[Federal Register Volume 77, Number 168 (Wednesday, August 29, 2012)]
[Proposed Rules]
[Pages 52553-52581]
[FR Doc No: 2012-20524]

Vol. 77

Wednesday,

No. 168

August 29, 2012

Part III

Environmental Protection Agency

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40 CFR Part 60

Standards of Performance for Stationary Gas Turbines; Standards of
Performance for Stationary Combustion Turbines; Proposed Rule

Federal Register / Vol. 77 , No. 168 / Wednesday, August 29, 2012 /
Proposed Rules

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ENVIRONMENTAL PROTECTION AGENCY

40 CFR Part 60

[EPA-HQ-OAR-2004-0490; FRL-9695-6]
RIN 2060-AQ29

Standards of Performance for Stationary Gas Turbines; Standards
of Performance for Stationary Combustion Turbines

AGENCY: Environmental Protection Agency (EPA).

ACTION: Proposed rule.

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SUMMARY: The EPA is proposing to amend the new source performance
standards (NSPS) for stationary gas turbines and stationary combustion
turbines. These amendments are primarily in response to issues raised
by the regulated community. On July 6, 2006, the EPA promulgated
amendments to the new source performance standards for stationary
combustion turbines. On September 5, 2006, the Utility Air Regulatory
Group filed a petition for reconsideration of certain aspects of the
promulgated standards. The EPA is proposing to amend specific
provisions in the NSPS to resolve issues and questions raised by the
petition for reconsideration, and to address other technical and
editorial issues. In addition, this proposed rule would amend the
location and wording of existing paragraphs for clarity. The proposed
amendments would increase the environmental benefits of the existing
requirements because the emission standards would apply at all times.
The proposed amendments would also promote efficiency by recognizing
the environmental benefit of combined heat and power and the beneficial
use of low energy content gases.

DATES: Comments must be received on or before October 29, 2012.
    Public Hearing. If anyone contacts the EPA by September 10, 2012
requesting to speak at a public hearing, the EPA will hold a public
hearing on or about September 13, 2012.

ADDRESSES: Submit your comments, identified by Docket ID No. EPA-HQ-
OAR-2004-0490, by one of the following methods:
     http://www.regulations.gov: Follow the on-line
instructions for submitting comments.
     Email<EMAIL_ADDRESS>     Fax:<PHONE_NUMBER>.
     Mail: Air and Radiation Docket, U.S. EPA, Mail Code 6102T,
1200 Pennsylvania Ave. NW., Washington, DC 20460. Please include a
total of two copies.
     Hand Delivery: EPA Docket Center, Docket ID Number EPA-HQ-
OAR-2004-0490, EPA West Building, 1301 Constitution Ave. NW., Room
3334, Washington, DC, 20004. Such deliveries are accepted only during
the Docket's normal hours of operation, and special arrangements should
be made for deliveries of boxed information.
    Instructions: Direct your comments to Docket ID No. EPA-HQ-OAR-
2004-0490. The EPA's policy is that all comments received will be
included in the public docket without change and may be made available
online at http://www.regulations.gov, including any personal
information provided, unless the comment includes information claimed
to be Confidential Business Information (CBI) or other information
whose disclosure is restricted by statute. Do not submit information
that you consider to be CBI or otherwise protected through
regulations.gov or email. Send or deliver information identified as CBI
only to the following address: Roberto Morales, OAQPS Document Control
Officer (C404-02), Office of Air Quality Planning and Standards,
Environmental Protection Agency, Research Triangle Park, North Carolina
27711, Attention Docket ID No. EPA-HQ-OAR-2004-0490. Clearly mark the
part or all of the information that you claim to be CBI. For CBI
information in a disk or CD-ROM that you mail to the EPA, mark the
outside of the disk or CD-ROM as CBI and then identify electronically
within the disk or CD-ROM the specific information that is claimed as
CBI. In addition to one complete version of the comment that includes
information claimed as CBI, a copy of the comment that does not contain
the information claimed as CBI must be submitted for inclusion in the
public docket. Information so marked will not be disclosed except in
accordance with procedures set forth in 40 CFR part 2. The http://www.regulations.gov Web site is an ``anonymous access'' system, which
means the EPA will not know your identity or contact information unless
you provide it in the body of your comment. If you send an email
comment directly to the EPA without going through www.regulations.gov,
your email address will be automatically captured and included as part
of the comment that is placed in the public docket and made available
on the Internet. If you submit an electronic comment, the EPA
recommends that you include your name and other contact information in
the body of your comment and with any disk or CD-ROM you submit. If the
EPA cannot read your comment due to technical difficulties and cannot
contact you for clarification, the EPA may not be able to consider your
comment. Electronic files should avoid the use of special characters,
any form of encryption, and be free of any defects or viruses. For
additional information about the EPA's public docket visit the EPA
Docket Center homepage at http://www.epa.gov/dockets/.
    Docket: All documents in the docket are listed in the http://www.regulations.gov index. Although listed in the index, some
information is not publicly available, e.g., CBI or other information
whose disclosure is restricted by statute. Certain other material, such
as copyrighted material, will be publicly available only in hard copy.
Publicly available docket materials are available either electronically
in http://www.regulations.gov or in hard copy at the Air and Radiation
Docket EPA/DC, 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 and Radiation Docket is<PHONE_NUMBER>.
    Public Hearing: If a public hearing is requested, it will be held
at the EPA Facility Complex in Research Triangle Park, North Carolina
or at an alternate site nearby. Contact Ms. Pamela Garrett at (919)
541-7966 to request a hearing, to request to speak at a public hearing,
to determine if a hearing will be held, or to determine the hearing
location.

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 (email) address:
<EMAIL_ADDRESS>
SUPPLEMENTARY INFORMATION: Regulated Entities: Entities potentially
affected by this proposed action include, but are not limited to, the
following:

------------------------------------------------------------------------
                                                 Examples of regulated
             Category               NAICS \1\           entities
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Industry..........................       2211  Electric services.
                                       486210  Natural gas transmission.
                                       211111  Crude petroleum and
                                                natural gas.
                                       211112  Natural gas liquids.
                                          221  Electric and other
                                                services, combined.
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\1\ North American Industry Classification System (NAICS) code.

    This table is not intended to be exhaustive, but rather provides a
guide for readers regarding entities likely to be regulated by this
proposed rule. To determine whether your facility is regulated by this
proposed rule, you should examine the applicability criteria in
Sec. Sec.  60.4305 and 60.4310. If you have any questions regarding the
applicability of this proposed rule to a particular entity, contact the
person listed in the preceding FOR FURTHER INFORMATION CONTACT section.
    WorldWide Web (WWW): Following the Administrator's signature, a
copy of the proposed amendments will be posted on the Technology
Transfer Network's (TTN) policy and guidance page for newly proposed or
promulgated rules at http://www.epa.gov/ttn/oarpg. The TTN provides
information and technology exchange in various areas of air pollution
control.
    Outline: The information presented in this preamble is organized as
follows:

I. Background
II. Proposed Amendments
    A. Applicability
    B. NOX Emissions Standard
    C. SO2 Emissions Standard
    D. Malfunction Affirmative Defense
    E. Electronic Data Submittal
    F. Additional Proposed Amendments
    G. Additional Request for Comments
III. Statutory and Executive Order Reviews
    A. Executive Order 12866: Regulatory Planning and Review and
Executive Order 13563: Improving Regulation and Regulatory Review
    B. Paperwork Reduction Act
    C. Regulatory Flexibility Act
    D. Unfunded Mandates Reform Act (UMRA)
    E. Executive Order 13132: Federalism
    F. Executive Order 13175: Consultation and Coordination with
Indian Tribal Governments
    G. Executive Order 13045: Protection of Children from
Environmental Health and Safety Risks
    H. Executive Order 13211: Actions Concerning Regulations That
Significantly Affect Energy Supply, Distribution, or Use
    I. National Technology Transfer Advancement Act
    J. Executive Order 12898: Federal Actions to Address
Environmental Justice in Minority Populations and Low-Income
Populations.

I. Background

    On July 6, 2006, the EPA promulgated revised new source performance
standards (NSPS) for stationary combustion turbines (subpart KKKK of 40
CFR part 60) applicable to stationary combustion turbines on which
construction, modification or reconstruction is commenced after
February 18, 2005 (71 FR 38482). The new standards in subpart KKKK
reflect advances in turbine design and nitrogen oxide (NOX)
emission control technologies since the standards for these units were
originally promulgated in 1979 in subpart GG of 40 CFR part 60 (44 FR
52798). The new standards also reflect the use of lower sulfur fuels.
    A petition for reconsideration of the revised NSPS was filed by the
Utility Air Regulatory Group on September 5, 2006. The EPA has decided
to grant reconsideration of subpart KKKK to the extent specified in
this proposed rule. The amendments proposed by this action address
issues for which the petitioners specifically requested reconsideration
(see docket entry EPA-HQ-OAR-2004-0490-0325) and other matters as
described below.
    As part of this action, the EPA is also proposing to amend other
rule language to correct technical omissions, typographical errors,
grammatical errors and to address various other issues that have been
identified since promulgation. A significant issue identified since
promulgation is the development of new stationary combustion
technologies that are capable of burning a variety of low-British
thermal units (Btu) gases. The amendments proposed in this action
include amending the sulfur dioxide (SO2) standard for all
low-Btu gases similar to the biogas (i.e., landfill gas) standard
currently in subpart KKKK. The proposed amendments would not change the
EPA's original projections for this proposed rule's compliance costs,
environmental benefits, burden on industry or the number of affected
facilities. The EPA is also proposing limited conforming amendments to
subpart GG.
    Finally, the EPA is proposing to amend subpart KKKK to exempt some
stationary combustion turbines from the emission standards in subpart
KKKK. First, owners/operators of stationary combustion turbines that
meet the applicability criteria of, and that are complying with the
SO2 standard in, either subpart J or Ja (standards of
performance for petroleum refineries) would be exempt from complying
with the otherwise applicable SO2 standard in subpart KKKK.
In addition, owners/operators of stationary combustion turbines covered
that meet the applicability criteria of, and that are complying with
the SO2 and NOX standards in subparts Ea, Eb, Cd,
AAAA or BBBB (the municipal solid waste regulations) would be exempt
from complying with the otherwise applicable SO2 and
NOX standards in subpart KKKK.

II. Proposed Amendments

    We are proposing to amend subparts GG and KKKK of 40 CFR part 60 to
clarify the intent in applying and implementing specific rule
requirements, to correct unintentional technical omissions and
editorial errors, and address various other issues that have been
identified since the promulgation of subpart KKKK. A summary of the
proposed substantive amendments to the NSPS for stationary combustion
turbines and the rationale for these amendments are below.
    In addition, we are proposing to amend 40 CFR 60.17 (incorporations
by reference) and republish subpart KKKK in its entirety. The proposed
amendments include updating 40 CFR 60.17 to include additional test
methods identified in subpart KKKK and revising the wording and writing
style to clarify the requirements of the NSPS. We do not intend for
these editorial revisions to substantively change any of the technical
or administrative requirements of the subpart and have concluded that
they do not do so. To the extent that we determine that the editorial
revisions do effect any unintended substantive changes, we will correct
the problem in taking final action on the proposed rule.

