[Federal Register: July 6, 2006 (Volume 71, Number 129)]
[Rules and Regulations]
[Page 38481-38506]
[DOCID:fr06jy06-14]

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Part III

Environmental Protection Agency

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40 CFR Part 60

Standards of Performance for Stationary Combustion Turbines; Final Rule

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ENVIRONMENTAL PROTECTION AGENCY

40 CFR Part 60

[EPA-HQ-OAR-2004-0490, FRL-8033-4]
RIN 2060-AM79

Standards of Performance for Stationary Combustion Turbines

AGENCY: Environmental Protection Agency (EPA).

ACTION: Final rule.

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SUMMARY: This action promulgates standards of performance for new
stationary combustion turbines in 40 CFR part 60, subpart KKKK. The
standards reflect changes in nitrogen oxides (NOX) emission
control technologies and turbine design since standards for these units
were originally promulgated in 40 CFR part 60, subpart GG. The
NOX and sulfur dioxide (SO2) standards have been
established at a level which brings the emissions limits up to date
with the performance of current combustion turbines.

DATES: Effective date:The final rule is effective July 6, 2006. The
incorporation by reference of certain publications in the final rule is
approved by the Director of the Office of the Federal Register as of
July 6, 2006.

ADDRESSES: Docket: EPA has established a docket for this action under
Docket ID No. EPA-HQ-OAR-2004-0490. All documents in the docket are
listed electronically on http://www.regulations.gov. 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, is not placed on the Internet
and will be publicly available only in hard copy form. Publicly
available docket materials are available either electronically through
http://www.regulations.gov or in hard copy at the Air and Radiation Docket,

Docket ID No. EPA-HQ-OAR-2004-0490, EPA/DC, EPA West, Room B102, 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
Center is<PHONE_NUMBER>.

FOR FURTHER INFORMATION CONTACT: Mr. Christian Fellner, Combustion
Group, Emission Standards Division (C439-01), U.S. EPA, Research
Triangle Park, North Carolina 27711; telephone number<PHONE_NUMBER>;
facsimile number<PHONE_NUMBER>; e-mail address
<EMAIL_ADDRESS>

SUPPLEMENTARY INFORMATION:
    Regulated Entities. Categories and entities potentially regulated
by this action are those that own and operate stationary combustion
turbines with a heat input at peak load equal to or greater than 10.7
gigajoules (GJ) (10 million British thermal units (MMBtu)) per hour
that commenced construction, modification, or reconstruction after
February 18, 2005. Regulated categories and entities include, but are
not limited to:

----------------------------------------------------------------------------------------------------------------
            Category                NAICS       SIC                  Examples of regulated entities
----------------------------------------------------------------------------------------------------------------
Any industry using a new               2211       4911  Electric services.
 stationary combustion turbine
 as defined in the final rule
                                     486210       4922  Natural gas transmission.
                                     211111       1311  Crude petroleum and natural gas.
                                     211112       1321  Natural gas liquids.
                                        221       4931  Electric and other services, combined.
----------------------------------------------------------------------------------------------------------------

    Worldwide Web (WWW). In addition to being available in the docket,
an electronic copy of the final rule is available on the WWW through
the Technology Transfer Network Website (TTN Web). Following signature,
EPA will post a copy of the final rule on the TTN's 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.
    Judicial Review. Under section 307(b)(1) of the Clean Air Act
(CAA), judicial review of the final rule is available only by filing a
petition for review in the U.S. Court of Appeals for the District of
Columbia by September 5, 2006. Under section 307(d)(7)(B) of the CAA,
only an objection to the final rule that was raised with reasonable
specificity during the period for public comment can be raised during
judicial review. Moreover, under section 307(b)(2) of the CAA, the
requirements established by today's final action may not be challenged
separately in any civil or criminal proceedings brought by EPA to
enforce these requirements.
    Section 307(d)(7)(B) of the CAA further provides that ``only an
objection to a rule or procedure which was raised with reasonable
specificity during the period for public comment (including any public
hearing) may be raised during judicial review.'' This section also
provides a mechanism for EPA to convene a proceeding for
reconsideration, ``if the person raising an objection can demonstrate
to EPA that it was impracticable to raise such objection within [the
period for public comment] or if the grounds for such objection arose
after the period for public comment (but within the time specified for
judicial review) and if such objection is of central relevance to the
outcome of the rule.'' Any person seeking to make such a demonstration
to EPA should submit a Petition for Reconsideration to the Office of
the Administrator, U.S. EPA, Room 3000, Ariel Rios Building, 1200
Pennsylvania Ave., NW., Washington, DC 20460, with a copy to both the
person(s) listed in the FOR FURTHER INFORMATION CONTACT section, and
the Director of the Air and Radiation Law Office, Office of General
Counsel (Mail Code 2344A), U.S. EPA, 1200 Pennsylvania Ave., NW.,
Washington, DC 20004.
    Organization of This Document. The following outline is provided to
aid in locating information in this preamble.

I. Background
II. Summary of the Final Rule
    A. Does the final rule apply to me?
    B. What pollutants are regulated?
    C. What is the affected source?
    D. What emission limits must I meet?
    E. If I modify or reconstruct my existing turbine, does the
final rule apply to me?
    F. How do I demonstrate compliance?
    G. What monitoring requirements must I meet?
    H. What reports must I submit?
III. Summary of Significant Changes Since Proposal
    A. Applicability
    B. Emission Limitations
    C. Testing and Monitoring Procedures
    D. Reporting
    E. Other
IV. Summary of Responses to Major Comments
    A. Applicability
    B. NOX Emission Standards
    C. Definitions

V. Environmental and Economic Impacts
    A. What are the air impacts?
    B. What are the energy impacts?
    C. What are the economic impacts?
VI. Statutory and Executive Order Reviews
    A. Executive Order 12866: Regulatory Planning and Review
    B. Paperwork Reduction Act
    C. Regulatory Flexibility Act
    D. Unfunded Mandates Reform Act
    E. Executive Order 13132: Federalism
    F. Executive Order 13175: Consultation and Coordination with
Indian Tribal Governments
    G. Executive Order 13045: Protection of Children from
Environmental Health and Safety Risks
    H. Executive Order 13211: Actions that Significantly Affect
Energy Supply, Distribution, or Use
    I. National Technology Transfer and Advancement Act
    J. Congressional Review Act

I. Background

    This action promulgates new source performance standards (NSPS)
that apply to stationary combustion turbines with a heat input at peak
load equal to or greater than 10.7 GJ (10 MMBtu) per hour, based on the
higher heating value (HHV) of the fuel, that commence construction,
modification, or reconstruction after February 18, 2005. The NSPS are
being promulgated pursuant to section 111 of the CAA, which requires
EPA to promulgate and periodically revise the NSPS, taking into
consideration available control technologies and the costs of control.
EPA promulgated the original NSPS for stationary gas turbines in 1979
(44 FR 52798). Since promulgation of the NSPS for stationary gas
turbines, many advances in the design and control of emissions from
stationary combustion turbines have occurred. Nitrogen oxides and
SO2 are known to cause adverse health and environmental
effects. The final rule represents reductions in the NOX and
SO2 limits of over 80 and 90 percent, respectively. Today's
action allows turbine owners and operators to meet either
concentration-based or output-based standards. The output-based
standards in the final rule allow owners and operators the flexibility
to meet their emission limit targets by increasing the efficiency of
their turbines.

II. Summary of the Final Rule

A. Does the final rule apply to me?

    Today's final rule applies to stationary combustion turbines with a
heat input at peak load equal to or greater than 10.7 GJ (10 MMBtu) per
hour that commence construction, modification, or reconstruction after
February 18, 2005. A stationary combustion turbine is defined as all
equipment, including but not limited to the combustion turbine, the
fuel, air, lubrication and exhaust gas systems, control systems (except
emissions control equipment), heat recovery system, and any ancillary
components and sub-components comprising any simple cycle stationary
combustion turbine, any regenerative/recuperative cycle stationary
combustion turbine, any combined cycle combustion turbine, and any
combined heat and power combustion turbine based system. 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. The applicability of the final rule is
similar to that of 40 CFR part 60, subpart GG, except that the final
rule applies to new, modified, and reconstructed stationary combustion
turbines, and their associated heat recovery steam generators (HRSG)
and duct burners. The stationary combustion turbines subject to subpart
KKKK, 40 CFR part 60, are exempt from the requirements of 40 CFR part
60, subpart GG. Heat recovery steam generators and duct burners subject
to subpart KKKK are exempt from the requirements of 40 CFR part 60,
subparts Da, Db, and Dc.

B. What pollutants are regulated?

    The pollutants that are regulated by the final rule are
NOX and SO2.

C. What is the affected source?

    The affected source for the stationary combustion turbine NSPS is
each stationary combustion turbine with a heat input at peak load equal
to or greater than 10.7 GJ (10 MMBtu) per hour that commences
construction, modification, or reconstruction after February 18, 2005.
Integrated gasification combined cycle (IGCC) combustion turbine
facilities covered by subpart Da of 40 CFR part 60 (the Utility Boiler
NSPS) are exempt from the requirements of the final rule. Combustion
turbine test cells/stands are also exempt from the requirements of the
final rule.

D. What emission limits must I meet?

    The standards for NOX in the final rule allow the
turbine owner or operator the choice of a concentration-based or
output-based emission standard. The concentration-based limit is in
units of parts per million by volume (ppmv) at 15 percent oxygen. The
output-based emission limit is in units of emissions mass per unit
useful recovered energy, nanograms per Joule (ng/J) or pounds per
megawatt-hour (lb/MWh). The NOX limits, which are presented
in table 1 of this preamble, differ based on the fuel input at peak
load, fuel, application, and location of the turbine. The fuel input of
the turbine does not include any supplemental fuel input to the heat
recovery system and refers to the rating of the combustion turbine
itself. The 50 MMBtu/h category peak heat input is based on the fuel
input to a 23 percent efficient 3.5 megawatt (MW) combustion turbine.
The 850 MMBtu/h category peak heat input is based on the fuel input to
a 44 percent efficient 110 MW combustion turbine. The 30 MW category
for turbines located north of the Arctic Circle, turbines operating at
less than 75 percent of peak load, modified and reconstructed offshore
turbines, and turbines operating at temperatures less than 0[deg]F is
based on the categories in the original NSPS for combustion turbines,
subpart GG.

                    Table 1.--NOX Emission Standards
------------------------------------------------------------------------
                               Combustion turbine
   Combustion turbine type     heat input at peak       NOX emission
                                   load (HHV)             standard
------------------------------------------------------------------------
New turbine firing natural    < = 50 million         42 ppm at 15 percent
 gas, electric generating.     British thermal       oxygen (O2) or 290
                               units per             ng/J of useful
                               hour(MMBtu/h).        output (2.3 lb/
                                                     MWh).
New turbine firing natural    < = 50 MMBtu/h.......  100 ppm at 15
 gas, mechanical drive.                              percent O2 or 690
                                                     ng/J of useful
                                                     output (5.5 lb/
                                                     MWh).
New turbine firing natural    > 50 MMBtu/h and      25 ppm at 15 percent
 gas.                          < =850 MMBtu/h.        O2 or 150 ng/J of
                                                     useful output (1.2
                                                     lb/MWh).
New, modified, or             > 850 MMBtu/h.......  15 ppm at 15 percent
 reconstructed turbine                               O2 or 54 ng/J of
 firing natural gas.                                 useful output (0.43
                                                     lb/MWh).
New turbine firing fuels      < = 50 MMBtu/h.......  96 ppm at 15 percent
 other than natural gas,                             O2 or 700 ng/J of
 electric generating.                                useful output (5.5
                                                     lb/MWh).

