; compliance with the emission limitation is determined on a 30-
day rolling average basis and compliance with the percent reduction
requirement is determined on a 24-hour basis.
    (d) Sulfur dioxide emissions are limited to 520 ng/J (1.20 lb/
MMBtu) heat input from any affected facility which:
    (1) Combusts 100 percent anthracite;
    (2) Is classified as a resource recovery unit; or
    (3) Is located in a noncontinental area and combusts solid fuel or
solid-derived fuel.
    (e) Sulfur dioxide emissions are limited to 340 ng/J (0.80 lb/
MMBtu) heat input from any affected facility which is located in a
noncontinental area and combusts liquid or gaseous fuels (excluding
solid-derived fuels).
    (f) The emission reduction requirements under this section do not
apply to any affected facility that is operated under an SO2
commercial demonstration permit issued by the Administrator in
accordance with the provisions of Sec.  60.47Da.
    (g) Compliance with the emission limitation and percent reduction
requirements under this section are both determined on a 30-day rolling
average basis except as provided under paragraph (c) of this section.
    (h) When different fuels are combusted simultaneously, the
applicable standard is determined by proration using the following
formula:
    (1) If emissions of SO2 to the atmosphere are greater
than 260 ng/J (0.60 lb/MMBtu) heat input
[GRAPHIC] [TIFF OMITTED] TR13JN07.008

    (2) If emissions of SO2 to the atmosphere are equal to
or less than 260 ng/J (0.60 lb/MMBtu) heat input:
[GRAPHIC] [TIFF OMITTED] TR13JN07.009

Where:

Es = Prorated SO2 emission limit (ng/J heat
input);
%Ps = Percentage of potential SO2 emission
allowed;
x = Percentage of total heat input derived from the combustion of
liquid or gaseous fuels (excluding solid-derived fuels); and
y = Percentage of total heat input derived from the combustion of
solid fuel (including solid-derived fuels).

    (i) Except as provided in paragraphs (j) and (k) of this section,
on and after the date on which the initial performance test is
completed or required to be completed under Sec.  60.8, whichever date
comes first, no owner or operator of an affected facility that
commenced construction, reconstruction, or modification commenced after
February 28, 2005 shall cause to be discharged into the atmosphere from
that affected facility, any gases that contain SO2 in excess
of the applicable emission limitation specified in paragraphs (i)(1)
through (3) of this section.
    (1) For an affected facility for which construction commenced after
February 28, 2005, any gases that contain SO2 in excess of
either:
    (i) 180 ng/J (1.4 lb/MWh) gross energy output on a 30-day rolling
average basis; or
    (ii) 5 percent of the potential combustion concentration (95
percent reduction) on a 30-day rolling average basis.
    (2) For an affected facility for which reconstruction commenced
after February 28, 2005, any gases that contain SO2 in
excess of either:
    (i) 180 ng/J (1.4 lb/MWh) gross energy output on a 30-day rolling
average basis;
    (ii) 65 ng/J (0.15 lb/MMBtu) heat input on a 30-day rolling average
basis; or
    (iii) 5 percent of the potential combustion concentration (95
percent reduction) on a 30-day rolling average basis.
    (3) For an affected facility for which modification commenced after
February 28, 2005, any gases that contain SO2 in excess of
either:
    (i) 180 ng/J (1.4 lb/MWh) gross energy output on a 30-day rolling
average basis;
    (ii) 65 ng/J (0.15 lb/MMBtu) heat input on a 30-day rolling average
basis; or
    (iii) 10 percent of the potential combustion concentration (90
percent reduction) on a 30-day rolling average basis.
    (j) On and after the date on which the initial performance test is
completed or required to be completed under Sec.  60.8, whichever date
comes first, no owner or operator of an affected facility that
commenced construction, reconstruction, or modification commenced after
February 28, 2005, and that burns 75 percent or more (by heat input)
coal refuse on a 12-month rolling average basis, shall caused to be
discharged into the atmosphere from that affected facility any gases
that contain SO2 in excess of the applicable emission
limitation specified in paragraphs (j)(1) through (3) of this section.
    (1) For an affected facility for which construction commenced after
February

