Document ID: EPA-HQ-OAR-2004-0490-0327
Agency: epa
Document Type: Proposed Rule
Title: Standards of Performance for Stationary Gas Turbines; Standards of Performance for Stationary Combustion Turbines
Posted Date: 2012-08-29T04:00Z

[Federal Register Volume 77, Number 168 (Wednesday, August 29, 2012)]
[Proposed Rules]
[Pages 52553-52581]
From the Federal Register Online via the Government Printing Office [www.gpo.gov]
[FR Doc No: 2012-20524]

[[Page 52553]]

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  

[[Page 52554]]

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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: a-and-r-docket@epa.gov.
     Fax: (202) 566-9744.
     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 (202) 566-1744, and the telephone 
number for the Air and Radiation Docket is (202) 566-1742.
    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 (919) 541-4003, 
facsimile number (919) 541-5450, electronic mail (email) address: 
fellner.christian@epa.gov.

SUPPLEMENTARY INFORMATION: Regulated Entities: Entities potentially 
affected by this proposed action include, but are not limited to, the 
following:

[[Page 52555]]

------------------------------------------------------------------------
                                                 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.
------------------------------------------------------------------------
\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,

[[Page 52556]]

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

[[Page 52557]]

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

[[Page 52558]]

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

[[Page 52559]]

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

[[Page 52560]]

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

[[Page 52561]]

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

[[Page 52562]]

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

[[Page 52563]]

    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]
* * * * *

[[Page 52564]]

    (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

[[Page 52565]]

(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

[[Page 52566]]

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

[[Page 52567]]

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

[[Page 52568]]

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

[[Page 52569]]

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.

[[Page 52570]]

    (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.

[[Page 52571]]

[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.

[[Page 52572]]

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 
emissions standard according to Sec.  60.4333(d)(2), the fuel analyses 
may be performed either by you, a service contractor retained by you, 
the fuel vendor, or any other qualified agency as determined by the 
delegated permitting authority using the sampling frequency specified 
in Sec.  60.4365.
    (b) Representative fuel analysis samples may be collected either 
manually or by an automatic sampling system. For automatic sampling, 
following ASTM D5287 (incorporated by reference, see Sec.  60.17) for 
gaseous fuels or ASTM D4177 (incorporated by reference, see Sec.  
60.17) for liquid fuels. For reference purposes when manually 
collecting gaseous samples, see Gas Processors Association Standard 
2166 (incorporated by reference, see Sec.  60.17). For reference 
purposes when manually collecting liquid samples, see either Gas 
Processors Association Standard 2174 or the procedures for manual 
pipeline sampling in section 14 of ASTM D4057 (both of which are 
incorporated by reference, see Sec.  60.17).
    (c) Each collected fuel analysis sample must be analyzed for the 
total sulfur content of the fuel and heating value using the methods 
specified in paragraphs (c)(1) or (2) of this section, as applicable to 
the fuel type.
    (1) For the sulfur content of liquid fuels, ASTM D129, or 
alternatively D1266, D1552, D2622, D4294, or D5453 (all of which are 
incorporated by reference, see Sec.  60.17). For the heating value of 
liquid fuels, ASTM D240 or D4809 (both of which are incorporated by 
reference, see Sec.  60.17); or
    (2) For the sulfur content of gaseous fuels, ASTM D1072, or 
alternatively D3246, D4468, or D6667 (all of which are incorporated by 
reference, see Sec.  60.17). If the total sulfur content of the gaseous 
fuel during the most recent compliance demonstration was less than half 
the applicable standard, ASTM D4084, D4810, D5504, or D6228, or Gas 
Processors Association Standard 2377 (all of which are incorporated by 
reference, see Sec.  60.17), which measure the major sulfur compounds, 
may be used. For the heating value of gaseous fuels, ASTM D1826, or 
alternatively D3588, D4891, or D7164, or Gas Processors Association 
Standard 2172 (all of which are incorporated by reference, see Sec.  
60.17).

Sec.  60.4365  How frequently must I determine the fuel sulfur content?

    (a) If you are complying with requirements in Sec.  60.4360, the 
total sulfur content of all fuels combusted in each stationary 
combustion turbine subject to an SO2 emissions standard in 
Sec.  60.4330 must be determined according to the schedule specified in 
paragraphs (a)(1) or (2) of this section, as applicable to the fuel 
type, unless you determine a custom schedule for the stationary 
combustion turbine according to paragraph (b) of this section.
    (1) Liquid fuel. Use one of the total sulfur sampling options and 
the associated sampling frequency described in sections 2.2.3, 2.2.4.1, 
2.2.4.2, and 2.2.4.3 in appendix D to part 75 of this chapter (i.e. 
flow proportional sampling, daily sampling, sampling from the unit's 
storage tank after each addition of fuel to the tank, or sampling each 
delivery prior to combining it with liquid fuel already in the intended 
storage tank).
    (2) Gaseous fuel. If the fuel is supplied without intermediate bulk 
storage, the sulfur content value of the gaseous fuel must be 
determined and recorded once per operating day.
    (b) Custom schedules. As an alternative to the requirements of 
paragraph (a) of this section, you may implement custom schedules for 
determination of the total sulfur content of gaseous fuels, based on 
the design and operation of the affected facility and the 
characteristics of the fuel supply using the procedures provided in 
either paragraph (b)(1) and (2) of this section. Either you or the fuel 
vendor may perform the sampling. As an alternative to using one of 
these procedures, you may use a custom schedule that has been 
substantiated with data and approved by the Administrator or delegated 
authority as a change in monitoring prior to being used to comply with 
the applicable standard in Sec.  60.4330.
    (1) You may determine and implement a custom sulfur sampling 
schedule for your stationary combustion turbine using the procedure 
specified in paragraphs (b)(1)(i) through (iv) of this section.
    (i) Obtain daily total sulfur content measurements for 30 
consecutive operating days, using the applicable methods specified in 
this subpart. Based on the results of the 30 daily samples, the 
required frequency for subsequent monitoring of the fuel's total sulfur 
content must be as specified in paragraph (b)(1)(ii), (iii), or (iv) of 
this section, as applicable.
    (ii) If none of the 30 daily measurements of the fuel's total 
sulfur content exceeds half the applicable standard, subsequent sulfur 
content monitoring may be performed at 12-month intervals provided the 
fuel source or supplier does not change. If any of the samples taken at 
12-month intervals has a total sulfur content greater than half but 
less than the applicable standard, follow the procedures in paragraph 
(b)(1)(iii) of this section. If any measurement exceeds the applicable 
standard, follow the procedures in paragraph (b)(1)(iv) of this 
section.
    (iii) If at least one of the 30 daily measurements of the fuel's 
total sulfur content is greater than half but less than the applicable 
standard, but none exceeds the applicable standard, then:
    (A) Collect and analyze a sample every 30 days for 3 months. If any 
sulfur content measurement exceeds the applicable standard, follow the 
procedures in paragraph (b)(1)(iv) of this section. Otherwise, follow 
the procedures in paragraph (b)(1)(iii)(B) of this section.
    (B) Begin monitoring at 6-month intervals for 12 months. If any 
sulfur content measurement exceeds the applicable standard, follow the 
procedures in paragraph (b)(1)(iv) of this section. Otherwise, follow 
the procedures in paragraph (b)(1)(iii)(C) of this section.
    (C) Begin monitoring at 12-month intervals. If any sulfur content 
measurement exceeds the applicable standard, follow the procedures in 
paragraph (b)(1)(iv) of this section. Otherwise, continue to monitor at 
this frequency.
    (iv) If a sulfur content measurement exceeds the applicable 
standard, immediately begin daily monitoring according to paragraph 
(c)(1)(i) of this section. Daily monitoring must continue until 30 
consecutive daily samples, each having a sulfur content no greater than 
the applicable standard, are obtained. At that point, the applicable 
procedures of paragraph (b)(1)(ii) or (iii) of this section must be 
followed.
    (2) You may use the data collected from the 720-hour sulfur 
sampling demonstration described in section 2.3.6 in appendix D to part 
75 of this chapter to determine and implement a sulfur sampling 
schedule for your stationary combustion turbine using the procedure 
specified in paragraphs (b)(2)(i) through (iii) of this section.
    (i) If the maximum fuel sulfur content obtained from any of the 720 
hourly samples does not exceed half the applicable standard, then the 
minimum required sampling frequency must be one sample at 12 month 
intervals.