New turbine firing fuels      < = 50 MMBtu/h.......  150 ppm at 15
 other than natural gas,                             percent O2 or 1,100
 mechanical drive.                                   ng/J of useful
                                                     output (8.7 lb/
                                                     MWh).
New turbine firing fuels      > 50 MMBtu/h and <=   74 ppm at 15 percent
 other than natural gas.       850 MMBtu/h.          O2 or 460 ng/J of
                                                     useful output (3.6
                                                     lb/MWh).
New, modified, or             > 850 MMBtu/h.......  42 ppm at 15 percent
 reconstructed turbine                               O2 or 160 ng/J of
 firing fuels other than                             useful output (1.3
 natural gas.                                        lb/MWh).
Modified or reconstructed     < = 50 MMBtu/h.......  150 ppm at 15
 turbine.                                            percent O2 or 1,100
                                                     ng/J of useful
                                                     output (8.7 lb/
                                                     MWh).
Modified or reconstructed     > 50 MMBtu/h and <=   42 ppm at 15 percent
 turbine firing natural gas.   850 MMBtu/h.          O2 or 250 ng/J of
                                                     useful output (2.0
                                                     lb/MWh).
Modified or reconstructed     > 50 MMBtu/h and <=   96 ppm at 15 percent
 turbine firing fuels other    850 MMBtu/h.          O2 or 590 ng/J of
 than natural gas.                                   useful output (4.7
                                                     lb/MWh).
Turbines located north of     < = 30 megawatt (MW)   150 ppm at 15
 the Arctic Circle (latitude   output.               percent O2 or 1,100
 66.5 degrees north),                                ng/J of useful
 turbines operating at less                          output (8.7 lb/
 than 75 percent of peak                             MWh).
 load, modified and
 reconstructed offshore
 turbines, and turbines
 operating at temperatures
 less than 0 [deg]F.
Turbines located north of     > 30 MW output......  96 ppm at 15 percent
 the Arctic Circle (latitude                         O2 or 590 ng/J of
 66.5 degrees north),                                useful output (4.7
 turbines operating at less                          lb/MWh).
 than 75 percent of peak
 load, modified and
 reconstructed offshore
 turbines, and turbines
 operating at temperatures
 less than 0 [deg]F.
Heat recovery units           All sizes...........  54 ppm at 15 percent
 operating independent of                            O2 or 110 ng/J of
 the combustion turbine.                             useful output (0.86
                                                     lb/MWh).
------------------------------------------------------------------------

    We have determined that it is appropriate to exempt emergency
combustion turbines from the NOX limit. We have defined
these units as turbines that operate in emergency situations. For
example, turbines used to supply electric power when the local utility
service is interrupted are considered to fall under this definition.
Stationary combustion turbine test cells/stands are also exempt from
the final rule. Combustion turbines used by manufacturers in research
and development of equipment for both combustion turbine emissions
control techniques and combustion turbine efficiency improvements are
exempt from the NOX limits on a case-by-case basis. Given
the small number of turbines that are expected to fall under this
category and since there is not one definition that can provide an all-
inclusive description of the type of research and development work that
qualifies for the exemption from the NOX limit, we have
decided that it is appropriate to make these exemption determinations
on a case-by-case basis only.
    The emission standard for SO2 is the same for all
turbines regardless of size and fuel type. You may not cause to be
discharged into the atmosphere from the subject stationary combustion
turbine any gases which contain SO2 in excess of 110 ng/J
(0.90 lb/MWh) gross energy output for turbines that are located in
continental areas, and 780 ng/J (6.2 lb/MWh) gross energy output for
turbines located in noncontinental areas. You can choose to comply with
the SO2 limit itself or with a limit on the sulfur content
of the fuel. The fuel sulfur content limit is 26 ng SO2/J
(0.060 lb SO2/MMBtu) heat input for turbines located in
continental areas and 180 ng SO2/J (0.42 lb SO2/
MMBtu) heat input in noncontinental areas. This is approximately
equivalent to 0.05 percent by weight (500 parts per million by weight
(ppmw)) fuel oil and 0.4 percent by weight (4,000 ppmw) fuel oil
respectively.

E. If I modify or reconstruct my existing turbine, does the final rule
apply to me?

    The final rule applies to stationary combustion turbines that are
modified or reconstructed after February 18, 2005. The methods for
determining whether a source is modified or reconstructed are provided
in 40 CFR 60.14 and 40 CFR 60.15, respectively. A turbine that is
overhauled as part of a maintenance program is not considered a
modification if there is no increase in emissions.

F. How do I demonstrate compliance?

    In order to demonstrate compliance with the NOX limit,
an initial performance test is required. If you are using water or
steam injection, you must continuously monitor your water or steam to
fuel ratio in order to demonstrate compliance and you are not required
to perform annual stack testing to demonstrate compliance. If you are
not using water or steam injection, you must conduct performance tests
annually following the initial performance test in order to demonstrate
compliance. Alternatively, you may choose to demonstrate continuous
compliance with the use of a continuous emission monitoring system
(CEMS) or parametric monitoring; if you choose this option, you are not
required to conduct subsequent annual performance tests.
    If you are using a NOX CEMS, the initial performance
test required under 40 CFR 60.8 may, alternatively, coincide with the
relative accuracy test audit (RATA). If you choose this as your initial
performance test, you must perform a minimum of nine reference method
runs, with a minimum time per run of 21 minutes, at a single load
level, within 75 percent of peak (or the highest achievable) load. You
must use the test data both to demonstrate compliance with the
applicable NOX emission limit and to provide the required
reference method data for the RATA of the CEMS.

G. What monitoring requirements must I meet?

    If you are using water or steam injection to control NOX
emissions, you must install and operate a continuous monitoring system
to monitor and record the fuel consumption and the ratio of water or
steam to fuel being

fired in the turbine. Alternatively, you could use a CEMS consisting of
NOX and O2 or carbon dioxide (CO2)
monitors. During each full unit operating hour, each monitor must
complete a minimum of one cycle of operation for each 15-minute
quadrant of the hour. For partial unit operating hours, at least one
valid data point must be obtained for each quadrant of the hour in
which the unit operates.
    If you operate any new turbine which does not use water or steam
injection to control NOX emissions, you must perform annual
stack testing to demonstrate continuous compliance with the
NOX limit. Alternatively, you could elect either to use a
NOX CEMS or perform continuous parameter monitoring as
follows:
    (1) For a diffusion flame turbine without add-on selective
catalytic reduction (SCR) controls, you must define appropriate
parameters indicative of the unit's NOX formation
characteristics, and you must monitor these parameters continuously;
    (2) For any lean premix stationary combustion turbine, you must
continuously monitor the appropriate parameters to determine whether
the unit is operating in the low NOX combustion mode;
    (3) For any turbine that uses SCR to reduce NOX
emissions, you must continuously monitor appropriate parameters to
verify the proper operation of the emission controls; and
    (4) For affected units that are also regulated under part 75 of
this chapter, with state approval you can monitor the NOX
emission rate using the methodology in appendix E to part 75 of this
chapter, or the low mass emissions methodology in 40 CFR 75.19, the
monitoring requirements of the turbine NSPS may be met by performing
the parametric monitoring described in section 2.3 of appendix E of
part 75 of this chapter or in 40 CFR 75.19(c)(1)(iv)(H).
    Alternatively, you can petition the Administrator for other
acceptable methods of monitoring your emissions. If you choose to use a
CEMS or perform parameter monitoring to demonstrate continuous
compliance, annual stack testing is not required.
    If you choose to monitor combustion parameters or parameters
indicative of proper operation of NOX emission controls, the
appropriate parameters must be continuously monitored and recorded
during each run of the initial performance test to establish acceptable
operating ranges.
    If you operate any stationary combustion turbine subject to the
provisions of the final rule, and you choose not to comply with the
SO2 stack limit, you must monitor the total sulfur content
of the fuel being fired in the turbine. There are several options for
determining the frequency of fuel sampling, consistent with appendix D
to part 75 of this chapter for fuel oil; the sulfur content must be
determined and recorded once per unit operating day for gaseous fuel,
unless a custom fuel sampling schedule is used. Alternatively, you
could elect not to monitor the total potential sulfur emissions of the
fuel combusted in the turbine, if you demonstrate that the fuel does
not exceed 26 ng SO2/J (0.060 lb SO2/MMBtu) heat
input for turbines located in continental areas and 180 ng
SO2/J (0.42 lb SO2/MMBtu) heat input in
noncontinental areas. This demonstration may be performed by using the
fuel quality characteristics in a current, valid purchase contract,
tariff sheet, or transportation contract, or through representative
fuel sampling data which show that the potential sulfur emissions of
the fuel does not exceed the standard. Turbines located in continental
areas can demonstrate compliance by burning fuel oil containing 500
parts per million (ppm) or less sulfur or natural gas containing 20
grains or less of sulfur per 100 standard cubic feet. Turbines located
in noncontinental areas can demonstrate compliance by burning fuel oil
containing 0.4 weight percent (4,000 ppm) sulfur or less or natural gas
containing 140 grains or less of sulfur per 100 standard cubic feet.
    If you are required to periodically determine the sulfur content of
the fuel combusted in the turbine, a fuel sample must be collected
during the performance test. For liquid fuels, the sample for the total
sulfur content of the fuel must be analyzed using American Society of
Testing and Materials (ASTM) methods D129-00 (Reapproved 2005), D1266-
98 (Reapproved 2003), D1552-03, D2622-05, D4294-03, or D5453-05. For
gaseous fuels, ASTM D1072-90 (Reapproved 1999); D3246-05; D4468-85
(Reapproved 2000); or D6667-04 must be used to analyze the total sulfur
content of the fuel.
    The applicable ranges of some ASTM methods mentioned above are not
adequate to measure the levels of sulfur in some fuel gases. Dilution
of samples before analysis (with verification of the dilution ratio)
may be used, subject to the approval of the Administrator.

H. What reports must I submit?

    For each affected unit for which you continuously monitor
parameters or emissions, or periodically determine the fuel sulfur
content under the final rule, you must submit reports of excess
emissions and monitor downtime, in accordance with 40 CFR 60.7(c). For
simple cycle turbines, excess emissions must be reported for all 4-hour
rolling average periods of unit operation, including start-up,
shutdown, and malfunctions where emissions exceed the allowable
emission limit or where one or more of the monitored process or control
parameters exceeds the acceptable range as determined in the monitoring
plan. Combined cycle and combined heat and power units use a 30-day
rolling average to determine excess emissions.
    For each affected unit for which you perform an annual performance
test, you must submit an annual written report of the results of each
performance test.

III. Summary of Significant Changes Since Proposal

A. Applicability

    The proposed rule applied to owners and operators of stationary
combustion turbines with a peak power output at peak load equal to or
greater than 1 MW. The final rule applies to stationary combustion
turbines with a heat input at peak load equal to or greater than 10.7
GJ (10 MMBtu) per hour, based on the HHV of the fuel. Assuming an
efficiency of 23 percent, the final rule applies to stationary
combustion turbines with a peak output greater than 0.7 MW. Another
change from the proposed rule is the addition of an exemption for
stationary combustion turbine test cells/stands.

B. Emission Limitations

    The proposed rule established four subcategories of turbines based
on fuel type and turbine size, and different NOX emission
standards were proposed for each subcategory. The proposed
subcategories were the following: Less than 30 MW and firing natural
gas; greater than or equal to 30 MW and firing natural gas; less than
30 MW and firing oil or other fuel; and greater than or equal to 30 MW
and firing oil or other fuel. The final rule has 14 subcategories,
which are listed in table 1 of this preamble. Instead of the proposed
size break at 30 MW, the final rule breaks the turbines into
subcategories of less than or equal to 50 MMBtu/h of heat input,
greater than 50 MMBtu/h heat input to less than or equal to 850 MMBtu/h
heat input, and greater than 850 MMBtu/h heat input. Subcategories have
been included for modified and reconstructed turbines, heat recovery
units operating independent of the combustion turbine, turbines located
north of the Arctic

Circle, and turbines operating at part load. EPA concluded that
subcategories based on heat input at peak load rather than power output
are more appropriate. The boiler NSPS standards are subcategorized by
heat input, and heat input is a better indication than power output of
available combustion controls. Basing categories on heat input also
eliminates the disincentive of turbine redesign that increases
efficiency and output, but not fuel consumption.
    The proposed standards for NOX were output-based limits
in units of emissions mass per unit useful recovered energy, ng/J or
lb/MWh. This format has been retained in the final rule; however, an
optional concentration-based standard in units of ppmv at 15 percent
O2 has also been included for each subcategory.
    The proposed SO2 emission limits were raised slightly in
the final rule, and an additional subcategory was created. Different
emission limits were provided for turbines located in noncontinental
areas; those turbines have an SO2 emission limit of 780 ng/J
(6.2 lb/MWh). The other difference from the proposed rule is that
turbines located in Alaska do not have to meet the SO2
emission limits until January 1, 2008.

C. Testing and Monitoring Procedures

    The final rule contains several differences from the proposed
testing and monitoring procedures. The performance test for
NOX is not required to be conducted at four load levels; in
the final rule the test must be conducted at one load level that is
within plus or minus 25 percent of 100 percent of peak load. Testing
may be performed at the highest achievable load point, if at least 75
percent of peak load cannot be achieved in practice. We added a
requirement that the ambient temperature be greater than 0 [deg]F when
the test is conducted. Similarly, we specified in the final rule that
turbine owners and operators that are continuously monitoring
parameters or emissions have an alternate limit during periods when the
turbine operates at less than 75 percent of peak load or the ambient
temperature is less than 0 [deg]F.
    A provision was added that allows owners and operators of
stationary combustion turbines to reduce the frequency of subsequent
NOX performance tests to once every 2 years if the
NOX emission result from the performance test is less than
or equal to 75 percent of the NOX emission limit for the
turbine. If the results of any subsequent performance test exceed 75
percent of the NOX emission limit for the turbine, annual
performance tests must be resumed.
    The sulfur sampling requirements in the final rule also contain
some differences from the proposed requirements. Acceptable custom
schedules for determining the total sulfur content of gaseous fuels
were added in the final rule. We removed the statement that was in the
proposed rule that required at least one fuel sample to be collected
during each load condition, since we are no longer requiring
performance tests to be conducted at multiple loads.
    Finally, the proposed rule required that diffusion flame turbines
without SCR controls continuously monitor at least four parameters
indicative of the unit's NOX formation characteristics; the
final rule does not specify a minimum number of parameters that must be
continuously monitored by these units.

D. Reporting

    The reporting requirements in the final rule contain two
differences from the proposed reporting requirements. The proposed 40
CFR 60.4395 said that reports should be postmarked by the 30th day
following the end of each calendar quarter. The proposed rule actually
required semiannual reports, therefore, that section should have read
that the reports should be postmarked by the end of each 6-month
period, and the final rule has been written to correct this error.
Also, we specified that turbines that are conducting annual performance
testing should submit annual reports with the results of the
performance testing.

E. Other

    Several modifications were made to the definitions in the proposed
rule. The definition of efficiency was clarified to indicate that it is
based on the HHV of the fuel. The definitions for lean premix
stationary combustion turbine and diffusion flame stationary combustion
turbine were modified to alleviate any potential ambiguity about which
definition a turbine would fall under. Lastly, the definition of
natural gas was revised to remove references to pipeline natural gas.