28, 2005, any gases that contain SO2 in excess of either:
    (i) 180 ng/J (1.4 lb/MWh) gross energy output on a 30-day rolling
average basis; or
    (ii) 6 percent of the potential combustion concentration (94
percent reduction) on a 30-day rolling average basis.
    (2) For an affected facility for which reconstruction commenced
after February 28, 2005, any gases that contain SO2 in
excess of either:
    (i) 180 ng/J (1.4 lb/MWh) gross energy output on a 30-day rolling
average basis;
    (ii) 65 ng/J (0.15 lb/MMBtu) heat input on a 30-day rolling average
basis; or
    (iii) 6 percent of the potential combustion concentration (94
percent reduction) on a 30-day rolling average basis.
    (3) For an affected facility for which modification commenced after
February 28, 2005, any gases that contain SO2 in excess of
either:
    (i) 180 ng/J (1.4 lb/MWh) gross energy output on a 30-day rolling
average basis;
    (ii) 65 ng/J (0.15 lb/MMBtu) heat input on a 30-day rolling average
basis; or
    (iii) 10 percent of the potential combustion concentration (90
percent reduction) on a 30-day rolling average basis.
    (k) On and after the date on which the initial performance test is
completed or required to be completed under Sec.  60.8, whichever date
comes first, no owner or operator of an affected facility located in a
noncontinental area that commenced construction, reconstruction, or
modification commenced after February 28, 2005, shall cause to be
discharged into the atmosphere from that affected facility any gases
that contain SO2 in excess of the applicable emission
limitation specified in paragraphs (k)(1) and (2) of this section.
    (1) For an affected facility that burns solid or solid-derived
fuel, the owner or operator shall not cause to be discharged into the
atmosphere any gases that contain SO2 in excess of 520 ng/J
(1.2 lb/MMBtu) heat input on a 30-day rolling average basis.
    (2) For an affected facility that burns other than solid or solid-
derived fuel, the owner or operator shall not cause to be discharged
into the atmosphere any gases that contain SO2 in excess of
if the affected facility or 230 ng/J (0.54 lb/MMBtu) heat input on a
30-day rolling average basis.

Sec.  60.44Da  Standard for nitrogen oxides (NOX).

    (a) On and after the date on which the initial performance test is
completed or required to be completed under Sec.  60.8, whichever date
comes first, no owner or operator subject to the provisions of this
subpart shall cause to be discharged into the atmosphere from any
affected facility, except as provided under paragraphs (b), (d), (e),
and (f) of this section, any gases that contain NOX
(expressed as NO2) in excess of the following emission
limits, based on a 30-day rolling average basis, except as provided
under Sec.  60.48Da(j)(1):
    (1) NOX emission limits.

------------------------------------------------------------------------
                                                     Emission limit for
                                                         heat input
                     Fuel type                     ---------------------
                                                       ng/J     lb/MMBtu
------------------------------------------------------------------------
Gaseous fuels:
    Coal-derived fuels............................        210       0.50
    All other fuels...............................         86       0.20
Liquid fuels:
    Coal-derived fuels............................        210       0.50
    Shale oil.....................................        210       0.50
    All other fuels...............................        130       0.30
Solid fuels:
    Coal-derived fuels............................        210       0.50
    Any fuel containing more than 25%, by weight,       \(1)\      \(1)\
     coal refuse..................................
    Any fuel containing more than 25%, by weight,         340       0.80
     lignite if the lignite is mined in North
     Dakota, South Dakota, or Montana, and is
     combusted in a slag tap furnace \2\..........
    Any fuel containing more than 25%, by weight,         260       0.60
     lignite not subject to the 340 ng/J heat
     input emission limit \2\.....................
    Subbituminous coal............................        210       0.50
    Bituminous coal...............................        260       0.60
    Anthracite coal...............................        260       0.60
    All other fuels...............................        260       0.60
------------------------------------------------------------------------
\1\ Exempt from NOX standards and NOX monitoring requirements.
\2\ Any fuel containing less than 25%, by weight, lignite is not
  prorated but its percentage is added to the percentage of the
  predominant fuel.

    (2) NOX reduction requirement.

------------------------------------------------------------------------
                                                             Percent
                                                          reduction of
                       Fuel type                            potential
                                                           combustion
                                                          concentration
------------------------------------------------------------------------
Gaseous fuels.........................................                25
Liquid fuels..........................................                30
Solid fuels...........................................                65
------------------------------------------------------------------------

    (b) The emission limitations under paragraph (a) of this section do
not apply to any affected facility which is combusting coal-derived
liquid fuel and is operating under a commercial demonstration permit
issued by the Administrator in accordance with the provisions of Sec.
60.47Da.
    (c) Except as provided under paragraphs (d), (e), and (f) of this
section, when two or more fuels are combusted simultaneously, the
applicable standard is determined by proration using the following
formula:
[GRAPHIC] [TIFF OMITTED] TR13JN07.010

Where:

En = Applicable standard for NOX when multiple
fuels are combusted simultaneously (ng/J heat input);
w = Percentage of total heat input derived from the combustion of
fuels subject to the 86 ng/J heat input standard;
x = Percentage of total heat input derived from the combustion of
fuels subject to the 130 ng/J heat input standard;
y = Percentage of total heat input derived from the combustion of
fuels subject to the 210 ng/J heat input standard;
z = Percentage of total heat input derived from the combustion of
fuels subject to the 260 ng/J heat input standard; and
v = Percentage of total heat input delivered from the combustion of
fuels subject to the 340 ng/J heat input standard.

    (d)(1) On and after the date on which the initial performance test
is completed

or required to be completed under Sec.  60.8, whichever date comes
first, no owner or operator of an affected facility that commenced
construction after July 9, 1997, but before or on February 28, 2005
shall cause to be discharged into the atmosphere any gases that contain
NOX (expressed as NO2) in excess of 200 ng/J (1.6
lb/MWh) gross energy output, based on a 30-day rolling average basis,
except as provided under Sec.  60.48Da(k).
    (2) On and after the date on which the initial performance test is
completed or required to be completed under Sec.  60.8, whichever date