[[Page 52573]]

    (ii) If any sample result exceeds half the applicable standard, but 
none exceeds the applicable standard, follow the provisions of 
paragraph (b)(1)(iii) of this section.
    (iii) If the sulfur content of any of the 720 hourly samples 
exceeds the applicable standard, follow the provisions of paragraph 
(b)(1)(iv) of this section.

Sec.  60.4370  How do I demonstrate compliance with my SO2 
emissions standard using records of the fuel sulfur content?

    (a) If you elect to demonstrate compliance with a SO2 
emissions standard according to Sec.  60.4333(d)(3), you must maintain 
on-site records (such as a current, valid purchase contract, tariff 
sheet, or transportation contract) documenting that total sulfur 
content for the fuel combusted in your stationary combustion turbine at 
all times does not exceed the conditions specified in paragraph (b) 
through (e) of this section, as applicable to your stationary 
combustion turbine.
    (b) If your stationary combustion turbine is subject to the 
SO2 emissions standard in Sec.  60.4330(a), then the fuel 
combusted must have a potential SO2 emissions rate of 26 ng/
J (0.060 lb/MMBtu) heat input or less.
    (c) If your stationary combustion turbine is subject to the 
SO2 emissions standard in Sec.  60.4330(b), then the total 
sulfur content of the gaseous fuel combusted must be 650 (mg/scm) (28 
gr/100 scf).
    (d) If your stationary combustion turbine is subject to the 
SO2 emissions standard in Sec.  60.4330(c) or (d), the total 
sulfur content of the fuel combusted must be:
    (1) For natural gas, 140 gr/100 scf or less.
    (2) For fuel oil, 0.40 weight percent (4,000 ppmw) or less.
    (3) For other fuels, potential SO2 emissions of 180 ng/J 
(0.42 lb/MMBtu) heat input or less.
    (e) Representative fuel sampling data following the procedures 
specified in section 2.3.1.4 or 2.3.2.4 in appendix D to part 75 of 
this chapter documenting that the fuel meets the part 75 requirements 
to be considered either pipeline natural gas or natural gas.

Sec.  60.4372  How do I demonstrate compliance with my SO2 
emissions standard and determine excess emissions using a 
SO2 CEMS?

    (a) If you demonstrate continuous compliance using a CEMS for 
measuring SO2 emissions, excess emissions are defined as the 
applicable averaging period, either 4-operating hour or 30-operating 
day, during which the average SO2 emissions from your 
stationary combustion turbine measured by the CEMS exceeds the 
applicable SO2 emissions standard specified in Sec.  60.4330 
as determined using the procedures specified in this section that apply 
to your stationary combustion turbine.
    (b) You must install, calibrate, maintain, and operate a CEMS for 
measuring SO2 concentrations and either O2 or 
CO2 concentrations at the outlet of your stationary 
combustion turbine, and record the output of the system.
    (c) The 1-hour average SO2 emissions rate measured by a 
CEMS must be expressed in ng/J or lb/MMBtu heat input and must be used 
to calculate the average emissions rate under Sec.  60.4330.
    (d) You must use the procedures for installation, evaluation, and 
operation of the CEMS as specified in Sec.  60.13 and paragraphs (d)(1) 
through (3) of this section.
    (1) Each CEMS must be operated according to the applicable 
procedures under Performance Specifications 1, 2, and 3 in appendix B 
of this part;
    (2) Quarterly accuracy determinations and daily calibration drift 
tests must be performed according to Procedure 1 in appendix F of this 
part; and
    (3) The span value of the SO2 CEMS at the outlet from 
the SO2 control device (or outlet of the stationary 
combustion turbine if no SO2 control device is used) must be 
125 percent of either the highest applicable standard or highest 
potential SO2 emissions rate of the fuel combusted.
    (e) Correction of measured SO2 concentrations to 15 
percent O2 is not allowed.
    (f) If you have installed and certified a SO2 CEMS that 
meets the requirements of part 75 of this chapter, the delegated 
permitting authority can approve that only quality assured data from 
the CEMS must be used to identify excess emissions under this subpart. 
You must report periods where the missing data substitution procedures 
in subpart D of part 75 are applied as monitoring system downtime in 
the excess emissions and monitoring performance report required under 
Sec.  60.7(c).
    (g) All required fuel flow rate, steam flow rate, temperature, 
pressure, and megawatt data must be reduced to hourly averages.
    (h) Calculate the hourly average SO2 emissions rate, in 
units of the emissions standard under Sec.  60.4330, using lb/MMBtu for 
units complying with the input-based standard or using equation 11 of 
this subpart for units complying with the output-based standard:
    (1) For simple-cycle operation:
    [GRAPHIC] [TIFF OMITTED] TP29AU12.012
    

Where:

E = Hourly SO2 emissions rate, in lb/MWh,
(SO2)h = Average hourly SO2 
emissions rate, in lb/MMBtu,
Q = Hourly heat input rate to the stationary combustion turbine, in 
MMBtu, measured using the fuel flow meter(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 stationary combustion 
turbine, 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 12 and 13 of this 
subpart.
[GRAPHIC] [TIFF OMITTED] TP29AU12.013

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,

[[Page 52574]]

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] TP29AU12.014

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 rate 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 14 of this subpart:
[GRAPHIC] [TIFF OMITTED] TP29AU12.015

Where:

E = SO2 emissions rate in lb/MWh,
(SO2)m = SO2 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.