A. Applicability

    We are proposing to make five amendments to the applicability of
subpart KKKK of 40 CFR part 60. First,

the combustion turbine engine (the air compressor, combustor and
turbine sections) is the primary source of emissions from a stationary
combustion turbine. However, due to the broad definition of the
affected facility in subpart KKKK, the combustion turbine engine does
not necessarily constitute the majority of the costs of a new
stationary combustion turbine. The expanded definition of a stationary
combustion turbine in subpart KKKK is intended to simplify compliance
and recognize the environmental benefit of heat recovery at combined
cycle and combined heat and power (CHP) facilities. It is not intended
to change the circumstances in which a turbine engine is designated as
new or reconstructed. However, under subpart KKKK it is not clear
whether a CHP or combined cycle facility that replaces the turbine
engine would be considered ``new'' or ``reconstructed.'' The existing
language in subpart KKKK could be interpreted to mean that replacement
of a turbine engine with a new turbine engine at an existing combined
cycle or CHP facility not currently subject to subpart KKKK would
result in the new turbine engine being subject to subpart GG. In that
case, the heat recovery steam generator (HRSG) would continue to comply
with the same boiler NSPS as prior to the turbine engine replacement
and two NSPS would apply to the facility. It was clearly not the intent
when subpart KKKK was promulgated that these turbine engines would only
be subject to emission control technologies that were available in the
1970s. In this situation, combustion controls have the same cost
effectiveness as other new or reconstructed turbine engines. In
addition, compliance is minimally impacted by the design of the HRSG,
so there is no reason that two pieces of equipment should not be
combined. Since the subpart KKKK standards are input-based, with
optional alternative output-based standards, the efficiency of the HRSG
is not essential for demonstrating compliance. Further, the presence of
duct burners should not significantly impact the emissions rate since
typical low NOX natural gas-fired duct burners contribute
between 15 to 25 parts per million (ppm) NOX corrected to 15
percent oxygen (O2) and ultra low NOX duct
burners are available that only contribute approximately 3 ppm
NOX corrected to 15 percent O2. Therefore, while
we are maintaining the broad definition of an affected facility, we are
proposing that for the purposes of determining applicability and if a
stationary combustion turbine is ``new'' or ``reconstructed,'' only the
combustion turbine engine itself will be considered. This approach
reflects the environmental benefits of heat recovery and output-based
standards and was the intent of the original rule. This rule as amended
would make it clear that the replacement of a turbine engine at a CHP
or combined cycle facility that is not currently subject to subpart
KKKK with a new turbine engine would result in the establishment of a
new stationary combustion turbine under subpart KKKK, as was intended
when subpart KKKK was promulgated. Furthermore, the addition of a new
turbine engine to an existing HRSG would result in the establishment of
a new stationary combustion turbine under subpart KKKK that includes
the existing heat recovery steam generating unit. However, the
construction or reconstruction of a HRSG associated with a turbine
engine covered by subpart GG would not result in the entire facility
being subject to subpart KKKK. A positive aspect of this approach is
that the most current subpart KKKK requirements would apply to turbine
engines that are replaced at combined cycle and CHP facilities already
subject to subpart KKKK.
    In the event the final rule does not include this clarification,
the stationary combustion engine replaced at an existing combined cycle
or CHP facility would be covered by subpart GG, and the HRSG would be
covered by the applicable steam generating unit NSPS. Subpart GG would
be amended to include NOX emission standards for turbine
engines that are identical to those in Table 1 of subpart KKKK. The
subpart GG SO2 emission standards and the monitoring,
testing and reporting requirements would also be amended to be
identical to the requirements for simple cycle turbines subject to
subpart KKKK. With this approach, subpart GG would have to be amended
each time that the subpart KKKK standards are amended. To provide
additional compliance flexibility, we would add the ability for owners/
operators of new and reconstructed turbine engine replacements at
existing combined cycle and CHP facilities to petition the
Administrator to voluntarily comply with the new and reconstructed
requirements, as applicable, in subpart KKKK as an alternative to
demonstrating compliance with amended subpart GG and applicable boiler
NSPS separately. This approach would provide an equivalent amount of
environmental protection as the previously described approach. However,
we have concluded that the previously described approach avoids
petition requirement and would reduce the regulatory burden of the
proposed rule. We specifically request comment on the level of
environmental protection and regulatory burden for each approach. A
disadvantage of this approach is that the most current subpart KKKK
requirements would not apply to turbine engines that are replaced at
combined cycle and CHP facilities already subject to subpart KKKK. We
are requesting comment if this approach could be amended to assure that
future amended subpart KKKK requirements would apply to new and
reconstructed turbine engines.
    Second, we are proposing to exempt owners/operators of stationary
combustion turbines that meet the applicability requirements and that
are complying with the SO2 standard in either subparts J or
Ja of 40 CFR part 60 (Standards of performance for petroleum
refineries) from complying with the otherwise applicable SO2
standard in subpart KKKK. The SO2 standard in both subparts
J and Ja is more stringent than in subpart KKKK, so this proposed
amendment would simplify compliance for owner/operators of petroleum
refineries without an increase in pollutant emissions. In addition,
owners/operators of stationary combustion turbines covered that meet
the applicability criteria of, and that are complying with, the
SO2 and NOX standards in subparts Ea, Eb, Cd,
AAAA or BBBB (the municipal solid waste regulations) would be exempt
from complying with the otherwise applicable SO2 and
NOX standards in subpart KKKK. The SO2 standards
in the municipal solid waste rules are more stringent than in subpart
KKKK, so this proposed amendment would simplify compliance for owner/
operators of petroleum refineries without an increase in pollutant
emissions.
    Third, we are proposing to exempt owners/operators of stationary
combustion turbines that are subject to a federally enforceable permit
limiting fuel to gaseous fuels containing no more than 20 grains of
sulfur per 100 standard cubic feet (scf) and/or liquid fuels containing
no more than 0.050 weight percent sulfur (500 ppm sulfur by weight)
from the SO2 standard. Both of these fuels have potential
SO2 emissions of less than 0.060 pounds per million British
thermal units (lb/MMBtu) and would be in compliance with the
SO2 standard. The proposed amendment would reduce the burden
for owners/operators burning natural gas and

distillate oil of complying with subpart KKKK by limiting reporting and
recordkeeping costs without increasing emissions.
    Fourth, we are proposing to allow owners/operators of stationary
combustion turbines currently covered by subpart GG and any associated
steam generating unit subject to an NSPS to have the option to petition
the Administrator to comply with subpart KKKK in lieu of complying with
subpart GG and any associated steam generating unit NSPS. Since the
applicability of subpart KKKK encompasses any associated heat recovery
equipment, owners/operators would have the flexibility to comply with
one NSPS instead of multiple NSPS. The Administrator will only grant
the petition if he/she determines that compliance with subpart KKKK
would be equivalent to, or more stringent than, compliance with subpart
GG and any associated steam generating unit NSPS. For example, assuming
equal amounts of fuel are combusted in the turbine and duct burners
(HRSG), an existing oil-fired combined cycle combustion turbine subject
separately to subpart GG and subpart Db of 40 CFR part 60 would have an
equivalent combined NOX emissions standard of approximately
65 parts per million (ppm). By contrast, the subpart KKKK
NOX standard for modified turbines burning fuels other than
natural gas is 96 ppm. The Administrator would, therefore, deny the
petition in such circumstances. We have concluded that this is only an
issue for turbines burning fuels other than natural gas. Also, we are
clarifying that if any solid fuel as defined in subpart KKKK is burned
in the HRSG, the HRSG would be covered by the applicable steam
generating unit NSPS and not subpart KKKK. We are not aware of any
existing stationary combustion turbines that burn solid fuel in the
HRSG, but the intent of this proposed rule is to cover only liquid and
gaseous fuels. The amendment would prevent a large solid fuel-fired
boiler from using the exhaust from a combustion turbine engine in order
to avoid the requirements of the applicable steam generating unit NSPS.
    Finally, we are requesting comment on how to address combustion
turbine engines that are overhauled or refurbished off site in such a
manner that neither the owner, operator nor manufacturer can identify
which components have been replaced and, therefore, cannot conduct the
otherwise required reconstruction analysis. The owner/operator of a
turbine engine that is overhauled or refurbished in such a manner that
each individual component of the engine is tracked would still perform
the traditional reconstruction analysis, i.e., the owner/operator would
compare the total cost of replacement components with the cost of a
comparable new turbine engine. In general, a reconstructed facility is
one which has had components replaced to the extent that the fixed
capital costs of the new components exceeds 50 percent of the fixed
capital cost that would be required to construct a comparable entirely
new facility. (See 40 CFR 60.15.)
    We are requesting comment on two potential approaches for dealing
with circumstances where there is insufficient information to determine
which components of a particular combustion turbine engine have been
replaced. The first approach would base the reconstruction test on
changes to the combustor alone. (That is, the test would be whether the
fixed capital cost of the replacement combustor exceeds 50 percent of
the fixed capital cost that would be required to install a comparable
new combustor.) The alternate approach would be based on the number of
times a particular turbine engine has been refurbished. Potential
language for both approaches is as follows:

    1. An overhauled or refurbished turbine engine where neither the
owner/operator nor manufacturer can identify which components have
been replaced shall be considered reconstructed if the combustor
itself is either replaced or reconstructed (as specified under Sec.
60.15). When such information is known, an owner or operator of a
turbine engine that is overhauled or refurbished shall perform a
reconstruction analysis on the entire turbine engine as described
under Sec.  60.15.

    The corresponding definition for a combustor would be:

    A combustor means a component or area in a combustion turbine
engine where fuel is added to the pressurized air molecules and
combustion takes place. It is also known as a burner or flame can.
    2. An overhauled or refurbished turbine engine where neither the
owner/operator nor manufacturer can identify which components have
been replaced during the most recent and previous two refurbishments
shall be considered reconstructed. When such information is known,
an owner or operator of a turbine engine that is overhauled or
refurbished shall perform a reconstruction analysis on the turbine
engine as described under Sec.  60.15.

    If this provision is adopted, it would provide an owner/operator
with relative certainty that they could potentially operate a
combustion turbine for approximately 90,000 hours, or over 10 years of
continuous operation, before triggering the reconstruction provisions
in subpart KKKK. (Assuming that turbine exchanges take place at
approximately 30,000 operating hour intervals.) This approach would
provide relative regulatory certainty for both the owner/operator of
the combustion turbine and the turbine manufacturer.
    We are also requesting comment on the frequency of an entire
combustor replacement. It is our understanding that combustion liners
and the fuel injection system are replaced at intervals similar to
major overhauls, but that the combustor need not be replaced in
entirety. If this is the case, then the ``combustor'' approach could
inadvertently hinder emissions improvements by providing an incentive
to replace only the critical components of the combustor instead of
upgrading the entire combustor. A potential alternative approach would
be to limit the applicability of the combustor to the combustion liner
and fuel injection system such that once those components are replaced
the combustion turbine would be considered reconstructed. Assuming the
replacement intervals are similar to overhaul intervals, if we adopt
this approach in the final rule, we would consider two replacements
prior to triggering reconstruction.
    Finally, we are requesting comment on whether a similar approach
should be adopted for turbines that are overhauled onsite. It is our
understanding that larger combustion turbines operating on natural gas
have overhaul schedules of approximately every 50,000 operating hours.
Under these assumptions, a combustion turbine could potentially operate
continuously for over 17 years prior to triggering the amended
reconstruction provision under subpart KKKK.
    If we adopt reconstruction triggers that differ from the general
provisions, we intend to maintain the qualification that it is
technologically and economically feasible to meet the applicable
standards for each combustion turbine that triggers the amended
reconstruction provisions. Instances where it might not be economically
feasible would be made on a case-by-case basis by the Administrator.
Examples of situations where it might not be economically feasible to
meet the emissions standard include low NOX combustor
designs being unavailable, turbine designs that are not compatible with
water or steam injection, or demineralized water or steam required for
NOX control being unavailable.
    In addition to the above proposed amendments to the applicability
of Subpart KKKK to new, reconstructed, and modified stationary
combustion

turbines, we are proposing to exempt non-major sources subject to this
NSPS from title V permitting requirements. Under the Clean Air Act
(CAA) section 502(a), the EPA may exempt non-major sources subject to
CAA section 111 (NSPS) standards from the requirements of title V if
the EPA finds that compliance with such requirements is
``impracticable, infeasible, or unnecessarily burdensome'' on such
sources. The EPA's finding to support exemption of non-major source
stationary combustion turbines subject to Subparts GG and KKKK from the
title V permitting requirements is available in the docket.