IV. Summary of Responses to Major Comments

    A more detailed summary of comments and our responses can be found
in the Response to Public Comments on Proposed Standards of Performance
for Stationary Combustion Turbines document, which can be obtained from
the docket.

A. Applicability

    Comment: Several commenters suggested changing the minimum size
threshold for applicability of the rule, as proposed. Some suggested 3
MW, while others suggested 3.5 MW. Reasons included the fact that lean
premix technology is not available for turbines less than 3 MW, other
control options are not feasible, no commercially available small units
were identified that can achieve the proposed emission levels, and no
emission test data were provided in the docket for small units.
    Another reason given was that there was some ambiguity because of
the differing minimum size criteria between the rule, as proposed, and
40 CFR part 60, subpart GG. Two commenters suggested that EPA clarify
that subpart KKKK, 40 CFR part 60, is the effective NSPS, and that 40
CFR part 60, subpart GG, no longer applies for all new, reconstructed,
or modified stationary combustion turbines. The commenters said that it
is not clear if 40 CFR part 60, subpart GG, will no longer apply after
the effective date of the final rule. Since the minimum size criterion
was slightly different in the two subparts, the commenters requested
clarification of this issue to avoid future confusion. The commenters
requested that EPA clarify that 40 CFR part 60, subpart GG, no longer
applies after the effective date of the final rule.
    Response: This comment addresses the minimum size threshold for the
final rule. In 40 CFR 60.4305 of the rule, as proposed, the
applicability criteria stated that the applicable units are turbines
with a peak load power output equal to or greater than 1 MW. This
minimum size threshold is marginally higher than the minimum threshold
in 40 CFR part 60, subpart GG, which affects turbines with a minimum
heat input at peak load of 10.7 GJ per hour or larger based on the
lower heating value of the fuel (approximately 10 MMBtu/h). With a
lower heating value (LHV) thermal efficiency of 23 to 25 percent, which
is typical at full load for older small industrial turbines, this
firing rate is equivalent to 0.7 MW. While the difference between the
40 CFR part 60, subpart GG, and the proposed 40 CFR part 60, subpart
KKKK, applicability thresholds was initially believed to be minor, the
natural gas industry representatives pointed out that there is a class
of turbines used in natural gas transmission that fall within this
range. Solar Saturn units, which are widely used in the gas
transmission industry, include a peak load between 0.7 and 1.0 MW.
While the industry has said that

not many new units are sold in this range, there are many already in
existence, which may be modified or reconstructed, which would need to
be addressed by one of the rules. Therefore, the final rule has been
written to include the minimum size applicability threshold of 10.7 GJ
per hour.
    While we do not agree that the size cutoff should be established to
exempt turbines less than 3.5 MW, EPA has concluded that it is
appropriate to create a new subcategory. Discussions with turbine
manufacturers suggest that a subcategory for small turbines, between
the minimum size threshold for the final rule and 50 MMBtu/h (HHV),
should be created. This division is based on the fuel input to a 23
percent efficient 3.5 MW turbine. The only turbine identifiable in this
size range that can be used for mechanical drive applications is a
Solar Saturn, and Solar Turbines does not plan to further develop dry
low NOX technology on the Saturn line, nor does it have that
capability at the current time. According to the gas transmission
industry representatives, there are about 300 turbines in this small
size range, comprising over 25 percent of the existing turbines in gas
transmission. None of these units include lean premixed combustion.
Other add-on controls have not been applied to the variable load
operating profile characteristic of gas transmission equipment, nor
would such add-on controls be economically feasible for these small
units with minimal emissions. Therefore, the final rule has
incorporated a new subcategory of small turbines, ranging from the
applicability limit to 50 MMBtu/h.
    Comment: Several commenters suggested that modified and
reconstructed units should be treated differently than new units.
Reasons provided by the commenters included costs for retrofitting
being excessive, and weight and space needs being prohibitive. One
commenter stated that there are many existing turbines that could be
affected by the modification section of the rule for which there is no
cost effective technology that achieves emissions lower than those
suggested by the commenter. One commenter stated that the terms
``modification'' and ``reconstruction'' were not clearly defined, and
that requiring these units to meet the same limits as new units may
discourage existing turbine users from modifying units to improve
efficiency or lower emissions, if such modifications do not ensure
compliance with the limit for new units.
    Options recommended by the commenters included removing them from
the applicability of 40 CFR part 60, subpart KKKK, giving them separate
limits under subpart KKKK, or making them subject to 40 CFR part 60,
subpart GG. One commenter recommended that units manufactured through
1985 (20 years and older) be exempted from the requirements of the
proposed NSPS, and the previous NSPS levels should apply.
    Response: We acknowledge the commenters' views, and in the final
rule there are new subcategories for some modified and reconstructed
units. While we provided more flexibility in the final rule for small
and medium sized turbines (ranging from the applicability threshold to
850 MMBtu/h), we had no information on large turbines (greater than 850
MMBtu/h) which would suggest any compliance issues for modified or
reconstructed units. Therefore, no subcategory was added for large
(greater than 850 MMBtu/h) modified or reconstructed units.
    Comment: Several commenters suggested that EPA include an exemption
for offshore turbines, turbines located north of the Arctic Circle, and
turbines in other existing remote locations. Alternatively, the
commenters suggested subcategorizing them separately. The commenters
said that due to a harsh environment and fuel availability and
variability, these turbines are commonly diffusion flame, and land-
based emissions abatement techniques are unsuitable; space limitations
are also a concern. One commenter said that the rule, as proposed,
would preclude the use of new, modified or reconstructed turbines
located in electric utility service in Alaska, because of the
additional costs associated with meeting the proposed limits.
    Response: EPA has concluded that a subcategory should be created
for modified and reconstructed offshore turbines and turbines installed
north of the Arctic Circle to recognize their distinct differences.
There is a substantial difference in temperature between the North
Slope of Alaska and even the coldest areas in the lower 48 States. As
noted by the commenters, turbine operators on the North Slope of Alaska
have experienced problems with operation of the turbines in lean premix
mode, and turbine manufacturers do not guarantee the performance of
their turbines at the ambient temperatures typically found north of the
Arctic Circle. Therefore, a subcategory for turbines operated north of
the Arctic Circle has been established.
    With regards to the rest of Alaska, EPA concluded that the final
rule includes limits which will reduce or eliminate the need for add-on
controls for the vast majority of turbines, and that these new emission
limitations address the concerns of the commenters.
    Modified and reconstructed offshore turbines have been given a
subcategory due to the lack of space on platforms for additional
controls.
    The subcategories for these turbines are based on power output
instead of heat input at peak load. Since the standards for these
subcategories are similar to 40 CFR part 60, subpart GG, EPA used the
same categories as subpart GG to avoid being less stringent than the
existing emissions standards.
    Comment: Several commenters had issues with periods of startup,
shutdown and malfunction. Some commenters believed that the averaging
times that are specified for continuous monitoring (using either a CEMS
or parametric monitoring) were too short to accommodate such periods.
The commenters believed that exceptions should be developed for periods
of startup, shutdown and maintenance if 4-hour averages were
maintained. One commenter suggested 30-day rolling averages, one
commenter suggested 24-hour rolling averages, and one commenter
suggested 12-month rolling averages.
    One commenter wanted clarification of the applicability of the
NOX standards during periods of startup, shutdown and
malfunction. Two commenters pointed out that while these periods of
excess emissions were not considered violations, they might appear to
be to State regulatory agencies or the public. Another commenter
requested that EPA allow sources to permit emissions associated with
startup and shutdown events where it is not feasible to have the same
emission profile as normal operating conditions. This commenter
requested that a clarification be made that deviating from a monitored
parameter only results in excess emissions if emissions calculated from
that parameter result in exceeding an emission limit for the averaging
period used to demonstrate compliance.
    One commenter was particularly concerned about combined cycle units
with longer startup periods as part of a normal startup cycle. The
commenter felt that this should not constitute a malfunction, and
should not be reported in an excess emissions report. Another commenter
asked that a reasonable startup period (up to 24 hours) be provided for
units with SCR, since minimum temperatures must be met.
    Response: The final rule states that excess emissions and
deviations must be recorded during periods of startup, shutdown, and
malfunction. We recognize that even for well-operated

units with efficient NOX emission controls, excess emission
``spikes'' during unit startup and shutdown are inevitable, and
malfunctions of emission controls and process equipment occasionally
occur. However, at all times, including periods of startup, shutdown,
and malfunction, 40 CFR 60.11(d) requires affected units to be operated
in a manner consistent with good air pollution control practice for
minimizing emissions. Excess emissions data may be used to determine
whether a facility's operation and maintenance procedures are
consistent with 40 CFR 60.11(d). While continuous compliance is not
required, excess emissions during startup, shutdown, and malfunction
must be reported. Thus, we retained the 4-hour rolling average period
in the final rule for simple cycle units. We realize that including
units with heat recovery under the combustion turbine NSPS adds
additional compliance issues for those units. Boiler NOX
emissions vary over short time periods and short averaging times make
the output-based options unworkable due to the difficulty in
continuously taking full advantage of the recovered thermal energy. For
units with heat recovery and CEMS, the standard is therefore determined
on a 30-day rolling average. Under the previous NSPS, heat recovery
units are covered under either subpart Da, Db, or Dc, 40 CFR part 60.
Those standards determine compliance based on a 30-day rolling average.
In recognition of these factors, EPA concluded that a 30-day rolling
average is the appropriate averaging time for units that are using
recovered thermal energy. Since simple cycle turbines are used
primarily for peaking applications, a 30-day average is not practical
for these units. Initial compliance determinations could take several
years, and once a unit is determined to be out of compliance it could
take several years for the 30-day average to return below the standard.
    In regards to parametric monitoring, a deviation from a monitored
parameter only results in excess emissions if the calculations show an
exceedence of the emission limit. This is clearly communicated in the
final rule, in the section entitled ``How do I establish and document a
proper parameter monitoring plan?'' Regarding the negative stigma, we
cannot determine how other parties interpret the final rule. It is
clear that continuous compliance is not a requirement of the final rule
during periods of startup, shutdown, and malfunction.

B. NOX Emission Standards

    Comment: Numerous commenters recommended that there be some type of
concentration-based standards for NOX. One commenter said
that while it applauds EPA's proposed shift to output-based standards,
they might not be applicable in all situations. The commenter said that
it is unclear how the calculation would work for a turbine with a
bypass stack or another situation where heat is wasted. In addition,
the commenter believed that an increased level of effort for monitoring
parameters is required, which creates financial and technical burdens
for compliance. The commenter recommended that EPA provide an optional
concentration-based standard that can be used where data for
calculating an output-based standard are unavailable or inappropriate.
    One commenter recommended a ppmv standard consistent with current
regulations, or a separate standard for simple cycle and combined cycle
units. The commenter cited some of the following as rationale for its
suggestion: Many State implementation plan regulations and best
available control technology analyses are in ppmv, and 40 CFR part 60,
subpart GG, is in ppmv; efficiency varies over load; carbon monoxide
(CO) needs to be balanced; there are a limited number of units able to
meet output-based limits without SCR; and output-based standards add
complexity and computational and measurement uncertainty. Another
commenter recommended that EPA allow optional concentration-based
standards (i.e., ppmv corrected to 15 percent oxygen) so that if a
source does not need energy efficiency adjustments to show compliance,
it could choose to measure only emission concentrations at the stack.
    Two commenters said that EPA should replace the output-based
NOX emission limit with a concentration-based standard for
turbines less than 30 MW, which are primarily mechanical drive units.
Similarly, several commenters said that EPA should provide optional
concentration-based standards for all non-utility (mechanical drive)
turbines; another solution would be to revise the monitoring approach
to reduce cost and burden. The commenters' rationale was that
mechanical drive units do not always include instruments that allow
heat balance calculation of power output, and are frequently running at
partial loads.
    According to the commenters, a concentration-based limit would
eliminate the need for variables that are difficult to accurately and
readily obtain. Alternatively, these commenters felt that modifications
should be made to include provisions in equation 4 of 40 CFR
60.4350(f)(3) for waste heat recovery when it is installed.
    One commenter believed that limits should be specified on a
concentration basis rather than on an output basis because some data
show that lower concentrations can be attained at lower loads, yet, due
to decreased efficiencies at lower loads, these emissions would exceed
limitations on an output basis.
    One commenter recommended a NOX standard in ppm rather
than an output-based standard for alternative fuels. The commenter said
that in many cases, there is no demand for steam or thermal energy at
or near landfills, so combined heat and power projects are unwarranted.
    Response: We have considered the commenters' concerns, and have
included an alternative concentration-based limit in the final rule for
all turbines. Some units have difficulty with determining their power
output, and adding a concentration-based emission limit significantly
simplifies the regulation.
    Comment: Several commenters said that turbines operating at partial
load might not be able to meet the output-based limit. The commenters
said that there are times when combustion turbines will run at partial
load conditions, for example when a facility has not yet geared up to
full production or when power is available from the grid at a lower
cost than can be produced by the nonutility. According to the
commenters, the turbine efficiency is lower at partial load operation,
which leads to higher output-based emissions. Three commenters made the
point that many combustion turbines shift out of lean premix mode into
diffusion flame mode at lower loads, leading to increased
NOX emissions.
    One commenter requested that the NOX limits for partial
loads be increased to account for lower thermal efficiencies at partial
loads. One commenter suggested that part load operation for both gas
and distillate oil revert to limits set on the basis of corrected
NOX concentrations (parts per million by volume dry (ppmvd)
at 15 percent O2). The commenter said that this coincides
with operating schedules for existing General Electric dry low
NOX turbines, which are tuned to yield constant
NOX ppm throughout the operating load range. The commenter
believed that this limit basis is also advantageous from the standpoint
of compliance monitoring, since NOX concentration can be
measured directly on site when equipped with CEMS. Several