    (i) For stationary combustion turbines other than combined cycle 
combustion turbines and CHP combustion turbines, you must determine 
excess emissions on a 4-operating hour rolling average basis. The ``4-
operating hour rolling average SO2 measured emissions rate'' 
is the SO2 emissions measured by the CEMS for a given 
operating hour and the 3 consecutive operating hours immediately 
preceding that hour expressed in the units appropriate for the 
SO2 emissions standard that is applied to your stationary 
combustion turbine. Each operating hour, calculate the 4-operating hour 
rolling average SO2 measured emissions rate using all of the 
non out-of-control SO2 emission data obtained during the 
previous 4-operating hour operating period. If the 4-operating hour 
period contains more than one operating hour with no data points (one 
or more CEMS was out-of-control for the entire hour), report the 4-
operating hour rolling average SO2 emissions rate determined 
for the period as occurring during a period with monitor downtime. If 
you elect to comply with the applicable heat input-based emissions rate 
standard, calculate both the measured emissions rate and the emissions 
standard using Equation 15 of this subpart. If you elect to comply with 
the applicable output-based emissions standard, calculate the measured 
emissions rate using Equation 16-1 of this subpart and calculate the 
emissions standard using Equation 16-2 of this subpart.
[GRAPHIC] [TIFF OMITTED] TP29AU12.016

Where:

E = 4-operating hour rolling average SO2 measured 
emissions rate or emissions standard for stationary combustion 
turbines other than combined cycle combustion turbines and CHP 
combustion turbines (lb/MMBtu or ng/J),
    Ei = Hourly average SO2 emissions rate or 
emissions standard for non out-of-control operating hour ``i'' (lb/
MMBtu or ng/J), and
    Qi = Total heat input to stationary combustion 
turbine for non out-of-control operating hour ``i'' (MMBtu or J as 
appropriate).

[GRAPHIC] [TIFF OMITTED] TP29AU12.017

Where:

E = 4-operating hour rolling average SO2 measured 
emissions rate for stationary combustion turbines other than 
combined cycle combustion turbines and CHP combustion turbines (lb/
MWh or ng/J),
Ei = Hourly average SO2 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), and
Pi = Total gross energy output from stationary combustion 
turbine for non out-of-control operating hour ``i'' (MWh or J).
[GRAPHIC] [TIFF OMITTED] TP29AU12.018

Where:

E = 4-operating hour rolling average SO2 emissions 
standard for stationary combustion turbines other than combined 
cycle combustion turbines and CHP combustion turbines (lb/MWh or ng/
J),
Ei = Hourly SO2 emissions standard for non 
out-of-control operating hour ``i'' (lb/MMBtu or ng/J), and
Pi = Total gross energy output from stationary combustion 
turbine for non out-of-control operating hour ``i'' (MWh or J).

    (ii) For combined cycle combustion turbines and CHP combustion 
turbines, you must determine excess emissions on a 30 operating-day 
rolling average basis. The excess emissions level is the heat input 
weighted-average of the SO2 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 SO2 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 standard, calculate the measured 
emissions rate and emissions rate using Equation 17 of this subpart. If 
you elect to comply with the applicable output-based standard, 
calculate the measured emissions rate using Equation 18-1 of this 
subpart and calculate the emissions standard using Equation 18-2 of 
this subpart.
[GRAPHIC] [TIFF OMITTED] TP29AU12.019

Where:

[[Page 52575]]

E = 30-operating day rolling average SO2 measured 
emissions rate or emissions standard for combined cycle combustion 
turbines and CHP combustion turbines (lb/MMBtu or ng/J),
Ei = Hourly average SO2 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] TP29AU12.020

Where:

E = 30-operating day average SO2 measured emissions rate 
for combined cycle combustion turbines and CHP combustion turbines 
(lb/MWh or ng/J),
Ei = Hourly average SO2 measured 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 non out-of-control operating hours in the 30 
operating-day period.
[GRAPHIC] [TIFF OMITTED] TP29AU12.021

Where:

E = 30-operating day average SO2 emissions standard for 
combined cycle combustion turbines and CHP combustion turbines (lb/
MWh or ng/J),
Ei = Hourly SO2 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 non out-of-control operating hours in the 30 
operating-day period.

Recordkeeping and Reporting

Sec.  60.4375  What reports must I submit?

    (a) An owner or operator of a stationary combustion turbine that 
elects to continuously monitor parameters or emissions, or to 
periodically determine the fuel sulfur content under this subpart, must 
submit reports of excess emissions and monitor downtime, according to 
Sec.  60.7(c). Excess emissions must be reported for all periods of 
unit operation, including startup, shutdown, and malfunction.
    (b) An owner or operator of a stationary combustion turbine that 
performs performance tests to demonstrate compliance with this subpart 
must submit a written report of the results of each performance test 
before the close of business on the 60th day following the completion 
of the performance test, except as specified in paragraph (c) of this 
part.
    (c)(1) Within 60 days after the date of completing each performance 
test (see Sec.  60.8) as required by this subpart you must submit the 
results of the performance tests required by this subpart to EPA's 
WebFIRE database by using the Compliance and Emissions Data Reporting 
Interface (CEDRI) that is accessed through EPA's Central Data Exchange 
(CDX) (www.epa.gov/cdx). Performance test data must be submitted in the 
file format generated through use of EPA's Electronic Reporting Tool 
(ERT) (see http://www.epa.gov/ttn/chief/ert/index.html). Only data 
collected using test methods on the ERT Web site are subject to this 
requirement for submitting reports electronically to WebFIRE. Owners or 
operators who claim that some of the information being submitted for 
performance tests is confidential business information (CBI) must 
submit a complete ERT file including information claimed to be CBI on a 
compact disk or other commonly used electronic storage media 
(including, but not limited to, flash drives) to EPA. The electronic 
media must be clearly marked as CBI and mailed to U.S. EPA/OAPQS/CORE 
CBI Office, Attention: WebFIRE Administrator, MD C404-02, 4930 Old Page 
Rd., Durham, NC 27703. The same ERT file with the CBI omitted must be 
submitted to EPA via CDX as described earlier in this paragraph. At the 
discretion of the delegated authority, you must also submit these 
reports, including the confidential business information, to the 
delegated authority in the format specified by the delegated authority.
    (2) Within 60 days after the date of completing each CEMS 
performance evaluation test (see Sec.  60.13), you must submit the 
relative accuracy test audit data electronically into EPA's Central 
Data Exchange by using the Electronic Reporting Tool as mentioned in 
paragraph (c)(1) of this section. Only data collected using test 
methods compatible with ERT are subject to this requirement to be 
submitted electronically to EPA's CDX.
    (3) All reports required by this subpart not subject to the 
requirements in paragraphs (c)(1) and (2) of this section must be sent 
to the Administrator or delegated authority at the appropriate address 
listed in Sec.  63.13. The Administrator or delegated authority may 
request a report in any form suitable for the specific case (e.g., by 
commonly used electronic media such as Excel spreadsheet, on CD or hard 
copy). The Administrator or delegated authority retains the right to 
require submittal of reports subject to paragraphs (c)(1) and (2) of 
this section in paper format.
    (d) The notification requirements of Sec.  60.8 apply to the 
initial and subsequent performance tests.
    (e) An owner or operator of an affected facility complying with 
Sec.  60.4333(b)(3) must notify the delegated permitting authority 
within 15 calendar days after the facility recommences operation.
    (f) An owner or operator of an affected facility complying with 
Sec.  60.4333(b)(4) must notify the delegated permitting authority 
within 15 calendar days after the facility has operated more than 50 
operating hours since the date the previous performance test was 
required to be conducted.