B. NOX Emissions Standard

    We are proposing to amend the NOX emissions standard for
stationary combustion turbines that burn multiple fuels. The existing
rule bases the applicable NOX standard on the total heat
input to the stationary combustion turbine, including any associated
duct burners, and the more stringent standard is only applicable if the
total heat input is derived from at least 50 percent natural gas.
However, fuel choice impacts combustion turbine engine NOX
emissions to a greater degree than it impacts such emissions from a
duct burner. Therefore, we are proposing that the NOX
standard be based on the type of fuel being burned in the combustion
turbine engine alone. The natural gas standard would apply at those
times when the fuel input to the combustion turbine engine meets the
definition of natural gas, regardless of the fuel, if any, that is
burned in the duct burners.
    We are also proposing to add a provision allowing for a site-
specific NOX standard for an owner/operator of a stationary
combustion turbine that burns by-product fuels. The owner/operator
would be required to petition the Administrator for a site-specific
standard using a procedure similar to what is currently required by
subpart Db of 40 CFR part 60 (the industrial boiler NSPS). We have
concluded that this is appropriate since subpart KKKK now covers the
HRSG that was previously covered by subpart Db.
    Since startup and shutdowns are part of the regular operating
practices of stationary combustion turbines, we are proposing that the
NOX emissions standard includes startup and shutdown
emissions. Since periods of startup and shutdown are by definition
periods of low load, the ``part-load standard'' would apply to all
hours that contain a startup or shutdown event. Since the ``part-load
standard'' is based on the emissions rate of a diffusion flame and not
dry low NOX (DLN) combustion controls, we have concluded
this standard is appropriate. Through analysis of continuous emission
monitoring system (CEMS) data, we have determined that including
periods of startup and shutdown in the standard would not result in
non-compliance with the standard. We analyzed NOX continuous
CEMS data from existing large and small turbines without post-
combustion controls to reduce NOX emissions. Even though
many of these turbines were built prior to the applicability date of
subpart KKKK, the theoretical compliance rate with a 4-hour rolling
average including all periods of operation was greater than 99 percent
for both large and small turbines. We were unable to determine if any
of the potential excess emissions were a result of either malfunction
of the NOX CEMS or combustion control equipment, or identify
all periods when the ``part-load standard'' would apply and the actual
level of theoretical compliance would be higher. Even though the
theoretical compliance rate is high when the NOX emissions
standard is determined directly, we are specifically requesting comment
on whether to account for startup conditions by considering the first
30 minutes of operation ``part-load'' such that the part-load emissions
rate would apply during that time period regardless of the actual load.
Implementing this option increases the theoretical compliance rate.
    Since we only used performance test data and did not analyze
NOX CEMS data in the original rulemaking, we are requesting
comment on whether it is appropriate to extend the averaging time for
simple cycle turbines to an operating day average. Emissions averages
would only be determined for operating days with 3 or more hours of
CEMS data that are not out-of-control. Data from operating days with
less than 3 hours of CEMS data that are not out-of-control would be
rolled over to the next operating day until 3 or more hours of data are
available. Extending the averaging period to an operating daily average
would increase the theoretical compliance rate. However, since
combustion turbines using combustion controls tend to have a steady
emissions profile, we have concluded that this approach would not
result in an increase in emissions, and could lower compliance burden
by reducing the reporting burden. An additional benefit of this
approach is that all non out-of-control emissions data would be used in
determining excess emissions. Under the current approach, any 4
operating hours with more than 1 hour of monitor downtime is reported
as monitor downtime and the emissions from the remaining hours are
excluded. We are not proposing a longer averaging period for a simple
cycle turbine. If we were to use a longer averaging period for simple
cycle turbines or determine compliance during startup, shutdown and
part-load periods separately from full-load periods, the NOX
standards would be re-evaluated to determine appropriate standards.
Furthermore, we are proposing to add a lb/MMBtu NOX option
that is equivalent to the ppm standard. This option would simplify
compliance for some sources while providing the same level of
environmental protection. Fourth, based on analysis of the CEMS data,
we are proposing to change the classification of large/small for
turbines operating at part-load. The existing rule divides large/small
turbines operating at part-load based on the rated output of the
turbine (i.e., turbines with outputs greater than 30 megawatts (MW) are
considered large). This proposed amendment would divide large/small
turbines operating at part-load based on the rated heat input (i.e.,
turbines with base load heat inputs greater 340 MMBtu per hour (MMBtu/
h) would be considered large). A heat input rating of 340 MMBtu/h is
approximately equivalent to an output rating of 30 MW, and this
amendment would simplify compliance by making the measurement method
for determination the large/small part-load subcategory consistent with
how the other subcategories are determined. A detailed discussion of
the NOX CEMS data for both large and small turbines is
available in the docket.
    We have concluded that the net power supplied to the end user is a
better indication of environmental performance than gross output from
the power producer. Therefore, we intend to amend the optional output-
based standard from gross to net output in the final rule. Net output
is the combination of the gross electrical (or mechanical) output of
the turbine engine and any output generated by the HRSG minus the
parasitic power requirements. A parasitic load for a stationary
combustion turbine is any of the loads or devices powered by
electricity, steam, hot water or directly by the gross output of the
stationary combustion turbine that does not contribute electrical,
mechanical or thermal output. One reason for this amendment is that
while combustion turbine engines that require high fuel gas feed
pressures typically have higher gross

efficiencies, they also often require fuel compressors that have
potentially larger parasitic loads than combustion turbine engines that
require lower fuel gas pressures. We have concluded that primary
parasitic loads include the fuel compressor, pump, or heater, fans,
inlet air cooling systems, control systems and post combustion
controls. We are requesting comment on any additional loads that should
be considered. To account for the parasitic loads, we intend to lower
the efficiency assumptions used to generate the output-based standards.
We have concluded that a 2.5 percent difference in efficiency is
appropriate, but are requesting comment on the issue. As an alternative
to continuously monitoring parasitic loads, we have concluded that
estimating parasitic loads is adequate and would minimize compliance
costs. A calibration would be required to determine the parasitic loads
at four load points (< 25 percent load, 25-50 percent load, 50-75
percent load, and >75 percent load). Once the parasitic load curve is
determined, the appropriate amount would be subtracted from the gross
output to determine net output. We are requesting comment on this
approach and whether a four-load test is appropriate or if a curve fit
of three loads greater than 25 percent load is sufficient.
    In addition, we are proposing to recognize the environmental
benefit of electricity generated by CHP facilities to account for the
benefit of on-site generation avoiding losses from the transmissions
and distribution of the electricity. Actual line losses vary from
location to location, but we are proposing a benefit of five percent
avoided transmission and distribution losses when determining the
electric output for CHP facilities. To avoid CHP facilities only
providing a trivial amount of thermal energy from qualifying for the
transmission and distribution benefit, we are proposing to restrict the
5 percent benefit to CHP facilities where at least 20 percent of the
annual output is useful thermal output.
    Finally, we are requesting comment on limiting the use of the 30-
day average. The existing rule provides a 30-day averaging period for
owners/operators of combined cycle and CHP turbines regardless of if
they elect to comply with the input or output-based standard. However,
based on the review of CEMS data, NOX emissions from
stationary combustion turbines are relatively stable in terms of ppm or
lb/MMBtu and a 30-day averaging time for combined cycle and CHP
facilities is not necessary. Owner/operators of any stationary
combustion turbine (including combined cycle and CHP turbines) electing
to comply with either of the input-based standards (ppm or lb/MMBtu)
would be required to use the 4-hour (or daily) averaging period. The
existing rule does not provide owner/operators of simple cycle turbines
the option to demonstrate compliance using a 30-day average. We have
concluded that few owner/operators of simple cycle turbines would elect
to demonstrate compliance with the output-based standard, but as
technology develops this might change in the future. Therefore, since
output is the only relevant characteristic that varies significantly
over short periods and a longer averaging period is necessary to
account for periods of lower efficiency, we are requesting comment on
using the 30-day averaging period for owner/operators of any stationary
combustion turbine electing to demonstrate compliance with the output-
based standard. Owner/operators of all stationary combustion turbines
electing to demonstrate compliance with either the ppm or lb/MMBtu
standards would use a 4-hour (or daily) averaging period.

C. SO2 Emissions Standard

    We are proposing to amend the rule language to clarify the intent
of the rule in that if a source elects to perform fuel analysis to
demonstrate compliance with the SO2 standard, the initial
test must measure all sulfur compounds (e.g. hydrogen sulfide, dimethyl
sulfide, carbonyl sulfide and thiol compounds). Alternate test
procedures can be used only if the measured sulfur content is less than
half of the applicable standard. In addition, we are proposing to allow
fuel blending to achieve the applicable SO2 standard. Under
the proposed language, an owner/operator of an affected facility would
be able to burn higher sulfur fuels as long as the average fuel fired
meets the applicable SO2 standard at all times. Finally, the
primary method of controlling SO2 emissions is through
selecting fuels containing low amounts of sulfur or through fuel
pretreatment operations that can operate at all times. We are proposing
that the SO2 standard apply during periods of startup and
shutdown.
    In recognition that ultra-low sulfur diesel is available for
transportation purposes in Hawaii, the Commonwealth of Puerto Rico and
the Virgin Islands, we are removing these areas from the definition of
noncontinental area. The only difference for owners/operators of
affected stationary combustion turbines located in noncontinental areas
is the ability to burn higher sulfur fuels. We have concluded that
since these areas have low sulfur diesel oil available it is not
appropriate to include these locations in the noncontinental area
definition. This amendment would still allow the use of higher sulfur
fuels in Guam, American Samoa, the Northern Mariana Islands and
offshore platforms where lower sulfur fuels are not necessarily as
readily accessible.
    For stationary combustion turbines combusting 50 percent or more
biogas (based on total heat input) per calendar month, the existing
Subpart KKKK establishes a maximum allowable SO2 emissions
standard of 65 nanograms (ng) SO2 per joule (/J) (0.15 lb
SO2/MMBtu) heat input. This standard was set to avoid
discouraging the development of energy recovery projects, which burn
landfill gases to generate electricity in stationary combustion
turbines (see 74 FR 11858, March 20, 2009). New stationary combustion
technologies using other low-Btu gases are becoming commercially
available. These technologies can burn low-Btu content gases recovered
from steelmaking (e.g., blast furnace gas and coke oven gas), coal bed
methane, closed landfills, etc. Similar to biogas, substantial
environmental benefits can be achieved by using these low-Btu gases to
generate electricity instead of flaring or direct venting to the
atmosphere, as is now common practice. Therefore, we are proposing to
expand the application of the existing 65 ng SO2/J (0.15 lb
SO2/MMBtu) heat input emissions standard to include
stationary combustion turbines combusting 50 percent or more (on a heat
input basis) of any gaseous fuels that have heating values less than 26
megajoules per standard cubic meter (700 Btu per scf) per calendar
month.
    To account for the environmental benefit of productive use and
simplify compliance for low-Btu gases, we have concluded that it is
appropriate to base the SO2 standard on a fuel concentration
basis as an alternative to a lb/MMBtu basis. The original subpart KKKK
2005 proposal (70 FR 8314) SO2 standard was based on the
sulfur content in distillate oil and included a sulfur standard of 0.05
percent by weight (500 ppm by weight (ppmw)). However, since we are
proposing to exempt liquid fuels containing less than 0.050 weight
percent sulfur from the SO2 standard, we are proposing an
alternate standard of 500 ppm by volume (ppmv). In general, emission
standards are applied to a gaseous mixture are by volume (ppmv), not by
weight (ppmw). Basing the standard on a volume basis would simplify
compliance and minimize burden to the regulated community. Therefore,
we are proposing a fuel

specification standard of 650 milligrams per standard cubic meter (28
gr/100 scf) for low-Btu gases. This is approximately equivalent to a
standard of 500 ppmv, and is in the units directly reported by most
test methods.

D. Malfunction Affirmative Defense

    The EPA has proposed standards in this proposed rule that apply at
all times and is proposing to add an affirmative defense to civil
penalties that are caused by malfunctions. The EPA's finding to support
the malfunction affirmative defense is available in the docket.

E. Electronic Data Submittal

    The EPA is proposing that owners/operators of stationary combustion
turbines submit electronic copies of required performance test reports
to the EPA's WebFIRE database. The EPA's finding to support this
requirement is available in the docket.

F. Additional Proposed Amendments

    We are also proposing several additional amendments. First, we have
concluded that it is not appropriate to require an affected facility
that is not currently in operation to startup to demonstrate compliance
with the NSPS. Commencing operation strictly for the purposes of
demonstrating compliance is an unnecessary cost and increases
emissions. Therefore, we are proposing to exempt units that are out of
operation at the time of the required performance test from conducting
the required performance test until 45 days after the facility is
brought back into operation.
    Similarly, owner/operators of a combustion turbine that has
operated 50 hours or less since the previous performance test was
required to be conducted can request an extension of the otherwise
required performance test from the appropriate EPA Regional Office
until the turbine has operated over 50 hours. This provision is fuel
specific and an owner/operator permitted to burn a backup fuel, but
that rarely does so, can request an extension on testing on that
particular fuel until it has been burned for over 50 hours.
    In addition, for similar, separate affected facilities using
identical control equipment, the Administrator or delegated authority
may authorize a single emissions test as adequate demonstration for up
to four other similar, separate affected facilities as long as: (1) The
most recent performance test for each affected facility shows that
performance of each affected facility is 75 percent or less of the
applicable emissions standard; (2) the manufacturer's recommended
maintenance procedures for each control device are followed; and (3)
each affected facility conducts a performance test for each pollutant
for which they are subject to a standard at least once every five
years. DLN combustion controls are the primary method for compliance
with the NSPS requirements and result in relatively stable emission
rates. Furthermore, the DLN combustor is a fundamental part of a
combustion turbine and as long as similar maintenance procedures are
followed we have concluded that emission rates will likely be
comparable between similar combustion turbines. Therefore, the
additional compliance costs associated with testing each affected
turbine would not result in significant emissions reductions.
    Additionally, turbine engine performance can deteriorate with
operation and age and operational parameters need to be verified
periodically to assure proper operation of emission controls.
Therefore, we are proposing to require facilities using the water or
steam to fuel ratio as a demonstration of continuous compliance with
the NOX emissions standard to verify the appropriate ratio
or parameters at a minimum of every 60 months. We have concluded this
would not add significant burden since the majority of affected
facilities are already required to conduct performance testing at least
every five years through title V requirements or other state permitting
requirements.
    The existing rule does not state how multiple combustion turbine
engines that are exhausted through a single HRSG would demonstrate
compliance with the NOX standard. Therefore, we are
proposing procedures for demonstrating compliance when multiple
combustion turbine engines are exhausted through a single HRSG and when
steam from multiple combustion turbine HRSGs is used in a single steam
turbine. Furthermore, the existing rule requires approval from the
permitting authority for any use of the part 75 NOX
monitoring provisions in lieu of the specified part 60 procedures, but
we concluded that approval is an unnecessary burden for facilities only
using combustion controls. Therefore, we are proposing to allow sources
using only combustion controls to use the parametric NOX
monitoring in part 75 to demonstrate continuous compliance without
requiring prior approval. However, if the source is using post
combustion control technology to comply with the requirements of the
NSPS, then approval from the permitting authority is required prior to
using the part 75 CEMS calibration procedures in place of the part 60
procedures.
    Finally, for turbine engines replaced with an identical overhauled
engine as part of an exchange program, we are proposing that the new
turbine undergo a new performance test to verify proper operation, for
owner/operators using water or steam to fuel ratio to verify the proper
ratio, and for owner/operators using parametric monitoring to verify
that the operating parameters are still valid.