commenters said that the NOX emission standards should only
apply at full load, and performance testing should be conducted at 90
to 100 percent of peak load or the highest load point achievable in
practice. The commenters said that if EPA does not make this change,
EPA should provide data and analysis supporting the applicability of
the NOX standard at partial load outside of the typical
range for manufacturer guarantees.
    One commenter said that the requirement in 40 CFR 60.4400(b) of the
proposed rule to perform four tests between 70 and 100 percent load
seems excessive. The commenter requested that this section also clarify
that the four load points should be based upon the ambient conditions
and fuel characteristics realized during the time of testing, since
ambient temperature can affect the maximum or minimum operating load
during a given test program. The commenter noted that operating at
greater than 100 percent of peak load may also be possible, especially
during cold (much less than 59 [deg]F) ambient conditions.
    Response: We indicated in the final rule that the NOX
performance testing should be conducted at full load operation, which
is defined as plus or minus 25 percent of 100 percent of peak load, or
the highest load physically achievable in practice. Only one load point
is required for testing for the annual performance test. For continuous
monitoring, an alternate limit has been established when the turbine is
not operating at full load. Conducting the annual test at full load is
consistent with the Stationary Combustion Turbines NESHAP, 40 CFR part
63, subpart YYYY.
    Comment: Several commenters requested that EPA specify that the
emission standards only apply for ambient temperatures ranging from 0
to 100 [deg]F. Alternatively, the commenters asked EPA to provide data
and analysis supporting the applicability of the NOX
standard at ambient temperatures outside of the typical range for
manufacturer guarantees. Two commenters said that NOX is
higher at lower ambient temperatures, efficiencies are compromised at
lower ambient temperatures, and cold intake air causes flame stability
issues. The commenters also noted that EPA data in Alaska does not
cover the winter operating season. The commenter provided some plots of
emissions data for operations at low temperatures.
    Response: EPA concluded that turbines do not operate optimally at
ambient temperatures below 0 [deg]F. Therefore, compliance
demonstrations, such as annual testing, are required at ambient
temperatures greater than 0 [deg]F in the final rule. If you are using
a CEMS for demonstrating compliance, alternate emissions standards
apply when the ambient temperature is below 0 [deg]F. We recognize that
these temperatures may increase emissions from the turbine.
    Comment: A number of commenters had concerns with the efficiencies
that EPA used to determine the values for the output-based emission
standards. One commenter stated that if EPA retained an output-based
NOX standard for units less than 30 MW, EPA should revise
the efficiency basis for the standard, which is not supported by the
docket material for industrial scale units. Three commenters said that
the proposed NOX emission standards needed to be revised to
reflect the full range of turbine efficiencies that may be encountered
during operation. Three commenters said that during the first 5 years
of operation, the maximum load that can be achieved can decrease by as
much as 5 percent while the thermal efficiency can decrease by as much
as 2.5 percent.
    One commenter said that 30 percent efficiency is not consistently
achieved for small simple cycle turbines. The commenter recommended
using 23 percent efficiency (LHV) at full load for turbines less than
3.5 MW, and 25 percent efficiency (LHV) at full load for the 3.5-30 MW
turbines, to ensure that smaller turbines can achieve the NSPS at site
conditions, which provide variability in efficiency.
    Four commenters observed that the efficiencies on which the
proposed output-based emissions were based only apply at full loads.
One commenter said that the Gas Turbine World specifications show more
than half of all models less than 30 MW have efficiencies lower than 30
percent. The commenter also said that lower loads have lower
efficiencies, also many combined cycle units have efficiencies less
than what EPA assumes. Another commenter asserted that EPA's standard
is based on stack tests, conducted at steady state, so efficiency
losses associated with changing load are not captured. In addition, the
commenter believed that these efficiencies are only for ``out of the
box'' turbines.
    Two commenters said that EPA determined the 30 percent value based
on turbine efficiency data in Gas Turbine World, which is based on LHV,
but the commenters believed that EPA may have applied it
inappropriately, as if it were HHV. If EPA had intended to base the
efficiency assumption on HHV, it appears that the limit for turbines
less than 30 MW was rounded down from 1.046 to 1.0 lb/MWh, according to
the commenters. But if EPA intended to base the efficiency assumption
on LHV, then the commenters determined that the limit should be 1.147
lb/MWh. The commenters said that even if EPA had intended the HHV
efficiency, the rounding difference is almost 5 percent for the smaller
turbine category, and this could be significant for turbines just
meeting the 25 ppmv vendor guarantee.
    Response: We developed alternative concentration-based standards,
so that efficiency is no longer an issue if this alternative is chosen.
In the final rule, we used a baseline efficiency of 23 percent for
small turbines, 27 percent for medium turbines, and 44 percent for
large turbines. The small turbine efficiency is based on the 40 CFR
part 60, subpart GG, lowest efficiency, 25 percent based on LHV. The
medium turbine efficiency is based on the top 90 percent of the medium
turbine efficiencies listed in the 2005 Global Sourcing Guide for Gas
Turbine Engines (http://www.dieselpub.com/gsg). The large turbine

efficiency is based on the top 90 percent of the combined cycle
efficiencies listed in the 2005 Global Sourcing Guide for Gas Turbine
Engines. EPA concluded that these efficiencies are appropriate for
turbines that elect to comply with the output-based standard.
    Comment: Several commenters strongly opposed the NOX
emission limits established in the rule, as proposed. They contended
that EPA's basis for establishing the limits was fundamentally flawed
and not representative of current combustion turbines without the use
of add-on controls. The commenters said that the proposed limits have
no support in the docket's actual test data, and are the product of
generalizations and faulty assumptions about the data, and must be
withdrawn until they can be properly based on the data they cite.
    According to the commenters, over 35 percent of the reported
emission rates from natural gas-fired units and nearly all of those
from fuel oil-fired units exceed the proposed output-based limits.
Other concerns with the data expressed by the commenters included: Some
power ranges are insufficiently represented because there are no data
between 80 and 150 MW and there are few data over 160 MW;
aeroderivative turbines are underrepresented; there were no useable
emission rate data for several manufacturers; and EPA did not consider
variability in load and may not have had adequate data for low
temperatures. Another commenter believed that EPA did not heed the
recommendations of the Gas Turbine

Association in their November 11, 2004, memorandum. In addition, this
commenter believed that EPA did not match the population percentages to
the data they reviewed. For example, the commenter said that almost 68
percent of the recent turbine orders are in the small category, yet
only 21 percent of the data reviewed by EPA were in this subcategory.
Additionally, the commenter said that for this subcategory, the maximum
NOX emission concentration listed is 27.8 ppm, which is
above the level of 25 ppm used in proposing the standard for the small
subcategory.
    Many of the commenters provided suggested NOX emission
standards to EPA.
    Response: While not all turbine models were represented in the data
set, we concluded that it is representative of today's population of
turbines. In addition, we obtained more data during the comment period,
including emissions information for turbines less than 50 MMBtu/h.
Also, our analysis included the addition of manufacturer guarantees and
permit information, which, along with emissions data, gave us a clear
picture of the achievability of the standards. The emission limits in
the final rule have been revised, as appropriate, using these
additional data and information. See table 1 of this preamble for the
revised emission standards.
    Comment: One commenter believed that there is a significant
difference between aeroderivative turbines and frame type turbines in
that aeroderivatives cannot employ low NOX burners and must
use water injection. While aeroderivatives may be guaranteed by the
manufacturer to achieve 25 ppm at full load, the commenter believed
that setting a standard at that level affords no cushion for operation
below full load, especially in light of the short averaging times.
Therefore, the commenter requested that EPA either raise the emission
limit to allow for operational flexibility, or set different standards
for different types of combustion turbines.
    Response: We concluded that the majority of turbines are in some
manner related to jet engine designs. The combustion turbine industry
began in the aviation industry, and we concluded that it is not
appropriate to subcategorize turbines based on design characteristics.
The primary difference is the degree to which the turbines have been
optimized for stationary applications. Furthermore, EPA concluded that
there is no appropriate definition that separates aeroderivative and
frame turbines.
    In the final rule we increased the upper limit on the medium
turbine category to 850 MMBtu/h. The medium turbine category covers the
majority of turbines that the comments addressed. This category is
based on the heat input to a 44 percent efficient 110 MW turbine. The
standards in the final rule address the commenter's concerns.
    Comment: Four commenters suggested emission limits for small
turbines. One commenter recommended a fuel neutral standard of 150 ppmv
for turbines less than 3 MW. Another commenter recommended a
NOX standard of 100 ppmv for natural gas-fired turbines less
than 3 MW, and 150 ppmv for distillate oil-fired turbines less than 3
MW. One commenter said that if EPA retains turbines less than 3.5 MW in
40 CFR part 60, subpart KKKK, the NOX emission limit for new
construction should be 100 ppmv for natural gas and 175 ppmv for
distillate oil; for modified or reconstructed turbines, the
NOX emission limit should be 150 ppmv for natural gas and
200 ppmv for distillate oil. The commenter recommended a concentration
limit for mechanical drive turbines and an output-based limit based on
an efficiency of 23 percent for power generators. Another commenter
stated that if EPA retains turbines less than 3.5 MW in 40 CFR part 60,
subpart KKKK, the NOX emission limit for turbines between 1
and 3.5 MW should be no more stringent than 6 lb/MWh for natural gas,
distillate oil and other fuels. The commenter's rationale was that this
level is comparable to 40 CFR part 60, subpart GG, and significant
improvements in control technologies have not been made since subpart
GG was established.
    Response: Based on the comments received, we revised the emission
limitations in the final rule for small turbines, as shown in table 1
of this preamble. We received additional data from the turbine
manufacturer for small turbines. Based on these data, we concluded that
the majority of small turbines will be able to comply with the revised
emission limitations given in the final rule. These numbers were based
on data received from small turbine manufacturers during the public
comment period.
    Comment: Six commenters believed that the NOX standards
for turbines less than 30 MW were not consistently achievable in
practice. Two of the commenters said that the standard for natural gas
turbines 3 to 30 MW should be 42 ppmv. One commenter said that the
standard for natural gas turbines 3.5 to 30 MW should be 42 ppmv for
mechanical drive units, and based on 42 ppmv with an efficiency of 25
percent for power generation units. For distillate oil turbines 3.5 to
30 MW, the commenter said that the NOX standard should be 96
ppmv for mechanical drive units, and based on 96 ppmv with an
efficiency of 25 percent for power generation units. One commenter
recommended a standard of 100 ppmv for oil-fired turbines. Three
commenters suggested that EPA provide an option to pursue an
alternative emission limit for retrofit applications that do not offer
a 42 ppmv NOX guarantee.
    One commenter said that for turbines under 30 MW, a NOX
standard of 1.0 lb/MWh will be too stringent for some projects,
particularly the smaller (less than 3.5 MW) facilities. The commenter
believed that this will prevent the implementation of some projects
that could provide lower emissions than the generation sources they are
displacing. The commenter suggested that the limit should be no more
stringent than 1.4 lb/MWh (25 ppm at 25 percent efficiency, LHV) for
natural gas-fired turbines.
    One commenter did not believe that any turbines less than 30 MW
could meet the proposed emission limits. The commenter said that
peaking turbines would not be able to meet the emission limits because
they must operate at variable loads and also low temperatures increase
NOX emissions. The commenter believed that even at full load
and 60 [deg]F ambient temperature, a dry low NOX turbine
would just barely make the NOX limit. Therefore, the
commenter suggested that EPA increase the limit in combination with
defining a limited range over which the limit is applicable. The
commenter also noted that SCR has only been installed in a handful of
simple cycle units and high temperature SCR is less reliable than
standard SCR.
    Response: We revised the emission limitations as well as the
subcategory for medium turbines, as presented in table 1 of this
preamble. The medium subcategory has been extended to cover additional
turbines. The new subcategory on which these comments are based is from
50 MMBtu/h to 850 MMBtu/h. We concluded that, based on data submitted
during the comment period, the new emission limitations in the final
rule are achievable by most turbines in this subcategory without the
use of add-on controls.
    Comment: Several commenters said that the proposed NOX
limits for oil-fired units were too low. One commenter said that EPA's
proposed output-based limits for oil-fired units cannot be achieved on
simple cycle turbines with combustion controls. The commenter felt that
the limit for oil-

fired turbines, 1.2 lb/MWh, is de facto too stringent, and imposing an
efficiency of 48 percent would be arbitrary and capricious. The
commenter requested that EPA separate simple cycle from combined cycle,
particularly for oil-fired units. One commenter requested that EPA
either raise the emission limit for oil-fired combustion turbines, or
at least allow large oil-fired peaking units to comply with the
emission limit for small oil-fired units. Many of the commenters
provided suggested emission levels for oil-fired units to EPA.
    Response: EPA concluded that, based on data submitted during the
comment period, the new emission limitations in the final rule for oil-
fired turbines are achievable by most turbines without the use of add-
on controls.