Sec.  60.4380  How are NOX excess emissions and monitor 
downtime reported?

    (a) For reports required under Sec.  60.4375(a), periods of excess 
emissions and monitor downtime for stationary combustion turbines using 
water or steam to fuel ratio monitoring are reported as specified in 
paragraphs (a)(1) through (3) of this section.
    (1) An excess emission that must be reported is any operating hour 
for which the 4-operating hour rolling average steam or water to fuel 
ratio, as measured by the continuous monitoring system, is less than 
the acceptable steam or water to fuel ratio needed to demonstrate 
compliance with Sec.  60.4320, as established during the most recent 
performance test. Any operating hour during which no water or steam is 
injected into the turbine when the specific conditions require water or 
steam injection for NOX control will also be considered an 
excess emission.
    (2) A period of monitor downtime that must be reported is any 
operating hour in which water or steam is injected into the turbine, 
but the parametric data needed to determine the steam or water to fuel 
ratio are unavailable or out-of-control.
    (3) Each report must include the average steam or water to fuel 
ratio,

[[Page 52576]]

average fuel consumption, and the stationary combustion turbine load 
during each excess emission.
    (b) For reports required under Sec.  60.4375(a), periods of excess 
emissions and monitor downtime for stationary combustion turbines using 
a CEMS, excess emissions are reported as specified in paragraphs (b)(1) 
through (3) of this section.
    (1) An excess emission that must be reported is any unit operating 
period in which the 4-operating hour or 30-operating day rolling 
average NOX emissions rate exceeds the applicable emissions 
standard in Sec.  60.4320 as determined in Sec.  60.4350.
    (2) A period of monitor downtime that must be reported is any 
operating hour in which the data for any of the following parameters 
are either missing or out-of-control: NOX concentration, 
CO2 or O2 concentration, stack flow rate, heat 
input rate, steam flow rate, steam temperature, steam pressure, or 
megawatts. You are only required to monitor parameters used for 
compliance purposes.
    (3) For hours with multiple emission standards, the applicable 
standard for that hour is determined based on the condition, excluding 
periods of monitor downtime, that corresponded to the highest emissions 
standard.
    (c) For reports required under Sec.  60.4375(a), periods of excess 
emissions and monitor downtime for stationary combustion turbines using 
combustion parameters or parameters that document proper operation of 
the NOX emission controls excess emissions and monitor 
downtime are reported as specified in paragraphs (c)(1) and (2) of this 
section.
    (1) Excess emissions that must be reported are each 4-operating 
hour rolling average in which any monitored parameter (as averaged over 
the 4 operating-hour period) does not achieve the target value or is 
outside the acceptable range defined in the parameter monitoring plan 
for the unit.
    (2) Periods of monitor downtime that must be reported are each 
operating hour in which any of the required parametric data are either 
not recorded or are out-of-control.

Sec.  60.4385  How are SO2 excess emissions and monitor 
downtime reported?

    (a) If you choose the option to monitor the sulfur content of the 
fuel, excess emissions and monitor downtime are defined as follows:
    (1) For samples obtained using daily sampling, flow proportional 
sampling, or sampling from the unit's storage tank, excess emissions 
occur each operating hour included in the period beginning on the date 
and hour of any sample for which the sulfur content of the fuel being 
fired in the stationary combustion turbine exceeds the applicable 
standard and ending on the date and hour that a subsequent sample is 
taken that demonstrates compliance with the sulfur standard.
    (2) If the option to sample each delivery of fuel oil has been 
selected, you must immediately switch to one of the other oil sampling 
options (i.e., daily sampling, flow proportional sampling, or sampling 
from the unit's storage tank) if the sulfur content of a delivery 
exceeds 0.05 weight percent, 0.15 weight percent, or 0.40 weight 
percent as applicable. You must continue to use one of the other 
sampling options until all of the oil from the delivery has been 
combusted, and you must evaluate excess emissions according to 
paragraph (a) of this section. When all of the fuel from the delivery 
has been combusted, you may resume using the as-delivered sampling 
option.
    (3) A period of monitor downtime begins when a required sample is 
not taken by its due date. A period of monitor downtime also begins on 
the date and hour of a required sample, if invalid results are 
obtained. The period of monitor downtime ends on the date and hour of 
the next valid sample.
    (b) If you choose the option to maintain records of the fuel sulfur 
content, excess emissions are defined as any period during which you 
burn a fuel that you do not have appropriate fuel records or that fuel 
contains sulfur greater than the applicable standard.
    (c) For reports required under Sec.  60.4375(a), periods of excess 
emissions and monitor downtime for stationary combustion turbines using 
a CEMS, excess emissions are reported as specified in paragraphs (c)(1) 
through (2) of this section.
    (1) An excess emission that must be reported is any unit operating 
period in which the 4-operating hour or 30-operating day rolling 
average SO2 emissions rate exceeds the applicable emissions 
standard in Sec.  60.4330 as determined in Sec.  60.4372.
    (2) A period of monitor downtime that must be reported is any 
operating hour in which the data for any of the following parameters 
are either missing or out-of-control: SO2 concentration, 
CO2 or O2 concentration, stack flow rate, heat 
input rate, steam flow rate, steam temperature, steam pressure, or 
megawatts. You are only required to monitor parameters used for 
compliance purposes.

Sec.  60.4390  What records must I maintain?

    (a) You must maintain records of your information used to 
demonstrate compliance with this subpart as specified in Sec.  60.7.
    (b) An owner or operator of a stationary combustion turbine that 
uses the other fuels, part-load, or low temperature NOX 
standards in the compliance demonstration must maintain concurrent 
records of the hourly heat input, percent load, ambient temperature, 
and emissions data as applicable.
    (c) An owner or operator of a stationary combustion turbine that 
uses the tuning NOX standard in the compliance demonstration 
must identify the hours on which the maintenance was performed and a 
description of the maintenance.
    (d) An owner or operator of a stationary combustion turbine that 
demonstrates compliance using the output-based standard must maintain 
concurrent records of the total gross energy output and emissions data.
    (e) An owner or operator of a stationary combustion turbine that 
demonstrates compliance using the water or steam to fuel ratio or a 
parameter continuous monitoring system must maintain continuous records 
of the appropriate parameters.
    (f) An owner or operator of a stationary combustion turbine 
complying with the fuel based SO2 standard must maintain 
records of the results of all fuel analyses or a current, valid 
purchase contract, tariff sheet, or transportation contract.

Sec.  60.4395  When must I submit my reports?