G. Additional Request for Comments

    Affected Facility. We are considering and requesting comment on
amending the definition of the affected facility for systems with
multiple combustion turbine engines. Specifically, we are requesting
comment on treating multiple combustion turbine engines connected to a
single generator, separate combustion turbines engines using a single
HRSG and separate combustion turbine engines with separate HRSG that
use a single steam turbine or otherwise combine the useful thermal
output as single affected facilities. This approach would reduce burden
to the regulated community by simplifying monitoring. We are also
requesting comment on how the applicable emission standards would be
determined and on how ``new'' and ``reconstruction'' would be defined.
We are specifically requesting comment on basing the emission standards
on either the base load rating of the largest single combustion turbine
engine or the combined base load ratings of the combustion turbine
engines. For an affected facility with multiple combustion turbine
engines, we are requesting comment on considering the entire facility
``new'' or ``reconstructed'' if any combustion turbine engine is
replaced with a new combustion turbine engine or reconstructed.
    District Energy. We are considering and requesting comment on an
appropriate method to recognize the environmental benefit of district
energy systems. The steam or hot water distribution system of a
district energy system located in urban areas, college and university
campuses, hospitals, airports and military installations eliminates the
need for multiple, smaller boilers at individual buildings. A central
facility typically has superior emission controls and consists of a few
larger boilers facilitating more efficient operation than numerous
separate smaller individual boilers. However, when the hot water or
steam is distributed, approximately two to three percent of the thermal
energy in the water and six to nine percent of the

thermal energy in the steam is lost, reducing the net efficiency
advantage. We are requesting comment on whether it is appropriate to
divide the thermal output from district energy systems by a factor
(i.e., 0.95 or 0.90) that would account for the net efficiency benefits
of district energy systems. This approach would be similar to the
proposed approach to how the electric output for CHP is considered when
determining regulatory compliance. We request that comments include
technical analysis of the net benefits in support of any conclusions.
    Jet Fuel. We realize that jet fuel is an available fuel for
combustion turbines and are requesting comment on adding jet fuel to
the definition of distillate oil. In the event we include jet fuel in
the definition of distillate oil, we are also requesting the
appropriate test method (i.e., ASTM method) that should be used to
identify jet fuel.
    Low-Btu Gases. We are considering and requesting comment on
amending subpart KKKK to specifically exempt from the SO2
emission standards stationary combustion turbines combusting over 50
percent or more per calendar month low-Btu gases. Since these by-
product gases are a recovered waste that would otherwise be flared or
vented rather than a newly supplied fossil fuel such as natural gas or
fuel oil, the combusting of the low-Btu gases in a stationary
combustion turbine to generate electricity does not increase
SO2 emissions to the atmosphere. Such an exemption would
encourage the environmentally beneficial use of low-Btu by-product
gases, and would reduce the burden to the owners/operators of these
affected facilities by eliminating the need to demonstrate compliance
with an SO2 emissions standard. When the emissions
associated with the displaced electric and useful thermal output are
accounted for, there is a net reduction in emissions to the atmosphere.

III. Statutory and Executive Order Reviews

A. Executive Order 12866: Regulatory Planning and Review and Executive
Order 13563: Improving Regulation and Regulatory 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 Orders 12866 and
13563 (76 FR 3821, January 21, 2011).

B. Paperwork Reduction Act

    This action does not impose any new information collection burden.
The amended reconstruction provisions would not significantly impact
owners/operators of stationary combustion turbines within the next 5
years, and the other proposed 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. However, OMB previously
approved the information collection requirements contained in the
existing regulations (40 CFR part 60, subpart KKKK) under the
provisions of the Paperwork Reduction Act, 44 U.S.C. 3501 et seq., and
has assigned OMB control number 2060-0582. The OMB control numbers for
the 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 proposed 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 proposed rule on
small entities, I certify that this action will not have a significant
economic impact on a substantial number of small entities. The required
emissions control technology and other requirements have not been
significantly changed. In determining whether a rule has a significant
economic impact on a substantial number of small entities, the impact
of concern is any significant adverse economic impact on small
entities, since the primary purpose of the regulatory flexibility
analyses is to identify and address regulatory alternatives ``which
minimize any significant economic impact of the rule on small
entities.'' 5 U.S.C. 603 and 604. Thus, an agency may certify that a
rule will not have a significant economic impact on a substantial
number of small entities if the rule relieves regulatory burden, or
otherwise has a positive economic effect on all of the small entities
subject to the rule.
    Although this proposed rule will not have a significant economic
impact on a substantial number of small entities, the EPA nonetheless
has tried to reduce the impact of this rule on small entities. The
proposed amendments would allow flexibility in the timing of
performance testing of idle turbines and fuel blending to achieve the
SO2 standards.
    We therefore concluded that today's proposed rule would relieve
regulatory burden for all affected small entities.
    We continue to be interested in the potential impacts of the
proposed rule on small entities and welcome comments on issues related
to such impacts.

D. Unfunded Mandates Reform Act (UMRA)

    This proposed rule does not contain a federal mandate 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. Since the best system of emissions reduction is unchanged and
there are only minor proposed amendments to the performance testing,
recordkeeping, monitoring and reporting requirements, the proposed
amendments would not significantly impact the regulatory burden of this
rule. Thus, this proposed rule is not subject to the requirements of
sections 202 and 205 of UMRA.
    This proposed rule is also not subject to the requirements of
section 203 of UMRA because it contains no regulatory requirements that
might significantly or uniquely affect small governments. The proposed
amendments would reduce the overall regulatory requirements of the
rule.

E. Executive Order 13132: Federalism

    This action does not have federalism implications. It will not have
substantial direct effects on the states, on the relationship between
the national government and the states, or on the distribution of power
and responsibilities among the various

levels of government, as specified in Executive Order 13132. This
proposed rule will not impose substantial direct compliance costs on
state or local governments; it will not preempt state law. Thus,
Executive Order 13132 does not apply to this action.
    In the spirit of Executive Order 13132, and consistent with the EPA
policy to promote communications between the EPA and state and local
governments, the EPA specifically solicits comment on this proposed
rule from State and local officials.

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

    This action does not have tribal implications, as specified in
Executive Order 13175 (65 FR 67249, November 9, 2000). The EPA is not
aware of any stationary combustion turbine owned by an Indian tribe.
Thus, Executive Order 13175 does not apply to this action.
    The EPA specifically solicits additional comment on this proposed
action from tribal officials.

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

    The EPA interprets Executive Order 13045 (62 FR 19885, April 23,
1997) as applying to those regulatory actions that concern health or
safety risks, such that the analysis required under section 5-501 of
the Executive Order has the potential to influence the regulation. This
action is not subject to Executive Order 13045 because it is based
solely on technology performance. The proposal is not expected to
produce notable changes in criteria pollutant emissions or other
pollutants but does encourage the current trend towards cleaner
generation, helping to protect air quality and children's health. The
agency recognizes that children are among the groups most vulnerable to
climate change impacts and the public is invited to submit comments or
identify peer reviewed studies relevant to this proposal based solely
on technology.

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

    This action is not subject to Executive Order 13211, (66 FR 28355,
May 22, 2001) because it is not a significant regulatory action under
Executive Order 12866.

I. National Technology Transfer and Advancement Act

    Section 12(d) of the National Technology Transfer and Advancement
Act (NTTAA) of 1995, Public Law 104-113, 12(d) (15 U.S.C. 272 note)
directs the EPA to use voluntary consensus standards (VCS) in its
regulatory activities, unless to do so would be inconsistent with
applicable law or otherwise impractical. VCS are technical standards
(e.g., materials specifications, test methods, sampling procedures and
business practices) that are developed or adopted by VCS bodies. NTTAA
directs the EPA to provide Congress, through OMB, explanations when the
agency decides not use available and applicable VCS.
    This proposed rulemaking does not involve any new technical
standards. Therefore, the EPA did not consider the use of any VCS.

J. Executive Order 12898: Federal Actions To Address Environmental
Justice in Minority Populations and Low-Income Populations.

    Executive Order 12898 (59 FR 7629, February 16, 1994) establishes
federal executive policy on environmental justice. Its main provision
directs federal agencies, to the greatest extent practical and
permitted by law, to make environmental justice part of their mission
by identifying and addressing, as appropriate, disproportionately high
and adverse human health or environmental effects of their programs,
policies and activities on minority populations and low-income
populations in the United States.
    The EPA has determined that this proposed rule would not have
disproportionately high and adverse human health or environmental
effects on minority, low-income or indigenous populations because it
increases the level of environmental protection for all affected
populations without having any disproportionately high adverse human
health or environmental effects on any populations, including any
minority, low-income or indigenous populations. This proposed rule
would assure that all new stationary combustion turbines install
appropriate controls to minimize health impacts to nearby populations.
    To gain a better understanding of the source category and near
source populations, the EPA conducted a demographic analysis on recent
installations of combustion turbines selling >25 MW of power to
identify any overrepresentation of minority, low income, or indigenous
populations. This analysis only gives some indication of the prevalence
of sub-populations that may be exposed to air pollution from the
sources; it does not identify the demographic characteristics of the
most highly affected individuals or communities, nor does it quantify
the level of risk faced by those individuals or communities. The
demographic analysis results and the details concerning their
development are presented in the April 20, 2012, memorandum titled,
Environmental Justice Review, a copy of which is available in the
docket.

List of Subjects in 40 CFR Part 60

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

    Dated: June 22, 2012.
Lisa P. Jackson,
Administrator.
    For the reasons stated in the preamble, title 40, chapter I, part
60, of the Code of the Federal Regulations is proposed to be amended as
follows:

PART 60--[AMENDED]

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

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

Subpart A--[AMENDED]

    2. Section 60.17 is amended:
    a. By revising paragraph (a)(9);
    b. By revising paragraph (a)(16);
    c. By revising paragraph (a)(18);
    d. By revising paragraph (a)(22);
    e. By revising paragraph (a)(25);
    f. By revising paragraph (a)(40);
    g. By revising paragraph (a)(50);
    h. By revising paragraph (a)(57);
    i. By revising paragraph (a)(59);
    j. By revising paragraph (a)(61);
    k. By revising paragraph (a)(64);
    l. By revising paragraph (a)(68);
    m. By revising paragraph (a)(71);
    n. By revising paragraph (a)(72);
    o. By revising paragraph (a)(75);
    p. By revising paragraph (a)(76);
    q. By revising paragraph (a)(81);
    r. By revising paragraph (a)(88);
    s. By revising paragraph (a)(106);
    t. By revising paragraph (a)(107);
    u. By revising paragraph (a)(108); and
    v. By adding paragraphs (a)(109) through (a)(117).
    w. By revising paragraph (h)(4);
    x. By reserving paragraph (i);
    y. By redesignating paragraph (m)(1) as paragraph (m)(4);
    z. By revising paragraph (m)(2);
    aa. By adding new paragraphs (m)(1) and (m)(3); and

    bb. By revising newly redesignated paragraph (m)(4).
    The revisions and additions read as follows.

Sec.  60.17  Incorporations by Reference.