C. Definitions

    Comment: Four commenters requested that EPA clarify the definition
of efficiency. The commenters stated that the proposed definition is
based on the LHV, but that EPA usually defines regulations based on
HHV. The commenters believed that EPA may have intended to use HHV and
requested clarification on whether efficiency should be based on the
LHV or the HHV. One commenter stated that the LHV clause is unnecessary
and should be removed because most air permits are written, modeled and
reviewed upon the premise of the HHV of the fuel.
    Response: In the proposed rule, we inadvertently defined efficiency
in terms of LHV. Our intent was to use HHV. This change is reflected in
the final rule.

V. Environmental and Economic Impacts

A. What are the air impacts?

    We estimate that approximately 355 new stationary combustion
turbines will be installed in the United States over the next 5 years
and affected by the final rule. None of these units may need to install
add-on controls to meet the NOX limits required under the
final rule. However, many new turbines will already be required to
install add-on controls to meet NOX reduction requirements
under Prevention of Significant Deterioration (PSD) and New Source
Review (NSR). Thus, we concluded that the NOX reductions
resulting from the final rule will essentially be zero. The expected
SO2 reductions as a result of the final rule are approximately 830 tons
per year (tpy) in the 5th year after promulgation of the standards.
    Although we expect the final rule to result in a slight increase in
electrical supply generated by unaffected sources (e.g., existing
stationary combustion turbines), we concluded that this will not result
in higher NOX and SO2 emissions from these
sources. Other emission control programs such as the Acid Rain Program
and PSD/NSR already promote or require emission controls that would
effectively prevent emissions from increasing. All the emissions
reductions estimates and assumptions have been documented in the docket
to the final rule.

B. What are the energy impacts?

    We do not expect any significant energy impacts resulting from the
final rule. The only energy requirement is a potential small increase
in fuel consumption, resulting from back pressure caused by operating
an add-on emission control device, such as an SCR. However, most
entities would be able to comply with the final rule without the use of
any add-on control devices.

C. What are the economic impacts?

    EPA prepared an economic impact analysis to evaluate the impacts
the final rule would have on combustion turbines producers, consumers
of goods and services produced by combustion turbines, and society. The
analysis showed minimal changes in prices and output for products made
by the industries affected by the final rule. The price increase for
affected output is less than 0.003 percent, and the reduction in output
is less than 0.003 percent for each affected industry. Estimates of
impacts on fuel markets show price increases of less than 0.01 percent
for petroleum products and natural gas, and price increases of 0.04 and
0.06 percent for base-load and peak-load electricity, respectively. The
price of coal is expected to decline by about 0.002 percent, and that
is due to a small reduction in demand for this fuel type. Reductions in
output are expected to be less than 0.02 percent for each energy type,
including base-load and peak-load electricity.
    The social costs of the final rule are estimated at $0.4 million
(2002 dollars). Social costs include the compliance costs, but also
include those costs that reflect changes in the national economy due to
changes in consumer and producer behavior in response to the compliance
costs associated with a regulation. For the final rule, changes in
energy use among both consumers and producers to reduce the impact of
the regulatory requirements of the rule lead to the estimated social
costs being less than the total annualized compliance cost estimate of
$3.4 million (2002 dollars). The primary reason for the lower social
cost estimate is the increase in electricity supply generated by
unaffected sources (e.g., existing stationary combustion turbines),
which offsets mostly the impact of increased electricity prices to
consumers. The social cost estimates discussed above do not account for
any benefits from emission reductions associated with the final rule.
    For more information on these impacts, please refer to the economic
impact analysis in the public docket.

VI. Statutory and Executive Order Reviews

A. Executive Order 12866: Regulatory Planning and Review

    Under Executive Order 12866 (58 FR 51735, October 4, 1993), we must
determine whether a regulatory action is ``significant'' and,
therefore, subject to review by the Office of Management and Budget
(OMB) and the requirements of the Executive Order. The Executive Order
defines ``significant regulatory action'' as one that is likely to
result in a rule that may:
    (1) Have an annual effect on the economy of $100 million or more or
adversely affect in a material way the economy, a sector of the
economy, productivity, competition, jobs, the environment, public
health or safety, or State, local, or tribal governments or
communities;
    (2) Create a serious inconsistency or otherwise interfere with an
action taken or planned by another agency;
    (3) Materially alter the budgetary impact of entitlements, grants,
user fees, or loan programs, or the rights and obligation of recipients
thereof; or
    (4) Raise novel legal or policy issues arising out of legal
mandates, the President's priorities, or the principles set forth in
the Executive Order.
    Pursuant to the terms of Executive Order 12866, OMB has notified
EPA that it considers this a ``significant regulatory action'' within
the meaning of the Executive Order. EPA submitted this action to OMB
for review. Changes made in response to OMB suggestions or
recommendations will be documented in the public record.

B. Paperwork Reduction Act

    The information collection requirements in the final rule have been
submitted for approval to OMB under the Paperwork Reduction Act, 44
U.S.C. 3501 et seq. The Information Collection Request (ICR) document
prepared by EPA has been assigned ICR No. 2177.01.

    The final rule contains monitoring, reporting, and recordkeeping
requirements. The information would be used by EPA to identify any new,
modified, or reconstructed stationary combustion turbines subject to
the NSPS and to ensure that any new stationary combustion turbines
comply with the emission limits and other requirements. Records and
reports would be necessary to enable EPA or States to identify new
stationary combustion turbines that may not be in compliance with the
requirements. Based on reported information, EPA would decide which
units and what records or processes should be inspected.
    The final rule does not require any notifications or reports beyond
those required by the General Provisions. The recordkeeping
requirements require only the specific information needed to determine
compliance. These recordkeeping and reporting requirements are
specifically authorized by CAA section 114 (42 U.S.C. 7414). All
information submitted to EPA for which a claim of confidentiality is
made will be safeguarded according to EPA policies in 40 CFR part 2,
subpart B, Confidentiality of Business Information.
    The annual monitoring, reporting, and recordkeeping burden for this
collection (averaged over the first 3 years after July 6, 2006) is
estimated to be 20,542 labor hours per year at an average total annual
cost of $1,797,264. This estimate includes performance testing,
continuous monitoring, semiannual excess emission reports,
notifications, and recordkeeping. There are no capital/start-up costs
or operation and maintenance costs associated with the monitoring
requirements over the 3-year period of the ICR.
    Burden means the total time, effort, or financial resources
expended by persons to generate, maintain, retain, or disclose or
provide information to or for a Federal agency. This includes the time
needed to review instructions; develop, acquire, install, and utilize
technology and systems for the purposes of collecting, validating, and
verifying information, processing and maintaining information, and
disclosing and providing information; adjust the existing ways to
comply with any previously applicable instructions and requirements;
train personnel to be able to respond to a collection of information;
search data sources; complete and review the collection of information;
and transmit or otherwise disclose the information.
    An agency may not conduct or sponsor, and a person is not required
to respond to a collection of information unless it displays a
currently valid OMB control number. The OMB control numbers for EPA's
regulations in 40 CFR are listed in 40 CFR part 9 and 48 CFR chapter
15.

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 Procedures
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 today's final rule on
small entities, small entity is defined as: (1) A small business whose
parent company has fewer than 100 or 1,000 employees, depending on size
definition for the affected North American Industry Classification
System (NAICS) code, or fewer than 4 billion kilowatt-hours (kW-hr) per
year of electricity usage; (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. It
should be noted that small entities in one NAICS code would be affected
by the final rule, and the small business definition applied to each
industry by NAICS code is that listed in the Small Business
Administration size standards (13 CFR part 121).
    After considering the economic impacts of today's final rule on
small entities, we conclude that today's action will not have a
significant economic impact on a substantial number of small entities.
We determined, based on the existing combustion turbines inventory and
presuming the percentage of small entities in that inventory is
representative of the percentage of small entities owning new turbines
in the 5th year after promulgation, that one small entity out of 29 in
the industries impacted by the final rule will incur compliance costs
(in this case, only monitoring, recordkeeping, and reporting costs
since control costs are zero) associated with the final rule. This
small entity owns one affected turbine in the projected set of new
combustion turbines. This affected small entity is estimated to have
annual compliance costs of 0.3 percent of its revenues. The final rule
is likely to also increase profits for the small firms and increase
revenues for the many small communities (in total, 28 small entities)
using combustion turbines that are not affected by the final rule as a
result of the very slight increase in market prices. For more
information on the results of the analysis of small entity impacts,
please refer to the economic impact analysis in the docket.
    Although the final rule will not have a significant economic impact
on a substantial number of small entities, EPA nonetheless has tried to
reduce the impact of the final rule on small entities. In the final
rule, the Agency is applying the minimum level of control and the
minimum level of monitoring, recordkeeping, and reporting to affected
sources allowed by the CAA. In addition, as mentioned earlier in this
preamble, new turbines with heat inputs less than 10.7 GJ (10 MMBtu)
per hour are not subject to the final rule. This provision should
reduce the size of small entity impacts. We continue to be interested
in the potential impacts of the final rule on small entities and
welcome comments on issues related to such impacts.

D. Unfunded Mandates Reform Act

    Title II of the Unfunded Mandates Reform Act of 1995 (UMRA), Public
Law 104-4, establishes requirements for Federal agencies to assess the
effects of their regulatory actions on State, local, and tribal
governments and the private sector. Under section 202 of the UMRA, EPA
generally must prepare a written statement, including a cost-benefit
analysis, for proposed and final rules with ``Federal mandates'' that
may result in expenditures by State, local, and tribal governments, in
the aggregate, or by the private sector, of $100 million or more in any
1 year. Before promulgating an EPA rule for which a written statement
is needed, section 205 of the UMRA generally requires EPA to identify
and consider a reasonable number of regulatory alternatives and adopt
the least costly, most cost effective, or least burdensome alternative
that achieves the objective of the rule. The provisions of section 205
do not apply when they are inconsistent with applicable law. Moreover,
section 205 allows EPA to adopt an alternative other than the least
costly, most cost effective, or least burdensome alternative if the
Administrator publishes with the final rule an explanation why that
alternative was not adopted. Before EPA establishes any regulatory
requirements that may significantly or uniquely affect small
governments, including tribal governments, it must have developed

under section 203 of the UMRA a small government agency plan. The plan
must provide for notifying potentially affected small governments,
enabling officials of affected small governments to have meaningful and
timely input in the development of EPA regulatory proposals with
significant Federal intergovernmental mandates, and informing,
educating, and advising small governments on compliance with the
regulatory requirements.
    EPA has determined that the final rule contains no Federal mandates
that may result in expenditures of $100 million or more for State,
local, and tribal governments, in the aggregate, or the private sector
in any 1 year. Thus, the final rule is not subject to the requirements
of sections 202 and 205 of the UMRA. In addition, EPA has determined
that the final rule contains no regulatory requirements that might
significantly or uniquely affect small governments because they contain
no requirements that apply to such governments or impose obligations
upon them. Therefore, the final rule is not subject to the requirements
of section 203 of the UMRA.

E. Executive Order 13132: Federalism

    Executive Order 13132 (64 FR 43255, August 10, 1999) requires us to
develop an accountable process to ensure ``meaningful and timely input
by State and local officials in the development of regulatory policies
that have federalism implications.'' ``Policies that have federalism
implications'' are defined in the Executive Order to include
regulations that have ``substantial direct effects on the States, on
the relationship between the national government and the States, or on
the distribution of power and responsibilities among the various levels
of government.''
    The final rule does not have federalism implications. It will not
have substantial direct effects on the States, on the relationship
between the national government and the States, or on the distribution
of power and responsibilities among the various levels of government,
as specified in Executive Order 13132. Thus, Executive Order 13132 does
not apply to the final rule.

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

    Executive Order 13175 (65 FR 67249, November 6, 2000) requires EPA
to develop an accountable process to ensure ``meaningful and timely
input by tribal officials in the development of regulatory policies
that have tribal implications.'' ``Policies that have tribal
implications'' is defined in the Executive Order to include regulations
that have ``substantial direct effects on one or more Indian tribes, on
the relationship between the Federal government and the Indian tribes,
or on the distribution of power and responsibilities between the
Federal government and Indian tribes.''
    The final rule does not have tribal implications. It will not have
substantial direct effects on tribal governments, on the relationship
between the Federal government and Indian tribes, or on the
distribution of power and responsibilities between the Federal
government and Indian tribes, as specified in Executive Order 13175. We
do not know of any stationary combustion turbines owned or operated by
Indian tribal governments. However, if there are any, the effect of the
final rule on communities of tribal governments would not be unique or
disproportionate to the effect on other communities. Thus, Executive
Order 13175 does not apply to the final rule.

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

    Executive Order 13045 (62 FR 19885, April 23, 1997) applies to any
rule that: (1) Is determined to be ``economically significant'' as
defined under Executive Order 12866, and (2) concerns an environmental
health or safety risk that we have reason to believe may have a
disproportionate effect on children. If the regulatory action meets
both criteria, we must evaluate the environmental health or safety
effects of the planned rule on children, and explain why the planned
regulation is preferable to other potentially effective and reasonably
feasible alternatives.
    The final rule is not subject to Executive Order 13045 because it
is not an economically significant action as defined under Executive
Order 12866.