    Consistent with Sec.  60.7(c), all reports required under Sec.  
60.7(c) must be postmarked by the 30th day following the end of each 6-
month period.

Performance Tests

Sec.  60.4400  How do I conduct performance tests to demonstrate 
compliance with my NOX emissions standard if I do not have a 
NOX CEMS?

    (a) You must conduct the performance test according to the 
requirements in Sec.  60.8 and paragraphs (b) through (d) of this 
section.
    (b) You must use the methods in either paragraph (b)(1) or (2) of 
this section to measure the NOX concentration for each test 
run.
    (1) Measure the NOX concentration using EPA Method 7E in 
appendix A-4 of this part or EPA Method 20 in appendix A-7 of this 
part. In addition, when only natural gas is being combusted ASTM D6522 
(incorporated by reference, see Sec.  60.17) can be used instead of EPA 
Method 20 in appendix

[[Page 52577]]

A-7 of this part to determine the oxygen content in the exhaust gas. 
For units complying with the output-based standard, concurrently 
measure the stack gas flow rate, using EPA Methods 1 and 2 in appendix 
A-1 of this part, and measure and record the electrical and thermal 
output from the unit. Then, use Equation 19 of this subpart to 
calculate the NOX emissions rate:
[GRAPHIC] [TIFF OMITTED] TP29AU12.022

Where:

E = NOX emissions rate, in lb/MWh,
1.194 x 10-7 = Conversion constant, in lb/dscf-ppm,
(NOX)c = Average NOX concentration 
for the run, in ppm,
Qstd = Average stack gas volumetric flow rate, in dscf/h, 
and
P = Average gross electrical and mechanical energy output of the 
stationary combustion turbine, in MW (for simple-cycle operation), 
for combined-cycle operation, the sum of all electrical and 
mechanical output from the combustion and steam turbines, or, for 
CHP operation, the sum of all electrical and mechanical output from 
the combustion and steam turbines plus all useful recovered thermal 
output not used for additional electric or mechanical generation or 
to enhance the performance of the stationary combustion turbine, in 
MW, calculated according to Sec.  60.4350.

    (2) Measure the NOX and diluent gas concentrations, 
using either EPA Method 7E in appendix A-4 of this part and EPA Method 
3A in appendix A-2 of this part, or EPA Method 20 in appendix A-7 of 
this part. In addition, when only natural gas is being combusted ASTM 
D6522 (incorporated by reference, see Sec.  60.17) can be used instead 
of EPA Method 3A in appendix A-2 of this part or EPA Method 20 in 
appendix A-7 of this part to determine the oxygen content in the 
exhaust gas. Concurrently measure the heat input to the unit, using a 
fuel flowmeter (or flowmeters), an O2 or CO2 CEMS 
along with a stack flow meter, or the methodologies in appendix F to 
part 75 of this chapter, and for units complying with the output-based 
standard measure the electrical, mechanical, and thermal output of the 
unit. Use EPA Method 19 in appendix A-7 of this part to calculate the 
NOX emissions rate in lb/MMBtu. Then, use Equations 1 and, 
if necessary, 2 and 3 of this subpart in Sec.  60.4350(f) to calculate 
the NOX emissions rate in lb/MWh.
    (c) You must use the methods in either paragraph (c)(1) or (2) of 
this section to select the sampling traverse points for NOX 
and (if applicable) diluent gas.
    (1) You must select the sampling traverse points for NOX 
and (if applicable) diluent gas according to EPA Method 20 in appendix 
A-7 of this part or EPA Method 1 in appendix A-1 of this part (non-
particulate procedures), and sampled for equal time intervals. The 
sampling must be performed with a traversing single-hole probe, or, if 
feasible, with a stationary multi-hole probe that samples each of the 
points sequentially. Alternatively, a multi-hole probe designed and 
documented to sample equal volumes from each hole may be used to sample 
simultaneously at the required points.
    (2) As an alternative to paragraph (c)(1) of this section, you may 
select the sampling traverse points for NOX and (if 
applicable) diluent gas according to requirements in paragraphs 
(c)(2)(i) and (ii) of this section.
    (i) You perform a stratification test for NOX and 
diluent pursuant to the procedures specified in section 6.5.6.1(a) 
through (e) in appendix A of part 75 of this chapter.
    (ii) Once the stratification sampling is completed, you use the 
following alternative sample point selection criteria for the 
performance test specified in paragraphs (c)(2)(ii)(A) through (
    (A) If each of the individual traverse point NOX 
concentrations is within 10 percent of the mean 
concentration for all traverse points, or the individual traverse point 
diluent concentrations differs by no more than 0.5 percent 
CO2 (or O2) from the mean for all traverse 
points, then you may use three points (located either 16.7, 50.0 and 
83.3 percent of the way across the stack or duct, or, for circular 
stacks or ducts greater than 2.4 meters (7.8 feet) in diameter, at 0.4, 
1.2, and 2.0 meters from the wall). The three points must be located 
along the measurement line that exhibited the highest average 
NOX concentration during the stratification test; or
    (B) For a stationary combustion turbine subject to a NOX 
emissions standard greater than 15 ppm at 15 percent O2, you 
may sample at a single point, located at least 1 meter from the stack 
wall or at the stack centroid if each of the individual traverse point 
NOX concentrations is within 5 percent of the 
mean concentration for all traverse points, or the individual traverse 
point diluent concentrations differs by no more than 0.3 
percent CO2 (or O2) from the mean for all 
traverse points; or
    (C) For a stationary combustion turbine subject to a NOX 
emissions standard less than or equal to 15 ppm at 15 percent 
O2, you may sample at a single point, located at least 1 
meter from the stack wall or at the stack centroid if each of the 
individual traverse point NOX concentrations is within 
2.5 percent of the mean concentration for all traverse 
points, or the individual traverse point diluent concentrations differs 
by no more than 0.15 percent CO2 (or 
O2) from the mean for all traverse points.
    (d) The performance test must be done at any load condition within 
plus or minus 25 percent of 100 percent of the base load rating. You 
may perform testing at the highest achievable load point, if at least 
75 percent of the base load rating cannot be achieved in practice. You 
must conduct three separate test runs for each performance test. The 
minimum time per run is 60 minutes.
    (1) If the stationary combustion turbine combusts both natural gas 
and fuels other than natural gas as primary or backup fuels, separate 
performance testing is required for each fuel.
    (2) For a combined cycle or CHP combustion turbine with 
supplemental heat (duct burner), you must measure the total 
NOX emissions downstream of the duct burner. The duct burner 
must be in operation during the performance test.
    (3) If water or steam injection is used to control NOX 
with no additional post-combustion NOX control and you 
choose to monitor the steam or water to fuel ratio in accordance with 
Sec.  60.4335, then that monitoring system must be operated 
concurrently with each EPA Method 20 in appendix A-7 of this part or 
EPA Method 7E in appendix A-4 of this part run and must be used to 
determine the fuel consumption and the steam or water to fuel ratio 
necessary to comply with the applicable Sec.  60.4320 NOX 
emissions standard.
    (4) If you elect to install a CEMS, the performance evaluation of 
the CEMS may either be conducted separately or

[[Page 52578]]

(as described in Sec.  60.4405) as part of the initial performance test 
of the affected unit.
    (5) The ambient temperature must be greater than 0 [deg]F during 
the performance test. The delegated permitting authority may approve 
performance testing below 0 [deg]F if the timing of the required 
performance test and environmental conditions make it impractical to 
test at ambient conditions greater than 0 [deg]F.

