Standards of Performance for Stationary Combustion Turbines, 38482-38506 [06-5945]

Agencies

• ENVIRONMENTAL PROTECTION AGENCY

[Federal Register Volume 71, Number 129 (Thursday, July 6, 2006)]
[Rules and Regulations]
[Pages 38482-38506]
From the Federal Register Online via the Government Printing Office [www.gpo.gov]
[FR Doc No: 06-5945]



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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

Federal Register / Vol. 71, No. 129 / Thursday, July 6, 2006 / Rules 
and Regulations

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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 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 
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 (202) 566-1742.

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 (919) 541-4003; 
facsimile number (919) 541-5450; e-mail address 
fellner.christian@epa.gov.

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:

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            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 https://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

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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).

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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

[[Page 38485]]

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

[[Page 38486]]

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

[[Page 38487]]

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

[[Page 38488]]

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

[[Page 38489]]

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 (https://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

[[Page 38490]]

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 turb