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

    Today's action is not a ``significant energy action'' as defined in
Executive Order 13211 because it is not likely to have a significant
adverse effect on the supply, distribution, or use of energy.
    An increase in petroleum product output, which includes increases
in fuel production, is estimated at less than 0.01 percent, or about
600 barrels per day based on 2004 U.S. fuel production nationwide. A
reduction in coal production is estimated at 0.00003 percent, or about
3,000 short tpy based on 2004 U.S. coal production nationwide. The
reduction in electricity output is estimated at 0.02 percent, or about
5 billion kW-hr per year based on 2000 U.S. electricity production
nationwide.
    Production of natural gas is expected to increase by 4 million
cubic feet per day. The maximum of all energy price increases, which
include increases in natural gas prices as well as those for petroleum
products, coal, and electricity, is estimated to be a 0.04 percent
increase in peak-load electricity rates nationwide. Energy distribution
costs may increase by no more than the same amount as electricity
rates. We expect that there will be no discernable impact on the import
of foreign energy supplies, and no other adverse outcomes are expected
to occur with regards to energy supplies.
    Also, the increase in the cost of energy production should be
minimal given the very small increase in fuel consumption resulting
from back pressure related to operation of add-on emission control
devices, such as SCR. All of the estimates presented above account for
some passthrough of costs to consumers as well as the direct cost
impact to producers.
    For more information on these estimated energy effects, please
refer to the economic impact analysis for the final rule. This analysis
is available in the public docket.

I. National Technology Transfer and Advancement Act

    Section 12(d) of the National Technology Transfer and Advancement
Act (NTTAA) of 1995 (Pub. L. 104-113; 15 U.S.C. 272 note) directs EPA
to use voluntary consensus standards in their regulatory and
procurement activities unless to do so would be inconsistent with
applicable law or otherwise impractical. Voluntary consensus standards
are technical standards (e.g., materials specifications, test methods,
sampling procedures, business practices) developed or adopted by one or
more voluntary consensus bodies. The NTTAA directs EPA to provide
Congress, through annual reports to OMB, with explanations when an
agency does not use available and applicable voluntary consensus
standards.
    The final rule involves technical standards. EPA cites the
following methods in the final rule: EPA Methods 1, 2, 3A, 6, 6C, 7E,
8, 19, and 20 of 40 CFR part 60, appendix A; and Performance
Specifications (PS) 2 of 40 CFR part 60, appendix B.
    In addition, the final rule cites the following standards that are
also incorporated by reference in 40 CFR part 60, section 17: ASTM
D129-00

(Reapproved 2005), ASTM D1072-90 (Reapproved 1999), ASTM D1266 98
(Reapproved 2003), ASTM D1552-03, ASTM D2622-05, ASTM D3246-05, ASTM
D4057-95 (Reapproved 2000), ASTM D4084-05, ASTM D4177-95 (Reapproved
2000), ASTM D4294-03, ASTM D4468-85 (Reapproved 2000), ASTM D4810-88
(Reapproved 1999), ASTM D5287-97 (Reapproved 2002), ASTM D5453-05, ASTM
D5504-01, ASTM D6228-98 (Reapproved 2003), ASTM D6667-04, and Gas
Processors Association Standard 2377-86.
    Consistent with the NTTAA, EPA conducted searches to identify
voluntary consensus standards in addition to these EPA methods/
performance specifications. No applicable voluntary consensus standards
were identified for EPA Methods 8 and 19. The search and review results
have been documented and are placed in the docket for the final rule.
    One voluntary consensus standard was identified as an acceptable
alternative for the EPA methods cited in this rule. The voluntary
consensus standard ASME PTC 19-10-1981--Part 10, ``Flue and Exhaust Gas
Analyses,'' is cited in this rule for its manual method for measuring
the sulfur dioxide content of exhaust gas. This part of ASME PTC 19-10-
1981--Part 10 is an acceptable alternative to EPA Methods 6 and 20
(sulfur dioxide only).
    In addition to the voluntary consensus standards EPA uses in the
final rule, the search for emissions measurement procedures identified
11 other voluntary consensus standards. EPA determined that nine of
these 11 standards identified for measuring air emissions or surrogates
subject to emission standards in the final rule were impractical
alternatives to EPA test methods/performance specifications for the
purposes of the final rule. Therefore, EPA does not intend to adopt
these standards. See the docket for the reasons for the determinations
of these methods.
    Two of the 11 voluntary consensus standards identified in this
search were not available at the time the review was conducted for the
purposes of the final rule because they are under development by a
voluntary consensus body. See the docket for the list of these methods.
    Sections 60.4345, 60.4360, 60.4400 and 60.4415 of the final rule
discuss EPA testing methods, performance specifications, and procedures
required. Under 40 CFR 63.7(f) and 40 CFR 63.8(f) of subpart A of the
General Provisions, a source may apply to EPA for permission to use
alternative test methods or alternative monitoring requirements in
place of any of EPA testing methods, performance specifications, or
procedures.

J. Congressional Review Act

    The Congressional Review Act, 5 U.S.C. section 801 et. seq., as
added by the Small Business Regulatory Enforcement Fairness Act of
1996, generally provides that before a rule may take effect, the agency
promulgating the rule must submit a rule report, which includes a copy
of the rule, to each House of the Congress and to the Comptroller
General of the United States. EPA will submit a report containing
today's final rule and other required information to the U.S. Senate,
the U.S. House of Representatives, and the Comptroller General of the
United States prior to publication of the rule in the Federal Register.
This action is not a ``major rule'' as defined by 5 U.S.C. 804(2). The
final rule will be effective on July 6, 2006.

List of Subjects in 40 CFR Part 60

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

    Dated: February 9, 2006.
Stephen L. Johnson,
Administrator.

    Editorial Note: This document was received by the Office of the
Federal Register on June 28, 2006.

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

PART 60--[AMENDED]

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

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

Subpart A--[Amended]

0
2. Section 60.17 is amended by revising paragraphs (a), (h)(4), and
(m)(1), and reserving paragraph (m)(2) to read as follows:

Sec.  60.17  Incorporation by reference.

* * * * *
    (a) The following materials are available for purchase from at
least one of the following addresses: American Society for Testing and
Materials (ASTM), 100 Barr Harbor Drive, Post Office Box C700, West
Conshohocken, PA 19428-2959; or ProQuest, 300 North Zeeb Road, Ann
Arbor, MI 48106.
    (1) ASTM A99-76, 82 (Reapproved 1987), Standard Specification for
Ferromanganese, incorporation by reference (IBR) approved for Sec.
60.261.
    (2) ASTM A100-69, 74, 93, Standard Specification for Ferrosilicon,
IBR approved for Sec.  60.261.
    (3) ASTM A101-73, 93, Standard Specification for Ferrochromium, IBR
approved for Sec.  60.261.
    (4) ASTM A482-76, 93, Standard Specification for
Ferrochromesilicon, IBR approved for Sec.  60.261.
    (5) ASTM A483-64, 74 (Reapproved 1988), Standard Specification for
Silicomanganese, IBR approved for Sec.  60.261.
    (6) ASTM A495-76, 94, Standard Specification for Calcium-Silicon
and Calcium Manganese-Silicon, IBR approved for Sec.  60.261.
    (7) ASTM D86-78, 82, 90, 93, 95, 96, Distillation of Petroleum
Products, IBR approved for Sec. Sec.  60.562-2(d), 60.593(d), and
60.633(h).
    (8) ASTM D129-64, 78, 95, 00, Standard Test Method for Sulfur in
Petroleum Products (General Bomb Method), IBR approved for Sec. Sec.
60.106(j)(2), 60.335(b)(10)(i), and Appendix A: Method 19, <IP_ADDRESS>.3.
    (9) ASTM D129-00 (Reapproved 2005), Standard Test Method for Sulfur
in Petroleum Products (General Bomb Method), IBR approved for Sec.
60.4415(a)(1)(i).
    (10) ASTM D240-76, 92, Standard Test Method for Heat of Combustion
of Liquid Hydrocarbon Fuels by Bomb Calorimeter, IBR approved for
Sec. Sec.  60.46(c), 60.296(b), and Appendix A: Method 19, Section
<IP_ADDRESS>.3.
    (11) ASTM D270-65, 75, Standard Method of Sampling Petroleum and
Petroleum Products, IBR approved for Appendix A: Method 19, Section
<IP_ADDRESS>.1.
    (12) ASTM D323-82, 94, Test Method for Vapor Pressure of Petroleum
Products (Reid Method), IBR approved for Sec. Sec.  60.111(l),
60.111a(g), 60.111b(g), and 60.116b(f)(2)(ii).
    (13) ASTM D388-77, 90, 91, 95, 98a, Standard Specification for
Classification of Coals by Rank, IBR approved for Sec. Sec.  60.41(f)
of subpart D of this part, 60.45(f)(4)(i), 60.45(f)(4)(ii),
60.45(f)(4)(vi), 60.41b of subpart Db of this part, 60.41c of subpart
Dc of this part, and 60.251(b) and (c) of subpart Y of this part.
    (14) ASTM D388-77, 90, 91, 95, 98a, 99 (Reapproved 2004)
[egr]1, Standard Specification for Classification of Coals
by Rank, IBR approved for Sec. Sec.  60.24(h)(8), 60.41Da of subpart Da
of this part, and 60.4102.
    (15) ASTM D396-78, 89, 90, 92, 96, 98, Standard Specification for
Fuel Oils,