Sec.  60.4405  How do I conduct a performance test if I use a 
NOX CEMS?

    (a) If you use a CEMS the performance test must be performed 
according to the procedures specified in paragraph (b) of this section.
    (b) The initial performance test must use the procedure specified 
in paragraphs (b)(1) through (4) of this section.
    (1) Perform a minimum of nine RATA reference method runs, with a 
minimum time per run of 21 minutes, at a single load level, within plus 
or minus 25 percent of 100 percent of the base load rating. You may 
perform testing at the highest achievable load point, if at least 75 
percent of the base load rating cannot be achieved in practice. The 
ambient temperature must be greater than 0[emsp14][deg]F during the 
RATA runs. The delegated permitting authority may approve performance 
testing below 0 [deg]F if the timing of the required performance test 
and environmental conditions make it impractical to test at ambient 
conditions greater than 0 [deg]F.
    (2) For each RATA run, concurrently measure the heat input to the 
unit using a fuel flow meter (or flow meters) or the methodologies in 
appendix F to part 75 of this chapter, and for units complying with the 
output-based standard, measure the electrical and thermal output from 
the unit.
    (3) Use the test data both to demonstrate compliance with the 
applicable NOX emissions standard under Sec.  60.4320 and to 
provide the required reference method data for the RATA of the CEMS 
described under Sec.  60.4342.
    (4) Compliance with the applicable emissions standard in Sec.  
60.4320 is achieved if the sum of the NOX emissions divided 
by the heat input (or gross energy output) for all the RATA runs, 
expressed in units of lb/MMBtu or lb/MWh, does not exceed the emissions 
standard.

Sec.  60.4415  How do I conduct performance tests to demonstrate 
compliance with my SO2 emissions standard?

    (a) An owner or operator of an affected facility complying with the 
fuel based standard must submit fuel records (such as a current, valid 
purchase contract, tariff sheet, transportation contract, or results of 
a fuel analysis) to satisfy the requirements of Sec.  60.8.
    (b) An owner or operator of an affected facility complying with the 
SO2 emissions standard must conduct the performance test by 
measuring the SO2 emissions in the stationary combustion 
turbine exhaust gases using the methods in either paragraph (b)(1) or 
(2) of this section.
    (1) Measure the SO2 concentration using EPA Methods 6, 
6C, 8 in appendix A-4 of this part, or EPA Method 20 in appendix A-7 of 
this part. In addition, the American Society of Mechanical Engineers 
(ASME) standard, ASME PTC 19-10-1981-Part 10, ``Flue and Exhaust Gas 
Analyses,'' manual methods for sulfur dioxide (incorporated by 
reference, see Sec.  60.17) can be used instead of EPA Method 6 in 
appendix A-4 of this part or EPA Method 20 in appendix A-7 of this 
part. For units complying with the output based standard, concurrently 
measure the stack gas flow rate, using EPA Methods 1 and 2 in appendix 
A-1 of this part, and measure and record the electrical and thermal 
output from the unit. Then use Equation 20 of this subpart to calculate 
the SO2 emissions rate:
[GRAPHIC] [TIFF OMITTED] TP29AU12.023

Where:

E = SO2 emissions rate, in lb/MWh,
1.664 x 10-7 = Conversion constant, in lb/dscf-ppm,
(SO2)c = Average SO2 concentration 
for the run, in ppm,
Qstd = Average stack gas volumetric flow rate, in dscf/h, 
and
P = Average gross electrical and mechanical energy output of the 
stationary combustion turbine, in MW (for simple-cycle operation), 
for combined-cycle operation, the sum of all electrical and 
mechanical output from the combustion and steam turbines, or, for 
CHP operation, the sum of all electrical and mechanical output from 
the combustion and steam turbines plus all useful recovered thermal 
output not used for additional electric or mechanical generation or 
to enhance the performance of the stationary combustion turbine, in 
MW, calculated according to Sec.  60.4350(f)(2).

    (2) Measure the SO2 and diluent gas concentrations, 
using either EPA Methods 6, 6C, or 8 in appendix A-4 of this part and 
EPA Method 3A in appendix A-2 of this part, or EPA Method 20 in 
appendix A-7 of this part. In addition, you may use the manual methods 
for sulfur dioxide ASME PTC 19-10-1981-Part 10 (incorporated by 
reference, see Sec.  60.17). Concurrently measure the heat input to the 
unit, using a fuel flowmeter (or flowmeters), an O2 or 
CO2 CEMS along with a stack flow meter, or the methodologies 
in appendix F to part 75 of this chapter, and for units complying with 
the output based standard measure the electrical and thermal output of 
the unit. Use EPA Method 19 in appendix A-7 of this part to calculate 
the SO2 emissions rate in lb/MMBtu. Then, use Equations 11 
and, if necessary, 12 and 13 of this subpart in Sec.  60.4372 to 
calculate the SO2 emissions rate in lb/MWh.

Definitions

Sec.  60.4420  What definitions apply to this subpart?

    As used in this subpart, all terms not defined herein will have the 
meaning given them in the Clean Air Act and in subpart A (General 
Provisions) of this part.
    Affirmative defense means, in the context of an enforcement 
proceeding, a response or defense put forward by a defendant, regarding 
which the defendant has the burden of proof, and the merits of which 
are independently and objectively evaluated in a judicial or 
administrative proceeding.
    Base load rating means 100 percent of the manufacturer's design 
heat input capacity of the combustion turbine engine at ISO conditions 
using the higher heating value of the fuel.
    Biogas means gas produced by the anaerobic digestion or 
fermentation of organic matter including manure, sewage sludge, 
municipal solid waste, biodegradable waste, or any other biodegradable 
feedstock, under anaerobic conditions. Biogas is comprised primarily of 
methane and CO2.
    Byproduct means any liquid or gaseous substance produced at 
chemical manufacturing plants, petroleum refineries, or pulp and paper 
mills (except natural gas and fuel oil) and combusted in a stationary 
combustion