* * * * *
    (a) * * *
    (9) ASTM D129-11, Standard Test Method for Sulfur in Petroleum
Products (General High Pressure Decomposition Device Method), IBR
approved for Sec.  60.4360(c).
* * * * *
    (16) ASTM D975-11, 11b, Standard Specification for Diesel Fuel
Oils, IBR approved for Sec. Sec.  60.41b of subpart Db of this part,
60.41c of subpart Dc of this part, and 60.4420 of subpart KKKK of this
part.
* * * * *
    (18) ASTM D1072-06, 06, Standard Test Method for Total Sulfur in
Fuel Gases, IBR approved for Sec.  60.4360(c).
* * * * *
    (22) ASTM D1266-07, Standard Test Method for Sulfur in Petroleum
Products (Lamp Method), IBR approved for Sec.  60.4360(c).
* * * * *
    (25) ASTM D1552-08, Standard Test Method for Sulfur in Petroleum
Products (High-Temperature Method), IBR approved for Sec.  60.4360(c).
* * * * *
    (40) ASTM D2622-10, Standard Test Method for Sulfur in Petroleum
Products by Wavelength Dispersive X-Ray Fluorescence Spectrometry, IBR
approved for Sec.  60.4360(c).
* * * * *
    (50) ASTM D3246-11, Standard Test Method for Sulfur in Petroleum
Gas by Oxidative Microcoulometry, IBR approved for Sec.  60.4360(c).
* * * * *
    (57) ASTM D4057-06 (Reapproved 2011), Standard Practice for Manual
Sampling of Petroleum and Petroleum Products, IBR approved for Sec.
60.4360(b).
* * * * *
    (59) ASTM D4084-07, Standard Test Method for Analysis of Hydrogen
Sulfide in Gaseous Fuels (Lead Acetate Reaction Rate Method), IBR
approved for Sec.  60.4360(c).
* * * * *
    (61) ASTM D4177-95 (Reapproved 2010), Standard Practice for
Automatic Sampling of Petroleum and Petroleum Products, IBR approved
for Sec.  60.4360(b).
* * * * *
    (64) ASTM D4294-10, Standard Test Method for Sulfur in Petroleum
and Petroleum Products by Energy-Dispersive X-Ray Fluorescence
Spectrometry, IBR approved for Sec.  60.4360(c).
* * * * *
    (68) ASTM D4468-85 (Reapproved 2011), Standard Test Method for
Total Sulfur in Gaseous Fuels by Hydrogenolysis and Rateometric
Colorimetry, IBR approved for Sec. Sec.  60.335(b) and 60.4360(c).
* * * * *
    (71) ASTM D4810-88 (Reapproved 1999), 06, Standard Test Method for
Hydrogen Sulfide in Natural Gas Using Length of Stain Detector Tubes,
IBR approved for Sec.  60.4360(c).
    (72) ASTM D5287-97 (Reapproved 2002), 08, Standard Practice for
Automatic Sampling of Gaseous Fuels, IBR approved for Sec.  60.4360(b).
* * * * *
    (75) ASTM D5453-09, Standard Test Method for Determination of Total
Sulfur in Light Hydrocarbons, Motor Fuels and Oils by Ultraviolet
Fluorescence, IBR approved for Sec.  60.4360(c).
* * * * *
    (81) ASTM D6228-98 (Reapproved 2003), 10, 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.  60.4360(c).
* * * * *
    (88) ASTM D6667-10, Standard Test Method for Determination of Total
Volatile Sulfur in Gaseous Hydrocarbons and Liquefied Petroleum Gases
by Ultraviolet Fluorescence, IBR approved for Sec.  60.4360(c).
* * * * *
    (106) ASTM D3699-08, Standard Specification for Kerosine, including
Appendix Xl, (Approved September 1, 2008), IBR approved for Sec. Sec.
60.41b of subpart Db of this part, 60.41c of subpart Dc of this part,
and 60.4420 of subpart KKKK of this part.
    (107) ASTM D6751-11b, Standard Specification for Biodiesel Fuel
Blend Stock (B100) for Middle Distillate Fuels, including Appendices Xl
through X3, (Approved July 15, 2011), IBR approved for Sec. Sec.
60.41b of subpart Db of this part, 60.41c of subpart Dc of this part,
and 60.4420 of subpart KKKK of this part.
    (108) ASTM D7467-10, Standard Specification for Diesel Fuel Oil,
Biodiesel Blend (B6 to B20), including Appendices Xl through X3,
(Approved August 1, 2010), IBR approved for Sec. Sec.  60.41b of
subpart Db of this part, 60.41c of subpart Dc of this part, and 60.4420
of subpart KKKK of this part.
    (109) ASTM D240-09, Standard Test Method for Heat of Combustion of
Liquid Hydrocarbon Fuels by Bomb Calorimeter, IBR approved for Sec.
60.4360(c).
    (110) ASTM D396-10, Standard Specification for Fuel Oils, IBR
approved for Sec.  60.4420 of subpart KKKK of this part.
    (111) ASTM D1826-94 (Reapproved 2010), Standard Test Method for
Calorific (Heating) Value of Gases in Natural Gas Range by Continuous
Recording Calorimeter, IBR approved for Sec.  60.4350(c).
    (112) ASTM D3588-98 (Reapproved 2003) Standard Practice for
Calculating Heat Value, Compressibility Factor, and Relative Density of
Gaseous Fuels, IBR approved for Sec.  60.4360(c).
    (113) ASTM D4809-09a, Standard Test Method for Heat of Combustion
of Liquid Hydrocarbon Fuels by Bomb Calorimeter (Precision Method), IBR
approved for Sec.  60.4360(c).
    (114) ASTM D4891-89 (Reapproved 2006), Standard Test Method for
Heating Value of Gases in Natural Gas Range by Stoichiometric
Combustion, IBR approved for Sec.  60.4360(c).
    (115) ASTM D5504-08, Standard Test Method for Determination of
Sulfur Compounds in Natural Gas and Gaseous Fuels by Gas Chromatography
and Chemiluminescence, IBR approved for Sec.  60.4360(c).
    (116) ASTM D6522-11, 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.  60.4400(a).
    (117) ASTM D7164-05, 10, Standard Practice for On-line/At-line
Heating Value Determination of Gaseous Fuels by Gas Chromatography, IBR
approved for Sec.  60.4360(c).
* * * * *
    (h) * * *
    (4) ANSI/ASME PTC 19.10-1981, Flue and Exhaust Gas Analyses [Part
10, Instruments and Apparatus], (Issued August 31, 1981), IBR approved
for Sec.  60.56c(b), Sec.  60.63(f), Sec.  60.106(e), Sec.  60.104a(d),
(h), (i), and (j), Sec.  60.105a(d), (f), and (g), Sec.  60.106a(a),
Sec.  60.107a(a), (c), and (d), tables 1 and 3 of subpart EEEE, tables
2 and 4 of subpart FFFF, table 2 of subpart JJJJ, Sec.  60.4415(b),
Sec.  60.2145 and (t), Sec.  60.2710(s), (t) and (w), 60.2730(q),
60.4900(b), 60.5220(b), tables 1 and 2 to subpart LLLL, and tables 2
and 3 to subpart MMMM.
* * * * *
    (i) [Reserved]
* * * * *

    (m) * * *
    (1) Gas Processors Association Method 2166-05, Obtaining Natural
Gas Samples for Analysis by Gas Chromatography, IBR approved for Sec.
60.4360(b).
    (2) Gas Processors Association Method 2172-09, Calculation of Gross
Heating Value, Relative Density, Compressibility, and Theoretical
Hydrocarbon Liquid Content for Natural Gas Mixtures for Custody
Transfer, IBR approved for Sec.  60.4360(c).
    (3) Gas Processors Association Method 2174-93, Obtaining Liquid
Hydrocarbon Samples for Analysis by Gas Chromatography, IBR approved
for Sec.  60.4360(b).
    (4) Gas Processors Association Standard 2377-86, Test for Hydrogen
Sulfide and Carbon Dioxide in Natural Gas Using Length of Stain Tubes,
IBR approved for Sec. Sec.  60.105(b), 60.107a(b), 60.334(h), and
60.4360(c).
* * * * *

Subpart GG--[Amended]

    3. Section 60.330 is amended by revising paragraph (a) and adding
paragraph (c) to read as follows:

Sec.  60.330  Applicability and designation of affected facility.

    (a) The provisions of this subpart are applicable to the following
affected facilities: All stationary gas turbines not covered by
subparts Da or KKKK of this part with a heat input at peak load equal
to or greater than 10.7 gigajoules (10 million Btu) per hour, based on
the lower heating value of the fuel fired.
* * * * *
    (c) As an alternative to meeting the requirements of this subpart,
an owner or operator can petition the Administrator (in writing) to
comply with the requirements for modified units in subpart KKKK 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 for modified units in subpart KKKK
of this part.
    (d) If you are an owner or operator of a non-major source subject
to this subpart, you are exempt from the obligation to obtain a permit
under 40 CFR part 70 or 40 CFR part 71, provided you are not required
to obtain a permit under 40 CFR 70.3(a) or 40 CFR 71.3(a) for a reason
other than your status as a non-major source under this subpart.
Notwithstanding the previous sentence, you must continue to comply with
the provisions of this subpart, as applicable.

Subpart KKKK--Standards of Performance for Stationary Combustion
Turbines

    4. Part 60 is amended by revising subpart KKKK to read as follows:

Introduction

60.4300 What is the purpose of this subpart?

Applicability

60.4305 Does this subpart apply to my stationary combustion turbine?
60.4310 What stationary combustion turbines are not subject to this
subpart?

Emission Standards

60.4315 What pollutants are regulated by this subpart?
60.4320 What NOX emissions standard must I meet?
60.4330 What SO2 emissions standard must I meet?

General Compliance Requirements

60.4333 What are my general requirements for complying with this
subpart?
60.4334 Affirmative Defense for Violation of Emission Standards
During Malfunction.

Monitoring

60.4335 How do I demonstrate compliance with my NOX
emissions standard without using a NOX CEMS if I use
water or steam injection?
60.4340 How do I demonstrate compliance with my NOX
emissions standard without using a NOX CEMS if I do not
use water or steam injection?
60.4342 How do I monitor NOX control operating
parameters?
60.4345 How do I demonstrate compliance with my NOX
emissions standard using a NOX CEMS?
60.4350 How do I use the NOX CEMS data to determine
excess emissions?
60.4360 How do I use fuel sulfur analysis to determine the total
sulfur content of the fuel combusted in my stationary combustion
turbine?
60.4365 How frequently must I determine the fuel sulfur content?
60.4370 How do I demonstrate compliance with my SO2
emissions standard using records of the fuel sulfur content?
60.4372 How do I demonstrate compliance with my SO2
emissions standard and determine excess emissions using a
SO2 CEMS?

Recordkeeping and Reporting

60.4375 What reports must I submit?
60.4380 How are NOX excess emissions and monitor downtime
reported?
60.4385 How are SO2 excess emissions and monitor downtime
reported?
60.4390 What records must I maintain?
60.4395 When must I submit my reports?

Performance Tests

60.4400 How do I conduct performance tests to demonstrate compliance
with my NOX emissions standard if I do not have a
NOX CEMS?
60.4405 How do I conduct a performance test if I use a
NOX CEMS?
60.4415 How do I conduct performance tests to demonstrate compliance
with my SO2 emissions standard?

Definitions

60.4420 What definitions apply to this subpart?

Table 1 to Subpart KKKK of Part 60--Nitrogen Oxide Emission Standards
for Stationary Combustion Turbines

Subpart KKKK--Standards of Performance for Stationary Combustion
Turbines

Introduction

Sec.  60.4300  What is the purpose of this subpart?

    This subpart establishes emission standards and compliance
schedules for the control of emissions from stationary combustion
turbines that commenced construction, modification, or reconstruction
after February 18, 2005.

Applicability

Sec.  60.4305  Does this subpart apply to my stationary combustion
turbine?

    (a) You are subject to this subpart if you own or operate a
stationary combustion turbine that commenced construction,
modification, or reconstruction after February 18, 2005, and that has a
base load rating equal to or greater than 2.9 megawatts (MW) (10
million British thermal units per hour (MMBtu/h)), except as provided
for in Sec.  60.4310. Any additional heat input from duct burners used
with heat recovery steam generating units or fuel preheaters is not
included in the heat input value used to determine the applicability of
this subpart to a given stationary combustion turbine.
    (b) For the purpose of this subpart, only the combustion turbine
engine itself is used to determine whether the affected facility is new
or reconstructed. Other equipment included in the definition of a
stationary combustion turbine is not included when determining if a
facility is new or reconstructed.
    (c) A combustion turbine engine subject to this subpart is not
subject to subpart GG of this part.
    (d) Duct burners that do not burn any solid fuels when used with a
heat recovery steam generating unit that is part of either a combined
cycle combustion turbine or a combined heat and power (CHP) combustion
turbine subject to this subpart are not subject to subpart D, Da, Db,
or Dc of this part, as applicable.
    (e) If you own or operate either a stationary combustion turbine

(including a combined cycle combustion turbine or a CHP combustion
turbine) that commenced construction, modification, or reconstruction
on or before February 18, 2005, you may submit a written petition to
the Administrator requesting that the stationary combustion turbine be
allowed to comply with the applicable requirements for modified units
under this subpart as an alternative to complying with subpart GG of
this part, and with subparts D, Da, Db, and Dc of this part, as
applicable. If the Administrator or delegated authority approves the
petitioner's request, the affected facility must comply with the
requirements for modified units under this subpart unless the
combustion turbine engine is reconstructed or replaced with a new
facility in the future.
    (f) If you are an owner or operator of a non-major source subject
to this subpart, you are exempt from the obligation to obtain a permit
under 40 CFR part 70 or 40 CFR part 71, provided you are not required
to obtain a permit under 40 CFR 70.3(a) or 40 CFR 71.3(a) for a reason
other than your status as a non-major source under this subpart.
Notwithstanding the previous sentence, you must continue to comply with
the provisions of this subpart, as applicable.

Sec.  60.4310  What stationary combustion turbines are not subject to
this subpart?

    (a) An integrated gasification combined cycle electric utility
steam generating unit subject to subpart Da of this part is not subject
to this subpart.
    (b) A stationary combustion turbine used in a combustion turbine
test cell/stand as defined in Sec.  60.4420 is not subject to this
subpart.
    (c) A stationary combustion turbine subject to subpart Ea, subpart
Eb, or subpart AAAA of this part is not subject to this subpart.
    (d) A stationary combustion turbine subject to an EPA approved
State or Federal plan implementing under authority of Clean Air Act
sections 111(d)/129 either subpart Cb or subpart BBBB of this part is
not subject to this subpart.