IBR approved for Sec. Sec.  60.41b of subpart Db of this part, 60.41c
of subpart Dc of this part, 60.111(b) of subpart K of this part, and
60.111a(b) of subpart Ka of this part.
    (16) ASTM D975-78, 96, 98a, Standard Specification for Diesel Fuel
Oils, IBR approved for Sec. Sec.  60.111(b) of subpart K of this part
and 60.111a(b) of subpart Ka of this part.
    (17) ASTM D1072-80, 90 (Reapproved 1994), Standard Test Method for
Total Sulfur in Fuel Gases, IBR approved for Sec.  60.335(b)(10)(ii).
    (18) ASTM D1072-90 (Reapproved 1999), Standard Test Method for
Total Sulfur in Fuel Gases, IBR approved for Sec.  60.4415(a)(1)(ii).
    (19) ASTM D1137-53, 75, Standard Method for Analysis of Natural
Gases and Related Types of Gaseous Mixtures by the Mass Spectrometer,
IBR approved for Sec.  60.45(f)(5)(i).
    (20) ASTM D1193-77, 91, Standard Specification for Reagent Water,
IBR approved for Appendix A: Method 5, Section 7.1.3; Method 5E,
Section 7.2.1; Method 5F, Section 7.2.1; Method 6, Section 7.1.1;
Method 7, Section 7.1.1; Method 7C, Section 7.1.1; Method 7D, Section
7.1.1; Method 10A, Section 7.1.1; Method 11, Section 7.1.3; Method 12,
Section 7.1.3; Method 13A, Section 7.1.2; Method 26, Section 7.1.2;
Method 26A, Section 7.1.2; and Method 29, Section 7.2.2.
    (21) ASTM D1266-87, 91, 98, Standard Test Method for Sulfur in
Petroleum Products (Lamp Method), IBR approved for Sec. Sec.
60.106(j)(2) and 60.335(b)(10)(i).
    (22) ASTM D1266-98 (Reapproved 2003) [egr]1, Standard
Test Method for Sulfur in Petroleum Products (Lamp Method), IBR
approved for Sec.  60.4415(a)(1)(i).
    (23) ASTM D1475-60 (Reapproved 1980), 90, Standard Test Method for
Density of Paint, Varnish Lacquer, and Related Products, IBR approved
for Sec.  60.435(d)(1), Appendix A: Method 24, Section 6.1; and Method
24A, Sections 6.5 and 7.1.
    (24) ASTM D1552-83, 95, 01, Standard Test Method for Sulfur in
Petroleum Products (High-Temperature Method), IBR approved for
Sec. Sec.  60.106(j)(2), 60.335(b)(10)(i), and Appendix A: Method 19,
Section <IP_ADDRESS>.3.
    (25) ASTM D1552-03, Standard Test Method for Sulfur in Petroleum
Products (High-Temperature Method), IBR approved for Sec.
60.4415(a)(1)(i).
    (26) ASTM D1826-77, 94, Standard Test Method for Calorific Value of
Gases in Natural Gas Range by Continuous Recording Calorimeter, IBR
approved for Sec. Sec.  60.45(f)(5)(ii), 60.46(c)(2), 60.296(b)(3), and
Appendix A: Method 19, Section <IP_ADDRESS>.
    (27) ASTM D1835-87, 91, 97, 03a, Standard Specification for
Liquefied Petroleum (LP) Gases, IBR approved for Sec.  60.41Da of
subpart Da of this part.
    (28) ASTM D1835-82, 86, 87, 91, 97, Standard Specification for
Liquefied Petroleum (LP) Gases, IBR approved for Sec.  60.41b of
subpart Db of this part.
    (29) ASTM D1835-86, 87, 91, 97, Standard Specification for
Liquefied Petroleum (LP) Gases, IBR approved for Sec.  60.41c of
subpart Dc of this part.
    (30) ASTM D1945-64, 76, 91, 96, Standard Method for Analysis of
Natural Gas by Gas Chromatography, IBR approved for Sec.
60.45(f)(5)(i).
    (31) ASTM D1946-77, 90 (Reapproved 1994), Standard Method for
Analysis of Reformed Gas by Gas Chromatography, IBR approved for
Sec. Sec.  60.18(f)(3), 60.45(f)(5)(i), 60.564(f)(1), 60.614(e)(2)(ii),
60.614(e)(4), 60.664(e)(2)(ii), 60.664(e)(4), 60.704(d)(2)(ii), and
60.704(d)(4).
    (32) ASTM D2013-72, 86, Standard Method of Preparing Coal Samples
for Analysis, IBR approved for Appendix A: Method 19, Section
<IP_ADDRESS>.3.
    (33) ASTM D2015-77 (Reapproved 1978), 96, Standard Test Method for
Gross Calorific Value of Solid Fuel by the Adiabatic Bomb Calorimeter,
IBR approved for Sec.  60.45(f)(5)(ii), 60.46(c)(2), and Appendix A:
Method 19, Section <IP_ADDRESS>.3.
    (34) ASTM D2016-74, 83, Standard Test Methods for Moisture Content
of Wood, IBR approved for Appendix A: Method 28, Section 16.1.1.
    (35) ASTM D2234-76, 96, 97b, 98, Standard Methods for Collection of
a Gross Sample of Coal, IBR approved for Appendix A: Method 19, Section
<IP_ADDRESS>.1.
    (36) ASTM D2369-81, 87, 90, 92, 93, 95, Standard Test Method for
Volatile Content of Coatings, IBR approved for Appendix A: Method 24,
Section 6.2.
    (37) ASTM D2382-76, 88, Heat of Combustion of Hydrocarbon Fuels by
Bomb Calorimeter (High-Precision Method), IBR approved for Sec. Sec.
60.18(f)(3), 60.485(g)(6), 60.564(f)(3), 60.614(e)(4), 60.664(e)(4),
and 60.704(d)(4).
    (38) ASTM D2504-67, 77, 88 (Reapproved 1993), Noncondensable Gases
in C3 and Lighter Hydrocarbon Products by Gas Chromatography, IBR
approved for Sec.  60.485(g)(5).
    (39) ASTM D2584-68 (Reapproved 1985), 94, Standard Test Method for
Ignition Loss of Cured Reinforced Resins, IBR approved for Sec.
60.685(c)(3)(i).
    (40) ASTM D2597-94 (Reapproved 1999), Standard Test Method for
Analysis of Demethanized Hydrocarbon Liquid Mixtures Containing
Nitrogen and Carbon Dioxide by Gas Chromatography, IBR approved for
Sec.  60.335(b)(9)(i).
    (41) ASTM D2622-87, 94, 98, Standard Test Method for Sulfur in
Petroleum Products by Wavelength Dispersive X-Ray Fluorescence
Spectrometry,'' IBR approved for Sec. Sec.  60.106(j)(2) and
60.335(b)(10)(i).
    (42) ASTM D2622-05, Standard Test Method for Sulfur in Petroleum
Products by Wavelength Dispersive X-Ray Fluorescence Spectrometry,''
IBR approved for Sec.  60.4415(a)(1)(i).
    (43) ASTM D2879-83, 96, 97, Test Method for Vapor Pressure-
Temperature Relationship and Initial Decomposition Temperature of
Liquids by Isoteniscope, IBR approved for Sec. Sec.  60.111b(f)(3),
60.116b(e)(3)(ii), 60.116b(f)(2)(i), and 60.485(e)(1).
    (44) ASTM D2880-78, 96, Standard Specification for Gas Turbine Fuel
Oils, IBR approved for Sec. Sec.  60.111(b), 60.111a(b), and 60.335(d).
    (45) ASTM D2908-74, 91, Standard Practice for Measuring Volatile
Organic Matter in Water by Aqueous-Injection Gas Chromatography, IBR
approved for Sec.  60.564(j).
    (46) ASTM D2986-71, 78, 95a, Standard Method for Evaluation of Air,
Assay Media by the Monodisperse DOP (Dioctyl Phthalate) Smoke Test, IBR
approved for Appendix A: Method 5, Section 7.1.1; Method 12, Section
7.1.1; and Method 13A, Section <IP_ADDRESS>.
    (47) ASTM D3173-73, 87, Standard Test Method for Moisture in the
Analysis Sample of Coal and Coke, IBR approved for Appendix A: Method
19, Section <IP_ADDRESS>.3.
    (48) ASTM D3176-74, 89, Standard Method for Ultimate Analysis of
Coal and Coke, IBR approved for Sec.  60.45(f)(5)(i) and Appendix A:
Method 19, Section <IP_ADDRESS>.
    (49) ASTM D3177-75, 89, Standard Test Method for Total Sulfur in
the Analysis Sample of Coal and Coke, IBR approved for Appendix A:
Method 19, Section <IP_ADDRESS>.3.
    (50) ASTM D3178-73 (Reapproved 1979), 89, Standard Test Methods for
Carbon and Hydrogen in the Analysis Sample of Coal and Coke, IBR
approved for Sec.  60.45(f)(5)(i).
    (51) ASTM D3246-81, 92, 96, Standard Test Method for Sulfur in
Petroleum Gas by Oxidative Microcoulometry, IBR approved for Sec.
60.335(b)(10)(ii).
    (52) ASTM D3246-05, Standard Test Method for Sulfur in Petroleum
Gas by Oxidative Microcoulometry, IBR approved for Sec.
60.4415(a)(1)(ii).

    (53) ASTM D3270-73T, 80, 91, 95, Standard Test Methods for Analysis
for Fluoride Content of the Atmosphere and Plant Tissues (Semiautomated
Method), IBR approved for Appendix A: Method 13A, Section 16.1.
    (54) ASTM D3286-85, 96, Standard Test Method for Gross Calorific
Value of Coal and Coke by the Isoperibol Bomb Calorimeter, IBR approved
for Appendix A: Method 19, Section <IP_ADDRESS>.3.
    (55) ASTM D3370-76, 95a, Standard Practices for Sampling Water, IBR
approved for Sec.  60.564(j).
    (56) ASTM D3792-79, 91, Standard Test Method for Water Content of
Water-Reducible Paints by Direct Injection into a Gas Chromatograph,
IBR approved for Appendix A: Method 24, Section 6.3.
    (57) ASTM D4017-81, 90, 96a, Standard Test Method for Water in
Paints and Paint Materials by the Karl Fischer Titration Method, IBR
approved for Appendix A: Method 24, Section 6.4.
    (58) ASTM D4057-81, 95, Standard Practice for Manual Sampling of
Petroleum and Petroleum Products, IBR approved for Appendix A: Method
19, Section <IP_ADDRESS>.3.
    (59) ASTM D4057-95 (Reapproved 2000), Standard Practice for Manual
Sampling of Petroleum and Petroleum Products, IBR approved for Sec.
60.4415(a)(1).
    (60) ASTM D4084-82, 94, Standard Test Method for Analysis of
Hydrogen Sulfide in Gaseous Fuels (Lead Acetate Reaction Rate Method),
IBR approved for Sec.  60.334(h)(1).
    (61) ASTM D4084-05, Standard Test Method for Analysis of Hydrogen
Sulfide in Gaseous Fuels (Lead Acetate Reaction Rate Method), IBR
approved for Sec. Sec.  60.4360 and 60.4415(a)(1)(ii).
    (62) ASTM D4177-95, Standard Practice for Automatic Sampling of
Petroleum and Petroleum Products, IBR approved for Appendix A: Method
19, Section <IP_ADDRESS>.1.
    (63) ASTM D4177-95 (Reapproved 2000), Standard Practice for
Automatic Sampling of Petroleum and Petroleum Products, IBR approved
for Sec.  60.4415(a)(1).
    (64) ASTM D4239-85, 94, 97, Standard Test Methods for Sulfur in the
Analysis Sample of Coal and Coke Using High Temperature Tube Furnace
Combustion Methods, IBR approved for Appendix A: Method 19, Section
<IP_ADDRESS>.3.
    (65) ASTM D4294-02, Standard Test Method for Sulfur in Petroleum
and Petroleum Products by Energy-Dispersive X-Ray Fluorescence
Spectrometry, IBR approved for Sec.  60.335(b)(10)(i).
    (66) ASTM D4294-03, Standard Test Method for Sulfur in Petroleum
and Petroleum Products by Energy-Dispersive X-Ray Fluorescence
Spectrometry, IBR approved for Sec.  60.4415(a)(1)(i).
    (67) ASTM D4442-84, 92, Standard Test Methods for Direct Moisture
Content Measurement in Wood and Wood-base Materials, IBR approved for
Appendix A: Method 28, Section 16.1.1.
    (68) ASTM D4444-92, Standard Test Methods for Use and Calibration
of Hand-Held Moisture Meters, IBR approved for Appendix A: Method 28,
Section 16.1.1.
    (69) ASTM D4457-85 (Reapproved 1991), Test Method for Determination
of Dichloromethane and 1, 1, 1-Trichloroethane in Paints and Coatings
by Direct Injection into a Gas Chromatograph, IBR approved for Appendix
A: Method 24, Section 6.5.
    (70) ASTM D4468-85 (Reapproved 2000), Standard Test Method for
Total Sulfur in Gaseous Fuels by Hydrogenolysis and Rateometric
Colorimetry, IBR approved for Sec. Sec.  60.335(b)(10)(ii) and
60.4415(a)(1)(ii).
    (71) ASTM D4629-02, Standard Test Method for Trace Nitrogen in
Liquid Petroleum Hydrocarbons by Syringe/Inlet Oxidative Combustion and
Chemiluminescence Detection, IBR approved for Sec.  60.335(b)(9)(i).
    (72) ASTM D4809-95, Standard Test Method for Heat of Combustion of
Liquid Hydrocarbon Fuels by Bomb Calorimeter (Precision Method), IBR
approved for Sec. Sec.  60.18(f)(3), 60.485(g)(6), 60.564(f)(3),
60.614(d)(4), 60.664(e)(4), and 60.704(d)(4).
    (73) ASTM D4810-88 (Reapproved 1999), Standard Test Method for
Hydrogen Sulfide in Natural Gas Using Length of Stain Detector Tubes,
IBR approved for Sec. Sec.  60.4360 and 60.4415(a)(1)(ii).
    (74) ASTM D5287-97 (Reapproved 2002), Standard Practice for
Automatic Sampling of Gaseous Fuels, IBR approved for Sec.
60.4415(a)(1).
    (75) ASTM D5403-93, Standard Test Methods for Volatile Content of
Radiation Curable Materials, IBR approved for Appendix A: Method 24,
Section 6.6.
    (76) ASTM D5453-00, Standard Test Method for Determination of Total
Sulfur in Light Hydrocarbons, Motor Fuels and Oils by Ultraviolet
Fluorescence, IBR approved for Sec.  60.335(b)(10)(i).
    (77) ASTM D5453-05, Standard Test Method for Determination of Total
Sulfur in Light Hydrocarbons, Motor Fuels and Oils by Ultraviolet
Fluorescence, IBR approved for Sec.  60.4415(a)(1)(i).
    (78) ASTM D5504-01, Standard Test Method for Determination of
Sulfur Compounds in Natural Gas and Gaseous Fuels by Gas Chromatography
and Chemiluminescence, IBR approved for Sec. Sec.  60.334(h)(1) and
60.4360.
    (79) ASTM D5762-02, Standard Test Method for Nitrogen in Petroleum
and Petroleum Products by Boat-Inlet Chemiluminescence, IBR approved
for Sec.  60.335(b)(9)(i).
    (80) ASTM D5865-98, Standard Test Method for Gross Calorific Value
of Coal and Coke, IBR approved for Sec.  60.45(f)(5)(ii), 60.46(c)(2),
and Appendix A: Method 19, Section <IP_ADDRESS>.3.
    (81) ASTM D6216-98, Standard Practice for Opacity Monitor
Manufacturers to Certify Conformance with Design and Performance
Specifications, IBR approved for Appendix B, Performance Specification
1.
    (82) ASTM D6228-98, Standard Test Method for Determination of
Sulfur Compounds in Natural Gas and Gaseous Fuels by Gas Chromatography
and Flame Photometric Detection, IBR approved for Sec.  60.334(h)(1).
    (83) ASTM D6228-98 (Reapproved 2003), Standard Test Method for
Determination of Sulfur Compounds in Natural Gas and Gaseous Fuels by
Gas Chromatography and Flame Photometric Detection, IBR approved for
Sec. Sec.  60.4360 and 60.4415.
    (84) ASTM D6366-99, Standard Test Method for Total Trace Nitrogen
and Its Derivatives in Liquid Aromatic Hydrocarbons by Oxidative
Combustion and Electrochemical Detection, IBR approved for Sec.
60.335(b)(9)(i).
    (85) ASTM D6522-00, Standard Test Method for Determination of
Nitrogen Oxides, Carbon Monoxide, and Oxygen Concentrations in
Emissions from Natural Gas-Fired Reciprocating Engines, Combustion
Turbines, Boilers, and Process Heaters Using Portable Analyzers, IBR
approved for Sec.  60.335(a).
    (86) ASTM D6667-01, Standard Test Method for Determination of Total
Volatile Sulfur in Gaseous Hydrocarbons and Liquefied Petroleum Gases
by Ultraviolet Fluorescence, IBR approved for Sec.  60.335(b)(10)(ii).
    (87) ASTM D6667-04, Standard Test Method for Determination of Total
Volatile Sulfur in Gaseous Hydrocarbons and Liquefied Petroleum Gases
by Ultraviolet Fluorescence, IBR approved for Sec.  60.4415(a)(1)(ii).
    (88) ASTM D6784-02, Standard Test Method for Elemental, Oxidized,
Particle-Bound and Total Mercury in Flue Gas Generated from Coal-Fired
Stationary Sources (Ontario Hydro Method), IBR approved for Appendix B

to part 60, Performance Specification 12A, Section 8.6.2.
    (89) ASTM E168-67, 77, 92, General Techniques of Infrared
Quantitative Analysis, IBR approved for Sec. Sec.  60.593(b)(2) and
60.632(f).
    (90) ASTM E169-63, 77, 93, General Techniques of Ultraviolet
Quantitative Analysis, IBR approved for Sec. Sec.  60.593(b)(2) and
60.632(f).
    (91) ASTM E260-73, 91, 96, General Gas Chromatography Procedures,
IBR approved for Sec. Sec.  60.593(b)(2) and 60.632(f).
* * * * *
    (h) * * *
    (4) ANSI/ASME PTC 19.10-1981, Flue and Exhaust Gas Analyses [Part
10, Instruments and Apparatus], IBR approved for Tables 1 and 3 of
subpart EEEE, Tables 2 and 4 of subpart FFFF, and Sec. Sec.
60.4415(a)(2) and 60.4415(a)(3) of subpart KKKK of this part.
* * * * *
    (m) * * *
    (1) Gas Processors Association Method 2377-86, Test for Hydrogen
Sulfide and Carbon Dioxide in Natural Gas Using Length of Stain Tubes,
IBR approved for Sec. Sec.  60.334(h)(1), 60.4360, and
60.4415(a)(1)(ii).
    (2) [Reserved]

0
3. Part 60 is amended by reserving subpart IIII and subpart JJJJ and by
adding subpart KKKK to read as follows:

Subpart KKKK--Standards of Performance for Stationary Combustion
Turbines

Introduction

Sec.
60.4300 What is the purpose of this subpart?