[[Page 52579]]

turbine. Gaseous substances with CO2 levels greater than 50 
percent or carbon monoxide levels greater than 10 percent are not 
byproduct.
    Combined cycle combustion turbine means any stationary combustion 
turbine which recovers heat from the combustion turbine engine exhaust 
gases to generate steam that is used exclusively to create additional 
power output in a steam turbine.
    Combined heat and power (CHP) combustion turbine means any 
stationary combustion turbine which recovers heat from the combustion 
turbine engine exhaust gases to heat water or another medium, generate 
steam for useful purposes other than exclusively for additional 
electric generation, or directly uses the heat in the exhaust gases for 
a useful purpose.
    Combustion turbine engine means the air compressor, combustor, and 
turbine sections of a stationary combustion turbine.
    Combustion turbine test cell/stand means any apparatus used for 
testing uninstalled stationary or uninstalled mobile (motive) 
combustion turbines.
    Distillate oil means fuel oil that complies with the specifications 
for fuel oil numbers 1 or 2, as defined by the American Society for 
Testing and Materials in ASTM D396 (incorporated by reference, see 
Sec.  60.17), diesel fuel oil numbers 1 or 2, as defined by the 
American Society for Testing and Materials in ASTM D975 (incorporated 
by reference, see Sec.  60.17), kerosine, as defined by the American 
Society of Testing and Materials in ASTM D3699 (incorporated by 
reference, see Sec.  60.17), biodiesel as defined by the American 
Society of Testing and Materials in ASTM D6751 (incorporated by 
reference, see Sec.  60.17), or biodiesel blends as defined by the 
American Society of Testing and Materials in ASTM D7467 (incorporated 
by reference, see Sec.  60.17).
    Dry standard cubic foot (dscf) means the quantity of gas, free of 
uncombined water, that would occupy a volume of 1 cubic foot at 293 
Kelvin (20.0 [deg]C) and 101.325 kPa of pressure.
    Duct burner means a device that combusts fuel and that is placed in 
the exhaust duct from another source, such as a stationary combustion 
turbine, internal combustion engine, kiln, etc., to allow the firing of 
additional fuel to heat the exhaust gases.
    Emergency combustion turbine means any stationary combustion 
turbine which operates in an emergency situation. Examples include 
stationary combustion turbines used to produce power for critical 
networks or equipment, including power supplied to portions of a 
facility, when electric power from the local utility is interrupted, or 
stationary combustion turbines used to pump water in the case of fire 
or flood, etc. Emergency stationary combustion turbines do not include 
stationary combustion turbines used as peaking units at electric 
utilities or stationary combustion turbines at industrial facilities 
that typically operate at low capacity factors. Emergency combustion 
turbines may be operated for maintenance checks and readiness testing 
to retain their status as emergency combustion turbines, provided that 
the tests are required by the manufacturer, the vendor, or the 
insurance company associated with the turbine. Required testing of such 
units should be minimized, but there is no time limit on the use of 
emergency combustion turbines.
    Excess emissions means a specified averaging period over which 
either (1) the NOX or SO2 emissions rate are 
higher than the applicable emissions standard in Sec.  60.4320 or Sec.  
60.4330; (2) the total sulfur content of the fuel being combusted in 
the affected facility or the SO2 emissions exceeds the 
standard specified in Sec.  60.4330; or (3) the recorded value of a 
particular monitored parameter, including ration of water or steam to 
fuel, is outside the acceptable range specified in the parameter 
monitoring plan for the affected unit.
    Federally enforceable means all limitations and conditions that are 
enforceable by the Administrator or delegated authority, including the 
requirements of 40 CFR parts 60 and 61, requirements within any 
applicable State Implementation Plan, and any permit requirements 
established under 40 CFR 52.21 or under 40 CFR 51.18 and 51.24.
    Fuel oil means a fluid mixture of hydrocarbons that maintains a 
liquid state at ISO conditions. Additionally, fuel oil must meet the 
definition of either distillate oil or residual oil as defined by the 
American Society for Testing and Materials in ASTM D396 (incorporated 
by reference, see Sec.  60.17) or diesel fuel as defined by the 
American Society for Testing and Materials in ASTM D975 (incorporated 
by reference, see Sec.  60.17).
    Gross useful energy output means:
    (1) For simple cycle and combined cycle combustion turbines, the 
gross useful work performed is the gross electrical or direct 
mechanical output from both the combustion turbine engine and any 
associated steam turbine(s).
    (2) For a CHP combustion turbine, the gross useful work performed 
is the gross electrical or direct mechanical output from both the 
combustion turbine engine and any associated steam turbine(s) plus any 
useful thermal output measured relative to ISO conditions that is not 
used to generate additional electrical or mechanical output or to 
enhance the performance of the unit (i.e., steam delivered to an 
industrial process).
    (3) For a 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, the gross 
useful work performed is the gross electrical or direct mechanical 
output from both the combustion turbine engine and any associated steam 
turbine(s) divided by 0.95 plus any useful thermal output measured 
relative to ISO conditions that is not used to generate additional 
electrical or mechanical output or to enhance the performance of the 
unit (i.e., steam delivered to an industrial process).
    Heat recovery steam generating unit (HRSG) means a unit where the 
hot exhaust gases from the combustion turbine engine are routed in 
order to extract heat from the gases and generate useful output. Heat 
recovery steam generating units can be used with or without duct 
burners.
    Integrated gasification combined cycle electric utility steam 
generating unit (IGCC) means an electric utility steam generating unit 
that burns solid-derived fuels in a combined-cycle combustion turbine. 
No solid fuel is directly combusted in the unit during operation.
    ISO conditions means 288 Kelvin (15 [deg]C), 60 percent relative 
humidity and 101.325 kilopascals (kPa) pressure.
    Lean premix stationary combustion turbine means any stationary 
combustion turbine where the air and fuel are thoroughly mixed to form 
a lean mixture before delivery to the combustor. Mixing may occur 
before or in the combustion chamber. A lean premixed turbine may 
operate in diffusion flame mode during operating conditions such as 
startup and shutdown, extreme ambient temperature, or low or transient 
load.
    Low-Btu gas means biogas or any gas with a heating value of less 
than 26 megajoules per standard cubic meter (MJ/scm) (700 Btu/scf).
    Natural gas means a fluid mixture of hydrocarbons, composed of at 
least 70 percent methane by volume or that has a gross calorific value 
between 35 and 41 MJ/scm (950 and 1,100 Btu/scf), that maintains a 
gaseous state under ISO conditions. In addition, natural gas

[[Page 52580]]