Emission Standards

Sec.  60.4315  What pollutants are regulated by this subpart?

    The pollutants regulated by this subpart are nitrogen oxides
(NOX) and sulfur dioxide (SO2).

Sec.  60.4320  What NOX emissions standard must I meet?

    (a) For each simple cycle stationary combustion turbine, except as
provided for in paragraph (d) of this section, you must not discharge
into the atmosphere from the affected facility any gases that contain
NOX in excess of the applicable emissions standard as
determined on a 4-operating hour basis and according to the
requirements specified in paragraph (c) of this section.
    (b) For each combined-cycle combustion turbine or CHP combustion
turbine except as provided for in paragraph (d) of this section, you
must not discharge into the atmosphere from the affected facility any
gases that contain NOX into the atmosphere from the affected
facility in excess of the applicable emissions standard on a 30-
operating day basis and according to the requirements specified in
paragraph (c) of this section.
    (c) For the purpose of determining compliance with the applicable
emissions standard in paragraphs (a) and (b) of this section, you must
meet the requirements specified in paragraphs (c)(1) through (c)(4), as
applicable to your affected facility.
    (1) The NOX emissions standard that is applicable to
your affected facility shall be determined on an operating hour basis
except as provided for in paragraph (c)(2) of this section. Determining
the hourly NOX emission standards for your affected facility
requires recording hourly data and maintaining records according to the
requirements in Sec.  60.4390.
    (2) As an alternative to the requirements specified in paragraph
(c)(1) of this section, you may elect to use the lowest emissions
standard determined using Table 1 of this subpart that is applicable to
your affected facility for the entire required compliance period.
    (3) During each operating hour when only natural gas is combusted
in the combustion turbine engine, you must meet the applicable
NOX emissions standard determined using Table 1 of this
subpart for a stationary combustion firing natural gas. During each
operating hour when any fuel other than natural gas is combusted in the
combustion turbine engine, you must meet the applicable NOX
emissions standard determined using Table 1 of this subpart for a
stationary combustion firing fuels other than natural gas. If multiple
fuels are combusted during a given operating hour, then the highest
applicable NOX emissions standard is applied for the entire
operating hour.
    (4) If you have two or more combustion turbine engines connected to
a single electric generator, each of the combustion turbine engines
must meet the applicable NOX emissions standard determined
using Table 1 of this subpart.
    (d) Stationary combustion turbines specified in paragraphs (d)(1)
through (3) of this section are exempt from the applicable
NOX emissions standard in paragraphs (a) and (b) of this
section.
    (1) An emergency combustion turbine, as defined in Sec.  60.4420;
    (2) A stationary combustion turbine used for research and
development of equipment for combustion turbine emissions control
techniques or efficiency improvements as determined by the
Administrator or delegated authority on a case-by-case basis; and
    (3) A stationary combustion turbine that combusts byproduct fuels
for which a facility-specific NOX emissions standard has
been established by the Administrator according to the requirements of
paragraphs (d)(3)(i) and (ii).
    (i) You may request a facility-specific NOX emissions
standard by submitting a written request to the Administrator or
delegated authority explaining why your affected facility when burning
the byproduct fuel is unable to comply with the applicable
NOX emissions standard determined using Table 1 of this
subpart.
    (ii) If the Administrator approves the request, a letter will be
sent to the facility describing the facility-specific NOX
emissions standard. You must use the compliance procedures detailed in
the letter and make the letter available to the public. If the
Administrator determines it is appropriate, the conditions and
requirements of the letter can be reviewed and changed at any point.
    (e) For affected facilities for which construction, modification,
or reconstruction commenced before August 30, 2012, you must meet the
NOX emissions standard applicable under this section to your
affected facility during all times when the affected facility is
operating except during periods of startup, shutdown, or malfunction.
For each affected facility for which construction, reconstruction, or
modification commenced after August 29, 2012, you must meet the
NOX emissions standard applicable under this section to your
affected facility during all times when the affected facility is
operating (including periods of startup, shutdown, and malfunction).

Sec.  60.4330  What SO2 emissions standard must I meet?

    (a) For each stationary combustion turbine, except as provided for
in paragraphs (b) through (g) of this section, you must not cause to be
discharged into the atmosphere from the

affected facility any gases that contain SO2 in excess of
either:
    (1) 110 nanograms per Joule (ng/J) (0.90 pounds per megawatt-hour
(lb/MWh)) gross energy output; or
    (2) 26 ng SO2/J (0.060 lb SO2/MMBtu) heat
input.
    (b) As an alternative to the requirements of paragraph (a) of this
section, for each stationary combustion turbine combusting 50 percent
or more low-Btu gas per calendar month based on total heat input using
the higher heating value of the fuel, you may limit the sulfur content
of the fuel to no more than either:
    (1) 650 milligrams of sulfur per standard cubic meter (mg/scm) (28
grains (gr) of sulfur per 100 standard cubic feet (scf)); or
    (2) 65 ng SO2/J (0.15 lb SO2/MMBtu) heat
input.
    (c) For each stationary combustion turbine located in a
noncontinental area, you must not cause to be discharged into the
atmosphere from the affected facility any gases that contains
SO2 in excess of either:
    (1) 780 ng/J (6.2 lb/MWh) gross energy output; or
    (2) 180 ng SO2/J (0.42 lb SO2/MMBtu) heat
input.
    (d) For each stationary combustion turbine for which the
Administrator determines that the affected facility does not have
access to natural gas and the removal of sulfur compounds from the fuel
would cause more environmental harm than benefit, you must not cause to
be discharged into the atmosphere from the affected facility any gases
that contain SO2 in excess of either:
    (1) 780 ng/J (6.2 lb/MWh) gross energy output; or
    (2) 180 ng SO2/J (0.42 lb SO2/MMBtu) heat
input.
    (e) A stationary combustion turbine that is subject to
SO2 emission standards under either subpart J or Ja of this
part is not subject to the SO2 emission standards in this
subpart.
    (f) A combustion turbine that is subject to a federally enforceable
requirement limiting the sulfur content of gaseous fuels combusted in
the stationary combustion turbine to no more than 460 mg/scm (20 gr/100
scf) and/or for liquid fuels no more than 0.050 weight percent sulfur
is not subject to the SO2 emission standards in this
subpart.
    (g) For affected facilities for which construction, modification,
or reconstruction commenced before August 30, 2012, you must meet the
SO2 emissions standard applicable under this section to your
affected facility during all times when the affected facility is
operating except during periods of startup, shutdown, or malfunction.
For each affected facility for which construction, reconstruction, or
modification commenced after August 29, 2012, you must meet the
SO2 emissions standard applicable under this section to your
affected facility during all times when the affected facility is
operating (including periods of startup, shutdown and malfunction).

General Compliance Requirements

Sec.  60.4333  What are my general requirements for complying with this
subpart?

    (a) You must operate and maintain your stationary combustion
turbine, air pollution control equipment, and monitoring equipment in a
manner consistent with good air pollution control practices for
minimizing emissions at all times including during startup, shutdown,
and malfunction.
    (b) If you own or operate a stationary combustion turbine subject
to a NOX emissions standard in Sec.  60.4320, you must
conduct an initial performance test according to Sec.  60.8 using the
applicable methods in Sec.  60.4400 or Sec.  60.4405. Thereafter,
unless you perform continuous monitoring consistent with Sec. Sec.
60.4335, 60.4340(b), or 60.4345, you must conduct subsequent
performance tests according to the applicable requirements in
paragraphs (b)(1) through (b)(6) of this section.
    (1) Except as provided for in paragraphs (b)(2) through (b)(5) of
this section, you must conduct subsequent performance tests within 12
calendar months following the date the previous performance test was
required to be conducted. Performance tests must be separated by a
minimum of 9 calendar months.
    (2) If the NOX emission result from the most recent
performance test is less than or equal to 75 percent of the
NOX emissions standard for the stationary combustion
turbine, you may reduce the frequency of subsequent performance tests
to 24 calendar months following the date the previous performance test
was required to be conducted. Performance tests must be separated by a
minimum of 21 calendar months. If the results of any subsequent
performance test exceed 75 percent of the NOX emissions
standard for the stationary combustion turbine, you must resume annual
performance testing.
    (3) An affected facility that has not operated for the 60 calendar
days prior to the due date of a performance test is not required to
perform the subsequent performance test until 45 calendar days after
the next operating day. The delegated permitting authority must be
notified of recommencement of operation consistent with Sec.
60.4375(d).
    (4) If you own or operate an affected facility that has operated 50
operating hours or less in total or with a particular fuel since the
date the previous performance test was required to be conducted you may
request an extension from the otherwise required performance test until
after the affected facility has operated more than 50 operating hours
in total or with a particular fuel since the date of the previous
performance test was required to be conducted. A request for an
extension under this paragraph must be addressed to the relevant air
division or office director of the appropriate Regional Office of the
U.S. EPA as identified in Sec.  60.4(a) for his or her approval at
least 30 calendar days prior to the date on which the performance test
is required to be conducted. If an exemption is approved, a performance
test must be conducted within 45 calendar days after the day the
facility reaches 50 hours of operation since the date the previous
performance test was required to be conducted. When the facility has
operated more than 50 operating hours since the date the previous
performance test was required to be conducted, the delegated permitting
authority must be notified consistent with Sec.  60.4375(e).
    (5) For a facility at which a group consisting of no more than five
similar stationary combustion turbines (i.e., same manufacturer and
model number) is operated, you may request the use of a custom testing
schedule by submitting a written request to the Administrator or
delegated authority. The minimum requirements of the custom schedule
include the conditions specified in paragraphs (5)(i) through (v) of
this section.
    (i) Emissions from the most recent performance test for each
individual affected facility are 75 percent or less of the applicable
standard;
    (ii) Each stationary combustion turbine uses the same emissions
control technology;
    (iii) Each stationary combustion turbine is operated in a similar
manner;
    (iv) Each stationary combustion turbine and its emissions control
equipment are maintained according to the manufacturer's recommended
maintenance procedures; and
    (v) A performance test is conducted on each affected facility at
least once every 5 calendar years.
    (6) A stationary combustion turbine subject to a NOX
emissions standard in Sec.  60.4320 that exchanges the combustion
turbine engine for an overhauled combustion turbine engine