Applicability

60.4305 Does this subpart apply to my stationary combustion turbine?
60.4310 What types of operations are exempt from these standards of
performance?

Emission Limits

60.4315 What pollutants are regulated by this subpart?
60.4320 What emission limits must I meet for nitrogen oxides
(NOX)?
60.4325 What emission limits must I meet for NOX if my
turbine burns both natural gas and distillate oil (or some other
combination of fuels)?
60.4330 What emission limits must I meet for sulfur dioxide
(SO2)?

General Compliance Requirements

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

Monitoring

60.4335 How do I demonstrate compliance for NOX if I use
water or steam injection?
60.4340 How do I demonstrate continuous compliance for
NOX if I do not use water or steam injection?
60.4345 What are the requirements for the continuous emission
monitoring system equipment, if I choose to use this option?
60.4350 How do I use data from the continuous emission monitoring
equipment to identify excess emissions?
60.4355 How do I establish and document a proper parameter
monitoring plan?
60.4360 How do I determine the total sulfur content of the turbine's
combustion fuel?
60.4365 How can I be exempted from monitoring the total sulfur
content of the fuel?
60.4370 How often must I determine the sulfur content of the fuel?

Reporting

60.4375 What reports must I submit?
60.4380 How are excess emissions and monitor downtime defined for
NOX?
60.4385 How are excess emissions and monitoring downtime defined for
SO2?
60.4390 What are my reporting requirements if I operate an emergency
combustion turbine or a research and development turbine?
60.4395 When must I submit my reports?

Performance Tests

60.4400 How do I conduct the initial and subsequent performance
tests, regarding NOX?
60.4405 How do I perform the initial performance test if I have
chosen to install a NOX-diluent CEMS?
60.4410 How do I establish a valid parameter range if I have chosen
to continuously monitor parameters?
60.4415 How do I conduct the initial and subsequent performance
tests for sulfur?

Definitions

60.4420 What definitions apply to this subpart?
Table 1 to Subpart KKKK of Part 60-Nitrogen Oxide Emission Limits for
New 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) If you are the owner or operator of a stationary combustion
turbine with a heat input at peak load equal to or greater than 10.7
gigajoules (10 MMBtu) per hour, based on the higher heating value of
the fuel, which commenced construction, modification, or reconstruction
after February 18, 2005, your turbine is subject to this subpart. Only
heat input to the combustion turbine should be included when
determining whether or not this subpart is applicable to your turbine.
Any additional heat input to associated heat recovery steam generators
(HRSG) or duct burners should not be included when determining your
peak heat input. However, this subpart does apply to emissions from any
associated HRSG and duct burners.
    (b) Stationary combustion turbines regulated under this subpart are
exempt from the requirements of subpart GG of this part. Heat recovery
steam generators and duct burners regulated under this subpart are
exempted from the requirements of subparts Da, Db, and Dc of this part.

Sec.  60.4310  What types of operations are exempt from these standards
of performance?

    (a) Emergency combustion turbines, as defined in Sec.  60.4420(i),
are exempt from the nitrogen oxides (NOX) emission limits in
Sec.  60.4320.
    (b) Stationary combustion turbines engaged by manufacturers in
research and development of equipment for both combustion turbine
emission control techniques and combustion turbine efficiency
improvements are exempt from the NOX emission limits in
Sec.  60.4320 on a case-by-case basis as determined by the
Administrator.
    (c) Stationary combustion turbines at integrated gasification
combined cycle electric utility steam generating units that are subject
to subpart Da of this part are exempt from this subpart.
    (d) Combustion turbine test cells/stands are exempt from this
subpart.

Emission Limits

Sec.  60.4315  What pollutants are regulated by this subpart?

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

Sec.  60.4320  What emission limits must I meet for nitrogen oxides
(NOX)?

    (a) You must meet the emission limits for NOX specified
in Table 1 to this subpart.
    (b) If you have two or more turbines that are connected to a single
generator, each turbine must meet the emission limits for
NOX.

Sec.  60.4325  What emission limits must I meet for NOX if my turbine
burns both natural gas and distillate oil (or some other combination of
fuels)?

    You must meet the emission limits specified in Table 1 to this
subpart. If your total heat input is greater than or equal to 50
percent natural gas, you must meet the corresponding limit for a
natural gas-fired turbine when you are burning that fuel. Similarly,
when your total heat input is greater than 50 percent distillate oil
and fuels other than natural gas, you must meet the corresponding limit
for distillate oil and fuels other than natural gas for the duration of
the time that you burn that particular fuel.

Sec.  60.4330  What emission limits must I meet for sulfur dioxide
(SO2)?

    (a) If your turbine is located in a continental area, you must
comply with either paragraph (a)(1) or (a)(2) of this section. If your
turbine is located in Alaska, you do not have to comply with the
requirements in paragraph (a) of this section until January 1, 2008.
    (1) You must not cause to be discharged into the atmosphere from
the subject stationary combustion turbine any gases which contain
SO2 in excess of 110 nanograms per Joule (ng/J) (0.90 pounds
per megawatt-hour (lb/MWh)) gross output, or
    (2) You must not burn in the subject stationary combustion turbine
any fuel which contains total potential sulfur emissions in excess of
26 ng SO2/J (0.060 lb SO2/MMBtu) heat input. If
your turbine simultaneously fires multiple fuels, each fuel must meet
this requirement.
    (b) If your turbine is located in a noncontinental area or a
continental area that the Administrator determines does not have access
to natural gas and that the removal of sulfur compounds would cause
more environmental harm than benefit, you must comply with one or the
other of the following conditions:
    (1) You must not cause to be discharged into the atmosphere from
the subject stationary combustion turbine any gases which contain
SO2 in excess of 780 ng/J (6.2 lb/MWh) gross output, or
    (2) You must not burn in the subject stationary combustion turbine
any fuel which contains total sulfur with potential sulfur emissions in
excess of 180 ng SO2/J (0.42 lb SO2/MMBtu) heat
input. If your turbine simultaneously fires multiple fuels, each fuel
must meet this requirement.

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) When an affected unit with heat recovery utilizes a common
steam header with one or more combustion turbines, the owner or
operator shall either:
    (1) Determine compliance with the applicable NOX
emissions limits by measuring the emissions combined with the emissions
from the other unit(s) utilizing the common heat recovery unit; or
    (2) Develop, demonstrate, and provide information satisfactory to
the Administrator on methods for apportioning the combined gross energy
output from the heat recovery unit for each of the affected combustion
turbines. The Administrator may approve such demonstrated substitute
methods for apportioning the combined gross energy output measured at
the steam turbine whenever the demonstration ensures accurate
estimation of emissions related under this part.

Monitoring

Sec.  60.4335  How do I demonstrate compliance for NOX if I use water
or steam injection?

    (a) If you are using water or steam injection to control
NOX emissions, 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 being fired in the
turbine when burning a fuel that requires water or steam injection for
compliance.
    (b) Alternatively, you may use continuous emission monitoring, as
follows:
    (1) Install, certify, maintain, and operate a continuous emission
monitoring system (CEMS) consisting of a NOX monitor and a
diluent gas (oxygen (O2) or carbon dioxide (CO2))
monitor, to determine the hourly NOX emission rate in parts
per million (ppm) or pounds per million British thermal units (lb/
MMBtu); and
    (2) For units complying with the output-based standard, install,
calibrate, maintain, and operate a fuel flow meter (or flow meters) to
continuously measure the heat input to the affected unit; and
    (3) For units complying with the output-based standard, install,
calibrate, maintain, and operate a watt meter (or meters) to
continuously measure the gross electrical output of the unit in
megawatt-hours; and
    (4) For combined heat and power units complying with the output-
based standard, install, calibrate, maintain, and operate meters for
useful recovered energy flow rate, temperature, and pressure, to
continuously measure the total thermal energy output in British thermal
units per hour (Btu/h).

Sec.  60.4340  How do I demonstrate continuous compliance for NOX if I
do not use water or steam injection?

    (a) If you are not using water or steam injection to control
NOX emissions, you must perform annual performance tests in
accordance with Sec.  60.4400 to demonstrate continuous compliance. If
the NOX emission result from the performance test is less
than or equal to 75 percent of the NOX emission limit for
the turbine, you may reduce the frequency of subsequent performance
tests to once every 2 years (no more than 26 calendar months following
the previous performance test). If the results of any subsequent
performance test exceed 75 percent of the NOX emission limit
for the turbine, you must resume annual performance tests.
    (b) As an alternative, you may install, calibrate, maintain and
operate one of the following continuous monitoring systems:
    (1) Continuous emission monitoring as described in Sec. Sec.
60.4335(b) and 60.4345, or
    (2) Continuous parameter monitoring as follows:
    (i) For a diffusion flame turbine without add-on selective
catalytic reduction (SCR) controls, you must define parameters
indicative of the unit's NOX formation characteristics, and
you must monitor these parameters continuously.
    (ii) For any lean premix stationary combustion turbine, you must
continuously monitor the appropriate parameters to determine whether
the unit is operating in low-NOX mode.
    (iii) For any turbine that uses SCR to reduce NOX
emissions, you must continuously monitor appropriate parameters to
verify the proper operation of the emission controls.
    (iv) For affected units that are also regulated under part 75 of
this chapter, with state approval you can monitor the NOX
emission rate using the methodology in appendix E to part 75 of this
chapter, or the low mass

emissions methodology in Sec.  75.19, the requirements of this
paragraph (b) may be met by performing the parametric monitoring
described in section 2.3 of part 75 appendix E or in Sec.
75.19(c)(1)(iv)(H).

Sec.  60.4345  What are the requirements for the continuous emission
monitoring system equipment, if I choose to use this option?

    If the option to use a NOX CEMS is chosen:
    (a) Each NOX diluent CEMS must be installed and
certified according to Performance Specification 2 (PS 2) in appendix B
to this part, except the 7-day calibration drift is based on unit
operating days, not calendar days. With state approval, Procedure 1 in
appendix F to this part is not required. Alternatively, a
NOX diluent CEMS that is installed and certified according
to appendix A of part 75 of this chapter is acceptable for use under
this subpart. The relative accuracy test audit (RATA) of the CEMS shall
be performed on a lb/MMBtu basis.
    (b) As specified in Sec.  60.13(e)(2), during each full unit
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, to
validate the hour. For partial unit operating hours, at least one valid
data point must be obtained with each monitor for each quadrant of the
hour in which the unit operates. For unit operating hours in which
required quality assurance and maintenance activities are performed on
the CEMS, a minimum of two valid data points (one in each of two
quadrants) are required for each monitor to validate the NOX
emission rate for the hour.
    (c) Each fuel flowmeter shall be installed, calibrated, maintained,
and operated according to the manufacturer's instructions.
Alternatively, with state approval, fuel flowmeters that meet the
installation, certification, and quality assurance requirements of
appendix D to part 75 of this chapter are acceptable for use under this
subpart.
    (d) Each watt meter, steam flow meter, and each pressure or
temperature measurement device shall be installed, calibrated,
maintained, and operated according to manufacturer's instructions.
    (e) The owner or operator shall develop and keep on-site a quality
assurance (QA) plan for all of the continuous monitoring equipment
described in paragraphs (a), (c), and (d) of this section. For the CEMS
and fuel flow meters, the owner or operator may, with state approval,
satisfy the requirements of this paragraph by implementing the QA
program and plan described in section 1 of appendix B to part 75 of
this chapter.

Sec.  60.4350  How do I use data from the continuous emission
monitoring equipment to identify excess emissions?

    For purposes of identifying excess emissions:
    (a) All CEMS data must be reduced to hourly averages as specified
in Sec.  60.13(h).
    (b) For each unit operating hour in which a valid hourly average,
as described in Sec.  60.4345(b), is obtained for both NOX
and diluent monitors, the data acquisition and handling system must
calculate and record the hourly NOX emission rate in units
of ppm or lb/MMBtu, using the appropriate equation from method 19 in
appendix A 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.
    (c) Correction of measured NOX concentrations to 15
percent O2 is not allowed.
    (d) If you have installed and certified a NOX diluent
CEMS to meet the requirements of part 75 of this chapter, states can
approve that only quality assured data from the CEMS shall be used to