contains 460 mg/scm (20.0 gr/100 scf) or less of total sulfur. Finally, 
natural gas does not include any gaseous fuel produced in a process 
which might result in highly variable heating value.
    Noncontinental area means Guam, American Samoa, the Northern 
Mariana Islands, or offshore platforms.
    Offshore turbine means a stationary combustion turbine located on a 
platform in an ocean.
    Operating day means a 24-hour period between 12 midnight and the 
following midnight during which any fuel is combusted at any time in 
the unit. It is not necessary for fuel to be combusted continuously for 
the entire 24-hour period.
    Operating hour means a clock hour during which any fuel is 
combusted in the affected unit. If the unit combusts fuel for the 
entire clock hour, it is considered to be a full operating hour. If the 
unit combusts fuel for only part of the clock hour, it is considered to 
be a partial operating hour.
    Out-of-control period means any period beginning with the quadrant 
corresponding to the completion of a daily calibration error, linearity 
check, or quality assurance audit that indicates that the instrument is 
not measuring and recording within the applicable performance 
specifications and ending with the quadrant corresponding to the 
completion of an additional calibration error, linearity check, or 
quality assurance audit following corrective action that demonstrates 
that the instrument is measuring and recording within the applicable 
performance specifications.
    Simple cycle combustion turbine means any stationary combustion 
turbine which does not recover heat from the combustion turbine engine 
exhaust gases for purposes other than enhancing the performance of the 
stationary combustion turbine itself.
    Solid fuel means any fuel that has a definite shape and volume, has 
no tendency to flow or disperse under moderate stress, and is not 
liquid or gaseous at ISO conditions. This includes, but is not limited 
to, coal, biomass, and pulverized solid fuels.
    Stationary combustion turbine means all equipment, including but 
not limited to the combustion turbine engine, the fuel, air, 
lubrication and exhaust gas systems, control systems, heat recovery 
system, steam turbine, fuel compressor, heater, and/or pump, post-
combustion emission control technology, and any ancillary components 
and sub-components. Stationary means that the combustion turbine is not 
self propelled or intended to be propelled while performing its 
function. It may, however, be mounted on a vehicle for portability.
    Standard cubic foot (scf) means the quantity of gas that would 
occupy a volume of 1 cubic foot at 293 Kelvin (20.0 [deg]C) and 101.325 
kPa of pressure.
    Standard cubic meter (scm) means the quantity of gas that would 
occupy a volume of 1 cubic meter at 293 Kelvin (20.0 [deg]C) and 
101.325 kPa of pressure.
    Turbine tuning means planned maintenance of a lean premix 
combustion turbine engine involving adjustment of the operating 
configuration to maintain proper combustion dynamics. Turbine tuning is 
limited to 30 hours annually.
    Useful thermal output means the thermal energy made available for 
processes and applications other than electrical or mechanical 
generation or to enhance the performance of the stationary combustion 
turbine (i.e., the thermal energy made available for use in any 
industrial or commercial process or used in any heating application). 
Useful thermal output for this subpart is measured relative to the 
enthalpy of the thermal output in its most prevalent form at ISO 
conditions (e.g., liquid water).

    Table 1 to Subpart KKKK of Part 60--Nitrogen Oxide Emission Standards for Stationary Combustion Turbines
                               [All numerical values have two significant figures]
----------------------------------------------------------------------------------------------------------------
                                                                                                   Alternate NOX
                                         Combustion turbine heat                                     emissions
        Combustion turbine type         input at base load rating      NOX emissions standard       standard in
                                                  (HHV)                                              ppm at 15
                                                                                                    percent O2
----------------------------------------------------------------------------------------------------------------
New turbine firing natural gas,         <= 15 MW (50 MMBtu/h)....  67 ng/J (0.16 lb/MMBtu) heat               42
 electric generating.                                               input or 290 ng/J of gross
                                                                    energy output (2.3 lb/MWh).
New turbine firing natural gas,         <= 15 MW (50 MMBtu/h)....  160 ng/J (0.37 lb/MMBtu) heat             100
 mechanical drive.                                                  input or 690 ng/J of gross
                                                                    energy output (5.5 lb/MWh).
New turbine firing natural gas........  > 15 MW (50 MMBtu/h) and   40 ng/J (0.093 lb/MMBtu) heat              25
                                         <= 250 MW (850 MMBtu/h).   input or 150 ng/J of gross
                                                                    energy output (1.2 lb/MWh).
New, modified, or reconstructed         > 250 MW (850 MMBtuh)....  24 ng/J (0.056 lb/MMBtu) heat              15
 turbine firing natural gas.                                        input or 54 ng/J of gross
                                                                    energy output (0.43 lb/MWh).
New turbine firing fuels other than     <= 15 MW (50 MMBtu/h)....  160 ng/J (0.38 lb/MMBtu) heat              96
 natural gas, electric generating.                                  input or 710 ng/J of gross
                                                                    energy output (5.6 lb/MWh).
New turbine firing fuels other than     <= 15 MW (50 MMBtu/h)....  250 ng/J (0.59 lb/MMBtu) heat             150
 natural gas, mechanical drive.                                     input or 1,100 ng/J of gross
                                                                    energy output (8.7 lb/MWh).
New turbine firing fuels other than     > 15 MW (50 MMBtu/h) and   120 ng/J (0.29 lb/MMBtu) heat              74
 natural gas.                            <= 250 MW (850 MMBtu/h).   input or 470 ng/J of gross
                                                                    energy output (3.7 lb/MWh).
New, modified, or reconstructed         > 250 MW (850 MMBtu/h)...  73 ng/J (0.17 lb/MMBtu) heat               42
 turbine firing fuels other than                                    input or 160 ng/J of gross
 natural gas.                                                       energy output (1.3 lb/MWh).
Modified or reconstructed turbine.....  <= 15 MW (50 MMBtu/h)....  250 ng/J (0.59 lb/MMBtu) heat             150
                                                                    input or 1,100 ng/J of gross
                                                                    energy output (8.7 lb/MWh).
Modified or reconstructed turbine       > 15 MW (50 MMBtu/h) and   67 ng/J (0.16 lb/MMBtu) heat               42
 firing natural gas.                     <= 250 MW (850 MMBtu/h).   input or 250 ng/J of gross
                                                                    energy output (2.0 lb/MWh).
Modified or reconstructed turbine       > 15 MW (50 MMBtu/h) and   160 ng/J (0.38 lb/MMBtu) heat              96
 firing fuels other than natural gas.    <= 250 MW (850 MMBtu/h).   input or 600 ng/J of gross
                                                                    energy output (4.8 lb/MWh).

[[Page 52581]]

 
Turbines located north of the Arctic    <= 100 MW (340 MMBtu/h)..  250 ng/J (0.59 lb/MMBtu) heat             150
 Circle (latitude 66.5 degrees north),                              input or 1,100 ng/J of gross
 turbines operating at less than 75                                 energy output (8.7 lb/MWh).
 percent of the base load rating,
 turbines operated during periods of
 turbine tuning, startup, or shutdown,
 modified and reconstructed offshore
 turbines, or turbines operating at
 temperatures less than minus 17
 [deg]C.
Turbines located north of the Arctic    > 100 MW (340 MMBtu/h)...  160 ng/J (0.38 lb/MMBtu) heat              96
 Circle (latitude 66.5 degrees north),                              input or 610 ng/J of gross
 turbines operating at less than 75                                 energy output (4.8 lb/MWh).
 percent of the base load rating,
 turbines operated during periods of
 turbine tuning, startup, or shutdown,
 modified and reconstructed offshore
 turbines, or turbines operating at
 temperatures less than minus 17
 [deg]C.
Heat recovery units operating           All sizes................  86 ng/J (0.20 lb/MMBtu) heat               50
 independent of the combustion turbine                              input or 110 ng/J of gross
 engine.                                                            energy output (0.90 lb/MWh).
----------------------------------------------------------------------------------------------------------------

[FR Doc. 2012-20524 Filed 8-28-12; 8:45 am]
BILLING CODE 6560-50-P