as part of an exchange program, must conduct an initial performance
test according to Sec.  60.8 using the applicable methods in Sec.
60.4400.
    (c) Except as provided for in paragraphs (c)(1) or (2) of this
section, for each stationary combustion turbine subject to a
NOX emissions standard in Sec.  60.4320, you must
demonstrate continuous compliance using a continuous emissions
monitoring system (CEMS) for measuring NOX emissions
according to the provisions in Sec.  60.4345. If your stationary
combustion turbine is equipped with a NOX CEMS, those
measurements must be used to determine excess emissions.
    (1) If your stationary combustion turbine uses water or steam
injection but not post-combustion controls to meet the applicable
NOX emissions standard in Sec.  60.4320, you may elect to
demonstrate continuous compliance using either the pounds per million
British thermal units (lb/MMBtu) or the part per million (ppm) standard
according to the provisions in Sec.  60.4335.
    (2) If your stationary combustion turbine does not use water
injection, steam injection, or post-combustion controls to meet the
applicable NOX emissions standard in Sec.  60.4320, you may
elect to demonstrate continuous compliance with either the lb/MMBtu or
ppm standard according to the provisions in Sec.  60.4340.
    (d) An owner or operator of a stationary combustion turbine subject
to an SO2 emissions standard in Sec.  60.4330 must
demonstrate compliance using one of the methods specified in paragraphs
(d)(1) through (4) of this section.
    (1) Conduct an initial performance test according to Sec.  60.8 and
use the applicable methods in Sec.  60.4415. Thereafter, you must
conduct subsequent performance tests within 12 calendar months
following the date the previous performance test was required to be
conducted. Performance tests must be separated by a minimum of 9
calendar months. An affected facility that has not operated for the 60
calendar days prior to the due date of a performance test is not
required to perform the subsequent performance test until 45 calendar
days after the next operating day;
    (2) Conduct an initial performance test according to Sec.  60.8 and
use the applicable methods in Sec.  60.4415. Thereafter, conduct
subsequent fuel sulfur analyses using the applicable methods specified
in Sec.  60.4360 and at the frequency specified in Sec.  60.4365;
    (3) Conduct an initial performance test according to Sec.  60.8 and
use the applicable methods in Sec.  60.4415. Thereafter, maintain
records (such as a current, valid purchase contract, tariff sheet, or
transportation contract) documenting that total sulfur content for the
initial and subsequent fuel combusted in your stationary combustion
turbine at all times does not exceed applicable conditions specified in
Sec.  60.4370; or
    (4) Conduct an initial performance test according to Sec.  60.8
using the applicable methods in Sec.  60.4415. Thereafter, continue to
monitor SO2 emissions using a CEMS according to the
requirements specified in Sec.  60.4372.
    (e) If you elect to comply with an input-based standard (lb/MMBtu)
and your affected facility includes use of one or more heat recovery
steam generating units, then you must determine compliance with the
applicable NOX and SO2 emission standards
according to the procedures specified in paragraphs (e)(1) or (2) of
this section as applicable to the heat recovery steam generating unit
configuration used for your affected facility.
    (1) For a configuration where a single combustion turbine engine is
exhausted through the heat recovery steam generating unit, you must
measure both the emissions at the exhaust stack for the heat recovery
steam generating unit and the fuel flow to the combustion turbine
engine and any associated duct burners.
    (2) For a configuration where two or more combustion turbine
engines are exhausted through a heat recovery steam generating unit,
you must measure both the total emissions at the exhaust stack for the
heat recovery steam generating unit and the total fuel flow to each
combustion turbine engine and any associated duct burners. The
applicable emissions standard for the affected facility is equal to the
most stringent emissions standard for any individual combustion turbine
engine.
    (f) If you elect to comply with an output-based standard (lb/MWh)
and your affected facility includes use of one or more heat recovery
steam generating units, then you must determine compliance with the
applicable NOX and SO2 emission standards
according to the procedures in paragraphs (f)(1), (2), or (3) of this
section as applicable to the heat recovery steam generating unit
configuration used for your affected facility.
    (1) For a configuration where a single combustion turbine engine is
exhausted through the heat recovery steam generating unit, you must
measure both the emissions at the exhaust stack for the heat recovery
steam generating unit and the total electrical, mechanical energy, and
useful thermal output of the stationary combustion turbine (as
applicable).
    (2) For a configuration where two or more combustion turbine
engines are exhausted through a single heat recovery steam generating
unit, you must measure both the total emissions at the exhaust stack
for the heat recovery steam generating unit, and the total electrical,
mechanical energy, and useful thermal output of the heat recovery steam
generating unit and each combustion turbine engine (as applicable). The
applicable emissions standard for the affected facility is equal to the
most stringent emissions standard for any individual combustion turbine
engines.
    (3) For a configuration where your combustion turbine engines are
exhausted through two or more heat recovery steam generating units
which serve a common steam turbine or steam header, you must measure
both the emissions at the exhaust stack for each heat recovery steam
generating unit and the total electrical or mechanical energy output of
each combustion turbine engine (as applicable). To determine the gross
energy output of the steam produced by the heat recovery steam
generating unit, you must develop a custom method and provide
information, satisfactory to the Administrator or delegated authority,
apportioning the gross energy output of the steam produced by the heat
recovery steam generating units to each of the affected stationary
combustion turbines.

Sec.  60.4334  Affirmative Defense for Violation of Emission Standards
During Malfunction.

    In response to an action to enforce the standards set forth in
paragraphs Sec. Sec.  60.4320 and 60.4330 you may assert an affirmative
defense to a claim for civil penalties for violations of such standards
that are caused by malfunction, as defined at 40 CFR 60.2. Appropriate
penalties may be assessed; however, if you fail to meet your burden of
proving all of the requirements in the affirmative defense, the
affirmative defense shall not be available for claims for injunctive
relief.
    (a) To establish the affirmative defense in any action to enforce
such a standard, you must timely meet the reporting requirements in
paragraph (b) of this section, and must prove by a preponderance of
evidence that:
    (1) The violation:
    (i) Was caused by a sudden, infrequent, and unavoidable failure of
air pollution control equipment, process equipment, or a process to
operate in a normal or usual manner, and
    (ii) Could not have been prevented through careful planning, proper
design

or better operation and maintenance practices; and
    (iii) Did not stem from any activity or event that could have been
foreseen and avoided, or planned for; and
    (iv) Was not part of a recurring pattern indicative of inadequate
design, operation, or maintenance; and
    (2) Repairs were made as expeditiously as possible when a violation
occurred. Off-shift and overtime labor were used, to the extent
practicable to make these repairs; and
    (3) The frequency, amount and duration of the violation (including
any bypass) were minimized to the maximum extent practicable; and
    (4) If the violation resulted from a bypass of control equipment or
a process, then the bypass was unavoidable to prevent loss of life,
personal injury, or severe property damage; and
    (5) All possible steps were taken to minimize the impact of the
violation on ambient air quality, the environment, and human health;
and
    (6) All emissions monitoring and control systems were kept in
operation if at all possible, consistent with safety and good air
pollution control practices; and
    (7) All of the actions in response to the violation were documented
by properly signed, contemporaneous operating logs; and
    (8) At all times, the affected source was operated in a manner
consistent with good practices for minimizing emissions; and
    (9) A written root cause analysis has been prepared, the purpose of
which is to determine, correct, and eliminate the primary causes of the
malfunction and the violation resulting from the malfunction event at
issue. The analysis must also specify, using best monitoring methods
and engineering judgment, the amount of any emissions that were the
result of the malfunction.
    (b) Report. The owner or operator seeking to assert an affirmative
defense shall submit a written report to the Administrator or delegated
authority with all necessary supporting documentation, that it has met
the requirements set forth in paragraph (a) of this section. This
affirmative defense report shall be included in the first periodic
compliance, deviation report or excess emission report otherwise
required after the initial occurrence of the violation of the relevant
standard (which may be the end of any applicable averaging period). If
such compliance, deviation report or excess emission report is due less
than 45 days after the initial occurrence of the violation, the
affirmative defense report may be included in the second compliance,
deviation report, or excess emission report due after the initial
occurrence of the violation of the relevant standard.

Monitoring

Sec.  60.4335  How do I demonstrate compliance with my NOX emissions
standard without using a NOX CEMS if I use water or steam injection?

    If you qualify and elect to demonstrate continuous compliance
according to the provisions of Sec.  60.4333(c)(1), you must install,
calibrate, maintain, and operate a continuous monitoring system to
monitor and record the fuel consumption and the ratio of water or steam
to fuel fired in the combustion turbine engine consistent with the
requirements in Sec.  60.4342. Water or steam only needs to be injected
when a fuel is being combusted that requires water or steam injection
for compliance with the applicable NOX emissions standard.

Sec.  60.4340  How do I demonstrate compliance with my NOX emissions
standard without using a NOX CEMS if I do not use water or steam
injection?

    (a) If you qualify and elect to demonstrate continuous compliance
according to the provisions of Sec.  60.4333(c)(2), you must
demonstrate compliance with the NOX emissions standard using
the methods specified in either paragraphs (a)(1) through (3) of this
section.
    (1) Conduct performance tests according to requirements in Sec.
60.4400;
    (2) Monitor the NOX emissions rate using the methodology
in appendix E to part 75 of this chapter, or the low mass emissions
methodology in Sec.  75.19; or
    (3) Install, calibrate, maintain and operate an operating parameter
continuous monitoring system according to the requirements specified in
paragraph (b) of this section and consistent with the requirements
specified in Sec.  60.4342.
    (b) Continuous operating parameter monitoring must be performed
using the methods specified in paragraphs (b)(1) through (4) of this
section as applicable to the stationary combustion turbine.
    (1) Selection of the operating parameters used to comply with this
paragraph must be identified in the performance test report, and are
subject to the review and approval of the delegated permitting
authority.
    (2) For a lean premix stationary combustion turbine, you must
continuously monitor the appropriate parameters to determine whether
the unit is operating in low-NOX mode when low-
NOX operation is required to comply with the applicable
emission NOX standard.
    (3) For a stationary combustion turbine other than a lean premix
stationary combustion turbine, you must define parameters indicative of
the unit's NOX formation characteristics, and monitor these
parameters continuously.
    (4) You must perform the parametric monitoring described in section
2.3 in appendix E to part 75 of this chapter or in Sec.
75.19(c)(1)(iv)(H).

Sec.  60.4342  How do I monitor NOX control operating parameters?

    (a) If you monitor steam or water to fuel ratio according to Sec.
60.4335 or other parameters according to Sec.  60.4340, the applicable
parameters must be continuously monitored and recorded during the
performance test, to establish acceptable values and ranges. You may
supplement the performance test data with engineering analyses, design
specifications, manufacturer's recommendations, and other relevant
information to define the acceptable parametric ranges more precisely.
You must develop and keep on-site a parameter monitoring plan which
explains the procedures used to document proper operation of the
NOX emission controls. The plan must include the information
specified in paragraphs (a)(1) through (6) of this section:
    (1) Identification of the parameters to be monitored and show there
is a significant relationship to emissions and proper operation of the
NOX emission controls;
    (2) Selected parameter ranges (or designated conditions) indicative
of proper operation of the stationary combustion turbine NOX
emission controls, or describe the process by which such range (or
designated condition) will be established;
    (3) Explanation of the process you will use to make certain that
you obtain data that are representative of the emissions or parameters
being monitored (such as detector location, installation specification
if applicable);
    (4) Description of quality assurance and control practices used to
ensure the continuing validity of the data;
    (5) Description of the frequency of monitoring and the data
collection procedures which you will use (e.g., you are using a
computerized data acquisition over a number of discrete data points
with the average (or maximum value) being used for purposes of
determining whether an exceedance has occurred); and
    (6) Justification for the proposed elements of the monitoring. If a

proposed performance specification differs from manufacturer
recommendation, you must explain the reasons for the differences. You
must submit the data supporting the justification, but you may refer to
generally available sources of information used to support the
justification. You may rely on engineering assessments and other data,
provided you demonstrate factors which assure compliance or explain why
performance testing is unnecessary to establish indicator ranges.
    (b) The ratio of water or steam to fuel and parameter continuous
monitoring system ranges must be reestablished at least 60 calendar
months following the previous calibration and each time the combustion
turbine engine is replaced with an overhauled turbine engine as part of
an exchange program. An affected facility that has not operated for 60
calendar days prior to the due date of a recalibration you are not
required to perform the subsequent recalibration until 45 calendar days
after the next operating day.

Sec.  60.4345  How do I demonstrate compliance with my NOX emissions
standard using a NOX CEMS?

    (a) Each CEMS measuring NOX emissions used to meet the
requirements of this subpart, must meet the requirements in paragraphs
(a)(1) through (7) of this section.
    (1) You must install, certify, maintain, and operate a
NOX monitor to determine the hourly average NOX
emissions in the units of the standard with which you are complying;
    (2) If you elect to comply with the ppm emissions standard, you
must also install a diluent gas (oxygen (O2) or carbon
dioxide (CO2)) monitor;
    (3) If you elect to comply with an input-based emissions standard,
you must install, calibrate, maintain, and operate either a fuel flow
meter (or flow meters) or an O2 or CO2 CEMS and a
stack flow meter to continuously measure the heat input to the affected
facility;
    (4) If you elect to comply with an output-based emissions standard,
you must also install, calibrate, maintain, and operate both a watt
meter (or meters) to continuously measure the gross electrical output
from the affected facility and a stack flow meter. If you have a CHP
combustion turbine and elect to comply with an output-based emissions
standard, you must also install, calibrate, maintain, and operate
meters to continuously determine the total useful recovered thermal
energy. For steam this includes flow rate, temperature, and pressure.
If you have a direct mechanical dive application and elect to comply
with the output-based emissions standard you must submit a plan to the
Administrator or delegated authority for approval of how gross energy
output will be determined.
    (5) If you elect to comply with the part load NOX
emissions standard, you must install, calibrate, maintain, and operate
either a fuel flow meter (or flow meters) or an O2 or
CO2 CEMS and a stack flow meter to continuously measure the
heat input to the affected facility.
    (6) If you elect to comply with the temperature dependent
NOX emissions standard, you must install, calibrate,
maintain, and operate a thermometer to continuously monitor the ambient
temperature.
    (7) If you burn natural gas with fuels other than natural gas and
elect to comply with the fuels other than natural gas NOX
emissions standard, you must install, calibrate, maintain, and operate
a device to continuously monitor when a fuel other than natural gas
fuel is combusted in the combustion turbine engine.
    (b) Each NOX CEMS must be installed and certified
according to Performance Specification 2 (PS 2) in appendix B to this
part. The span value must be 125 percent of the highest applicable
standard or highest anticipated hourly NOX emissions rate.
For stationary combustion turbines that do not use post-combustion
technology to reduce emissions of NOX to comply with the
requirements of this subpart, the delegated permitting authority may
approve the use of the NOX and diluent CEMS that are
installed and certified according to appendix A of part 75 of this
chapter in lieu of Procedure 1 in appendix F to this part and the
requirements of Sec.  60.13 of this part, except that the relative
accuracy test audit (RATA) of the CEMS must be performed on a lb/MMBtu
basis.
    (c) During each full operating hour, both the NOX
monitor and the diluent monitor must complete a minimum of one cycle of
operation (sampling, analyzing, and data recording) for each 15-minute
quadrant of the hour. For partial operating hours, at least one data
point must be obtained with each monitor for each quadrant of the hour
in which the unit operates. For operating hours in which required
quality assurance and maintenance activities are performed on the CEMS,
a minimum of two data points (one in each of two quadrants) are
required for each monitor.
    (d) Each fuel flow meter must be installed, calibrated, maintained,
and operated according to the manufacturer's instructions.
Alternatively fuel flow meters that meet the installation,
certification, and quality assurance requirements in appendix D to part
75 of this chapter are acceptable for use under this subpart.
    (e) Each watt meter, steam flow meter, and each pressure or
temperature measurement device must be installed, calibrated,
maintained, and operated according to manufacturer's instructions.
    (f) You must develop, submit to the delegated permitting authority
for approval, maintain, and adhere to an on-site quality assurance (QA)
plan for all of the continuous monitoring equipment you use to comply
with this subpart. At a minimum, such a QA plan must address the
requirements of Sec. Sec.  60.13(d), (e), and (h) of this part. For the
CEMS and fuel flow meters, the owner or operator of a stationary
combustion turbine that does not use post combustion technology to
reduce emissions of NOX to comply with the requirements of
this subpart may, with approval of the delegated permitting authority,
satisfy the requirements of this paragraph by implementing the QA
program and plan described in section 1 in appendix B to part 75 of
this chapter in lieu of the requirements in Sec.  60.13(d)(1).

Sec.  60.4350  How do I use the NOX CEMS data to determine excess
emissions?

    (a) If you demonstrate continuous compliance using a CEMS for
measuring NOX emissions, excess emissions are defined as the
applicable compliance period for the stationary combustion turbine
(either 4-operating hours or 30-operating days), during which the
average NOX emissions from your affected facility measured
by the CEMS is greater than the applicable maximum allowable
NOX emissions standard specified in Sec.  60.4320 as
determined using the procedures specified in this section that apply to
your stationary combustion turbine.
    (b) The NOX CEMS data for each operating hour as
measured according to the requirements in Sec.  60.4345 must be used to
determine the hourly average NOX emissions. The hourly
average for a given operating hour is the average of all data points
for the operating hour. However, for any periods during which the
NOX, diluent, flow, watt, steam pressure, or steam
temperature monitors (as applicable) are out-of-control, the data
points are not used in determining the hourly average NOX
emissions. All data points that are not collected during out-of-control
periods must be used to determine the hourly average NOX
emissions.

    (c) For each operating hour in which an hourly average is obtained,
the data acquisition and handling system must calculate and record the
hourly average NOX emissions in units of ppm or lb/MMBtu,
using the appropriate equation from EPA Method 19 in appendix A-7 of
this part. For any hour in which the hourly average O2
concentration exceeds 19.0 percent O2 (or the hourly average
CO2 concentration is less than 1.0 percent CO2),
a diluent cap value of 19.0 percent O2 or 1.0 percent
CO2 (as applicable) may be used in the emission
calculations.
    (d) Correction of measured NOX concentrations to 15
percent O2 is only allowed if you elect to comply with the
ppm standard in Table 1 of this subpart.
    (e) Data used to meet the requirements of this subpart shall not
include substitute data values derived from the missing data procedures
of part 75 of this chapter, nor shall the data be bias adjusted
according to the procedures of part 75 of this chapter.
    (f) All required fuel flow rate, steam flow rate, temperature,
pressure, and megawatt data must be reduced to hourly averages.
However, for any periods during which the flow, watt, steam pressure,
or steam temperature monitors (as applicable) are out-of-control, the
data points are not used in determining the appropriate hourly average
value
    (g) Calculate the hourly average NOX emissions rate, in
units of the emissions standard under Sec.  60.4320, using either ppm
or lb/MMBtu for units complying with the input-based standard or
equation 1 of this subpart for units complying with the output-based
standard:
    (1) For a stationary combustion turbine complying with an output-
based emissions standard use Equation 1.
[GRAPHIC] [TIFF OMITTED] TP29AU12.000

Where:

E = Hourly NOX emissions rate, in lb/MWh,
(NOX)h = Average hourly NOX
emissions rate, in lb/MMBtu,
Q = Hourly heat input to the stationary combustion turbine, in
MMBtu, measured using the fuel flowmeter(s), e.g., calculated using
Equation D-15a in appendix D to part 75 of this chapter, an
O2 or CO2 CEMS and a stack flow meter, or the
methodologies in appendix F to part 75 of this chapter, and
P = Gross energy output of the stationary combustion turbine in MWh.

    (2) The gross energy output is calculated as the sum of the total
electrical and mechanical energy generated by the combustion turbine
engine, the additional electrical or mechanical energy (if any)
generated by the steam turbine following the heat recovery steam
generating unit, and the total useful thermal energy output that is not
used to generate additional electricity or mechanical output, expressed
in equivalent MWh, as calculated using Equations 2 and 3 of this
subpart:
[GRAPHIC] [TIFF OMITTED] TP29AU12.001

Where:

P = Gross energy output of the stationary combustion turbine system
in MWh,
(Pe)t = Electrical or mechanical energy output of the
stationary combustion turbine in MWh,
(Pe)c = Electrical or mechanical energy output (if any)
of the steam turbine in MWh,
Ps = Useful thermal energy of the steam, measured
relative to ISO conditions, not used to generate additional electric
or mechanical output, in MWh, and
Po = Other useful heat recovery, measured relative to ISO
conditions, not used for steam generation or performance enhancement
of the stationary combustion turbine.
T = Electric Transmission and Distribution Factor. Equal to 0.95 for
CHP combustion turbine where at least 20.0 percent of the total
gross useful energy output consists of electric or direct mechanical
output and 20.0 percent of the total gross useful energy output
consists of useful thermal output on an annual basis. Equal to 1.0
for all other combustion turbines.

[GRAPHIC] [TIFF OMITTED] TP29AU12.002

Where:

Ps = Useful thermal energy of the steam, measured
relative to ISO conditions, not used to generate additional electric
or mechanical output, in MWh,
Qm = Measured steam flow in lb,
H = Enthalpy of the steam at measured temperature and pressure
relative to ISO conditions, in Btu/lb, and
3.413 x 10\6\ = Conversion factor from Btu to MWh.

    (3) For mechanical drive applications complying with the output-
based standard, use equation 4 of this subpart:
[GRAPHIC] [TIFF OMITTED] TP29AU12.003

Where:

E = NOX emissions rate in lb/MWh,
(NOX)m = NOX emissions rate in lb/
h,
BL = Manufacturer's base load rating of turbine, in MW, and
AL = Actual load as a percentage of the base load rating.

    (h) For each simple cycle stationary combustion turbines, excess
NOX emissions are determined on a 4-operating hour averaging
period basis using the NOX CEMS data and procedures
specified in paragraphs (h)(1) through (4) of this section as
applicable to the NOX emissions standard in Table 1 to this
subpart.
    (1) For each 4-operating hour period, compute the 4-operating hour
rolling average NOX emissions as the heat input weighted
average of the hourly average of NOX emissions for a given
operating hour and the 3 operating hours immediately preceding that
operating hour using the applicable equation in paragraphs (h)(2)
through (4) of this section. If the 4-operating hour period contains
more than one operating hour with no data points (one or more
continuous monitors was out-of-control for the entire hour), report the
4-operating hour rolling average NOX emissions rate
determined for the period as occurring during a period with monitor
downtime.
    (2) If you elect to comply with the applicable heat input-based
emissions rate standard, calculate both the 4-operating hour rolling
average NOX emissions rate and the applicable 4-operating
hour rolling average NOX emissions standard, calculated
using hourly values from in Table 1, using Equation 5 of this subpart.

[GRAPHIC] [TIFF OMITTED] TP29AU12.004

Where:

E = 4-operating hour rolling average NOX emissions (lb/
MMBtu or ng/J),
Ei = Hourly average NOX emissions rate or
emissions standard for operating hour ``i'' (lb/MMBtu or ng/J), and
Qi = Total heat input to stationary combustion turbine
for operating hour ``i'' (MMBtu or J as appropriate).

    (3) If you elect to comply with the applicable output-based
emissions rate standard, calculate the 4-operating hour rolling average
NOX emissions rate using equation 6-1 of this subpart.
Calculate the applicable 4-operating hour rolling average
NOX emissions standard, calculated using hourly values from
in Table 1, using Equation 6-2 of this subpart.
[GRAPHIC] [TIFF OMITTED] TP29AU12.005

Where:
E = 4-operating hour rolling average NOX emissions rate
(lb/MWh or ng/J),
Ei = Hourly average NOX emissions rate for
operating hour ``i'' (lb/MMBtu or ng/J),
Qi = Total heat input to stationary combustion turbine
for operating hour ``i'' (MMBtu or J as appropriate), and
Pi = Total gross energy output from stationary combustion
turbine for operating hour ``i'' (MWh or J).
[GRAPHIC] [TIFF OMITTED] TP29AU12.006

Where:

E = 4-operating hour rolling average NOX emissions
standard (lb/MWh or ng/J),
Ei = Hourly NOX emissions standard for
operating hour ``i'' (lb/MWh or ng/J), and
Pi = Total gross energy output from stationary combustion
turbine for operating hour ``i'' (MWh or J).

    (4) If you elect to comply with the applicable concentration
standard using a numerical average, calculate both the 4-operating hour
rolling average NOX emissions rate and the applicable 4-
operating hour rolling average NOX emissions standard,
calculated using hourly values from in Table 1, using Equation 7 of
this subpart.
[GRAPHIC] [TIFF OMITTED] TP29AU12.007

Where:

E = 4-operating hour rolling average NOX emissions (ppm),
and
Cavei = 1-hour average NOX concentration as
determined using the procedure in Sec.  60.13(h) or emissions
standard for operating hour ``i'' (ppm).
    (i) For each combined cycle combustion turbine and CHP combustion
turbine, you must determine excess emissions on a 30 operating-day
rolling average basis. The measured emissions rate is the
NOX emissions measured by the CEMS for a given operating day
and the 29 operating days immediately preceding that day. Once each
day, calculate a new 30-operating day average measured emissions rate
using all hourly average values based on non out-of-control
NOX emission data for all operating hours during the
previous 30-operating day operating period. Report any 30-operating day
periods for which you have less than 75 percent data availability as
monitor downtime. If you elect to comply with the applicable heat
input-based emissions rate standard, calculate both the measured
emissions rate and emissions standard using Equation 8 of this subpart.
If you elect to comply with the applicable output-based emissions rate
standard, calculate the measured emissions rate using Equation 9-1 of
this subpart and calculate the emissions standard using Equation 9-2 of
this subpart. If you elect to comply with the applicable concentration
standard using a numerical average, calculate the measured emissions
rate and emissions standard using Equation 10 of this subpart.
[GRAPHIC] [TIFF OMITTED] TP29AU12.008

Where:

E = 30-operating day rolling average NOX measured
emissions rate or emissions standard for combined cycle combustion
turbines and CHP combustion turbines (lb/MMBtu or ng/J),
Ei = Hourly average NOX emissions rate or
emissions standard for non out-of-control operating hour ``i'' (lb/
MMBtu or ng/J),
Qi = Total heat input to stationary combustion turbine
for non out-of-control operating hour ``i'' (MMBtu or J as
appropriate), and
n = Total number of non out-of-control operating hours in the 30
operating-day period.
[GRAPHIC] [TIFF OMITTED] TP29AU12.009

Where:

E = 30-operating day average NOX measured emissions rate
for combined cycle combustion turbines and CHP combustion turbines
(lb/MWh or ng/J),
Ei = Hourly average NOX emissions rate for non
out-of-control operating hour ``i'' (lb/MMBtu or ng/J),
Qi = Total heat input to stationary combustion turbine
for non out-of-control operating hour ``i'' (MMBtu or J as
appropriate),
Pi = Total gross energy output from stationary combustion
turbine for non out-of-control operating hour ``i'' (MWh or J), and
n = Total number of operating non out-of-control hours in the 30
operating-day period.
[GRAPHIC] [TIFF OMITTED] TP29AU12.010

Where:

E = 30-operating day average NOX emissions standard for
combined cycle combustion turbines and CHP combustion turbines (lb/
MWh or ng/J),
Ei = Hourly NOX emissions standard for non
out-of-control operating hour ``i'' (lb/MWh or ng/J),
Pi = Total gross energy output from stationary combustion
turbine for non out-of-control operating hour ``i'' (MWh or J), and
n = Total number of operating non out-of-control hours in the 30
operating-day period.
[GRAPHIC] [TIFF OMITTED] TP29AU12.011

Where:

E = 30-operating day rolling average NOX measured
emissions rate or emissions standard for combined cycle combustion
turbines and CHP combustion turbines (ppm),
Cavei = 1-hour average NOX concentration as
determined using the procedure in Sec.  60.13(h) or emissions
standard for non out-of-control operating hour ``i'' (ppm), and
n = Total number of operating hours in the 30 operating-day period.

Sec.  60.4360  How do I use fuel sulfur analysis to determine the total
sulfur content of the fuel combusted in my stationary combustion
turbine?

    (a) If you elect to demonstrate compliance with a SO2